ULTRA PETROLEUM CORP - FORM 10-Q

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EX-31.2 - SECTION 302 CFO CERTIFICATION - ULTRA PETROLEUM CORP	d388866dex312.htm
EX-32.1 - SECTION 906 CEO CERTIFICATION - ULTRA PETROLEUM CORP	d388866dex321.htm
EX-31.1 - SECTION 302 CEO CERTIFICATION - ULTRA PETROLEUM CORP	d388866dex311.htm
EXCEL - IDEA: XBRL DOCUMENT - ULTRA PETROLEUM CORP	Financial_Report.xls
EX-32.2 - SECTION 906 CFO CERTIFICATION - ULTRA PETROLEUM CORP	d388866dex322.htm

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 June 30, 2012

¨	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):

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 July 23, 2012 was 152,930,367.

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	27

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

PART I – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2012			2011			2012			2011
	(Unaudited)
	(Amounts in thousands, except per share data)
Revenues:

Natural gas sales	$	140,836		$	249,835		$	331,876		$	481,751
Oil sales		29,434			30,732			64,537			56,107

Total operating revenues		170,270			280,567			396,413			537,858

Expenses:
Lease operating expenses		12,239			11,115			29,241			23,472
Production taxes		13,367			24,846			31,587			48,119
Gathering fees		16,766			13,910			36,318			26,917
Transportation charges		21,366			16,273			42,422			32,431
Depletion, depreciation and amortization		114,767			79,219			227,469			152,978
Ceiling test and other impairments		1,869,136			—			1,869,136			—
General and administrative		7,559			6,002			12,567			13,113

Total operating expenses		2,055,200			151,365			2,248,740			297,030

Operating (loss) income		(1,884,930	)		129,202			(1,852,327	)		240,828

Other income (expense), net:
Interest expense		(18,748	)		(15,590	)		(37,046	)		(30,180	)
(Loss) gain on commodity derivatives		(33,287	)		47,606			86,996			63,241
Rig cancellation fees		(4,666	)		—			(9,512	)		—
Other income (expense), net		7			(4	)		14			16

Total other (expense) income, net		(56,694	)		32,012			40,452			33,077

(Loss) income before income tax (benefit) provision		(1,941,624	)		161,214			(1,811,875	)		273,905

Income tax (benefit) provision		(754,642	)		57,709			(709,152	)		101,679

Net (loss) income	$	(1,186,982	)	$	103,505		$	(1,102,723	)	$	172,226

Net (loss) income per common share—basic	$	(7.76	)	$	0.68		$	(7.22	)	$	1.13

Net (loss) income per common share—fully diluted	$	(7.76	)	$	0.67		$	(7.22	)	$	1.11

Weighted average common shares outstanding—basic		152,921			152,899			152,761			152,749

Weighted average common shares outstanding—fully diluted		152,921			154,377			152,761			154,498

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS


	June 30, 2012			December 31, 2011
	(Unaudited)
	(Amounts in thousands of U.S. dollars, except share data)
ASSETS

Current Assets:
Cash and cash equivalents	$	15,698		$	11,307
Restricted cash		121			121
Oil and gas revenue receivable		59,085			88,243
Joint interest billing and other receivables		38,643			82,370
Derivative assets		143,032			230,385
Prepaid drilling costs and other current assets		5,984			7,494

Total current assets		262,563			419,920
Oil and gas properties, net, using the full cost method of accounting:
Proved		2,617,805			3,651,622
Unproved properties not being amortized		46,128			537,526
Property, plant and equipment		248,567			246,586
Deferred tax assets		44,778			—
Deferred financing costs and other		12,981			14,051

Total assets	$	3,232,822		$	4,869,705


LIABILITIES AND SHAREHOLDERS’ EQUITY

Current liabilities:
Accounts payable and accrued liabilities	$	179,132		$	295,873
Production taxes payable		59,445			62,117
Deferred tax liabilities		44,778			73,380
Interest payable		30,439			30,306
Derivative liabilities		2,456			—
Capital cost accrual		246,818			209,303

Total current liabilities		563,068			670,979
Long-term debt		2,117,000			1,903,000
Deferred income tax liabilities		—			635,009
Other long-term obligations		64,180			67,008
Commitments and contingencies
Shareholders’ equity:
Common stock - no par value; authorized - unlimited; issued and outstanding - 152,930,367 and 152,476,564 at June 30, 2012 and December 31, 2011, respectively		465,947			463,221
Treasury stock		(2	)		(14,951	)
Retained earnings		22,629			1,145,439

Total shareholders’ equity		488,574			1,593,709

Total liabilities and shareholders’ equity	$	3,232,822		$	4,869,705

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
	2012			2011
	(Unaudited)
	(Amounts in thousands of U.S. dollars)
Cash provided by (used in):
Operating activities:
Net (loss) income for the period	$	(1,102,723	)	$	172,226
Adjustments to reconcile net (loss) income to cash provided by operating activities:
Depletion and depreciation		227,469			152,978
Ceiling test and other impairments		1,869,136			—
Deferred income tax (benefit) provision		(712,175	)		97,128
Unrealized loss on commodity derivatives		89,809			26,879
Reduction in (excess) tax benefits from stock based compensation		4,027			(6,552	)
Stock compensation		4,781			6,446
Other		1,079			521
Net changes in operating assets and liabilities:
Accounts receivable		72,885			(12,336	)
Prepaid expenses and other		2,004			(1,571	)
Other non-current assets		—			7
Accounts payable and accrued liabilities		(116,706	)		26,825
Production taxes payable		(2,672	)		8,376
Interest expense payable		133			2,928
Other long-term obligations		(9,359	)		327
Taxation payable/receivable, net		(39	)		3,198

Net cash provided by operating activities		327,649			477,380
Investing Activities:
Oil and gas property expenditures		(469,290	)		(695,810	)
Gathering system expenditures		(91,296	)		(21,417	)
Change in capital cost accrual		37,515			27,158
Inventory		(996	)		(123	)
Purchase of capital assets		(4,025	)		(489	)

Net cash used in investing activities		(528,092	)		(690,681	)
Financing activities:
Borrowings on long-term debt		560,000			504,000
Payments on long-term debt		(346,000	)		(350,000	)
Repurchased shares/net share settlements		(6,296	)		(20,629	)
(Reduction in) excess tax benefits from stock based compensation		(4,027	)		6,552
Proceeds from exercise of options		1,157			9,242

Net cash provided by financing activities		204,834			149,165
Increase (decrease) in cash during the period		4,391			(64,136	)
Cash and cash equivalents, beginning of period		11,307			70,834

Cash and cash equivalents, end of period	$	15,698		$	6,698

See accompanying notes to consolidated financial statements.

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. In addition, the Company recently acquired acreage in eastern Colorado’s Denver Julesberg 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 Company recognized impairments of $92.5 million ($54.4 million, net of tax) at June 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.

(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

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

(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 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

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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					Six Months Ended
	June 30, 2012			June 30, 2011		June 30, 2012			June 30, 2011
	(Share amounts in 000’s)
Net (loss) income	$	(1,186,982	)	$	103,505	$	(1,102,723	)	$	172,226

Weighted average common shares outstanding—basic		152,921			152,899		152,761			152,749
Effect of dilutive instruments		—			1,478		—			1,749

Weighted average common shares outstanding—fully diluted		152,921			154,377		152,761			154,498

Net (loss) income per common share—basic	$	(7.76	)	$	0.68	$	(7.22	)	$	1.13

Net (loss) income per common share—fully diluted	$	(7.76	)	$	0.67	$	(7.22	)	$	1.11

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		1,859			935		1,886			935

(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

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

2. OIL AND GAS PROPERTIES AND EQUIPMENT:


	June 30, 2012			December 31, 2011
Developed Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	6,938,305		$	5,974,604
Less: Accumulated depletion, depreciation and amortization(2)		(4,320,500	)		(2,322,982	)

		2,617,805			3,651,622

Unproven Properties:
Acquisition and exploration costs not being amortized(1)		46,128			537,526

Net capitalized costs—oil and gas properties	$	2,663,933		$	4,189,148

Property, Plant and Equipment:
Gathering Systems	$	321,845		$	226,747
Less: Accumulated depreciation(3)		(102,936	)		(7,736	)

		218,909			219,011

Other Property and Equipment		15,003			11,333
Less: Accumulated depreciation		(7,688	)		(5,908	)

		7,315			5,425

Land		22,343			22,150

Net capitalized costs—property, plant and equipment	$	248,567		$	246,586

⁽¹⁾ For the six months ended June 30, 2012 and 2011, total interest on outstanding debt was $51.1 million and $45.7 million, respectively, of which, $14.0 million and $15.5 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 $1.8 billion ($1.1 billion, net of tax) non-cash write-down of the carrying value of its proved oil and natural gas properties at June 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 quoted market prices of $3.15 per MMBtu for Henry Hub natural gas and $95.67 per barrel for West Texas Intermediate oil, adjusted for market differentials.

⁽³⁾ The Company recognized impairments of $92.5 million ($54.4 million, net of tax) at June 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).

3. LONG-TERM LIABILITIES:


	June 30, 2012		December 31, 2011
Bank indebtedness	$	557,000	$	343,000
Senior Notes		1,560,000		1,560,000
Other long-term obligations		64,180		67,008

	$	2,181,180	$	1,970,008

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 June 30, 2012, the Company had $557.0 million in outstanding borrowings and $443.0 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 June 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 June 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 June 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.

4. SHARE BASED COMPENSATION:

Valuation and Expense Information


	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Total cost of share-based payment plans	$	3,335	$	5,007	$	7,016	$	10,131
Amounts capitalized in fixed assets	$	1,010	$	1,683	$	2,235	$	3,685
Amounts charged against income, before income tax benefit	$	2,325	$	3,324	$	4,781	$	6,446
Amount of related income tax benefit recognized in income	$	957	$	1,193	$	1,968	$	2,314

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the six months ended June 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		(28	)	$	25.08 to	$	75.18
Exercised		(33	)	$	16.97 to	$	25.68

Balance, June 30, 2012		1,398		$	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 six months ended June 30, 2012, the Company recognized $3.3 million in pre-tax compensation expense related to the 2010, 2011 and 2012 LTIP awards of restricted stock units as compared to $5.0 million during the six months ended June 30, 2011 related to the 2009, 2010 and 2011 LTIP awards of restricted stock units. The amounts recognized during the six months ended June 30, 2012 assumes that maximum performance objectives are attained under the 2010 and 2011 LTIP awards and target levels are attained under the 2012 LTIP. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at June 30, 2012, for each of the three year performance periods is expected to be approximately $11.4 million, $11.7 million, and $8.1 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).

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

5. INCOME TAXES:

During the quarter ended June 30, 2012, the Company recorded an income tax benefit of $754.6 million, or 38.9% of loss before income tax benefit. This compares to an income tax provision of $57.7 million, or 35.8% of income before income tax provision for the quarter ended June 30, 2011.

During the six months ended June 30, 2012, the Company recorded an income tax benefit of $709.2 million, or 39.1% of loss before income tax benefit. This compares to an income tax provision of $101.7 million, or 37.1% of income before income tax provision for the six months ended June 30, 2011.

As a result of the tax effect of the ceiling test and other impairments recorded during the quarter ended June 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 $37.8 million at June 30, 2012. This valuation allowance may be reversed in future periods against future income.

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

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 has 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.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Commodity Derivative Contracts: At June 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 - June 30, 2012
									Asset
Swap		NYMEX		Apr-Dec 2012		500,000	$	4.23	$	116,485
Swap		NYMEX		Apr-Oct 2012		90,000	$	5.00	$	24,091

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 June 30, 2012 and 2011:


	For the Three Months Ended June 30,					For the Six Months Ended June 30,
Natural Gas Commodity Derivatives:	2012			2011		2012			2011
Realized gain on commodity derivatives(1)	$	114,268		$	45,080	$	176,805		$	90,120
Unrealized (loss) gain on commodity derivatives(1)		(147,555	)		2,526		(89,809	)		(26,879	)

Total (loss) gain on commodity derivatives	$	(33,287	)	$	47,606	$	86,996		$	63,241

(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).

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 June 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	$	—	$	143,032	$	—	$	143,032

Liabilities:
Current derivative liability	$	—	$	2,456	$	—	$	2,456

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 ($54.4 million, net of tax) at June 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.

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 sheet 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.


	June 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	$	110,778	$	100,000	$	111,475
7.31% Notes due 2016, issued 2009		62,000		74,228		62,000		74,817
4.98% Notes due 2017, issued 2010		116,000		129,112		116,000		128,570
5.92% Notes due 2018, issued 2008		200,000		232,015		200,000		231,091
7.77% Notes due 2019, issued 2009		173,000		220,667		173,000		219,552
5.50% Notes due 2020, issued 2010		207,000		233,216		207,000		229,423
4.51% Notes due 2020, issued 2010		315,000		326,103		315,000		318,925
5.60% Notes due 2022, issued 2010		87,000		95,875		87,000		94,165
4.66% Notes due 2022, issued 2010		35,000		35,169		35,000		34,631
5.85% Notes due 2025, issued 2010		90,000		100,406		90,000		99,022
4.91% Notes due 2025, issued 2010		175,000		176,853		175,000		173,835
Credit Facility		557,000		557,000		343,000		343,000

	$	2,117,000	$	2,291,422	$	1,903,000	$	2,058,506

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

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 June 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.

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. In addition, the Company has recently acquired exploratory acreage in eastern Colorado’s Denver Julesburg Basin. 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 revenues 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, we have reduced capital expenditures by reducing the number of drilling rigs operating in our Wyoming fields and are encouraging the parties operating projects on our behalf in Pennsylvania to reduce their activity this year as well. Reductions in our 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 June 30, 2012, the average price realization for the Company’s natural gas was $4.04 per Mcf, including realized gains and losses on commodity derivatives. The Company’s average price realization for natural gas was $2.23 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 $4.38 per Mcf, excluding such realized gains during the second 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.

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).

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 June 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	$	—	$	143,032	$	—	$	143,032

Liabilities:
Current derivative liability	$	—	$	2,456	$	—	$	2,456

(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 ($54.4 million, net of tax) at June 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

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 six months ended June 30, 2012 and 2011 was $4.8 million and $6.4 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 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 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.

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 quarter ended June 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 $37.8 million as of June 30, 2012. This valuation allowance may be reversed in future periods against future 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 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 June 30, 2012 vs. Quarter Ended June 30, 2011

During the quarter ended June 30, 2012, production increased 10% on a gas equivalent basis to 65.1 Bcfe from 59.1 Bcfe for the same quarter in 2011. This increase in production was attributable to the Company’s successful drilling activities during 2011 and in the first six months of 2012. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 22% to $4.04 per Mcf in the second quarter of 2012 as compared to $5.17 per Mcf for the same quarter of 2011. During the three months ended June 30, 2012, the Company’s average price for natural gas was $2.23 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $4.38 per Mcf for the same period in 2011. The decrease in average natural gas prices offset in part by the increase in production contributed to a 39% decrease in revenues to $170.3 million as compared to $280.6 million in 2011.

Lease operating expense (“LOE”) increased to $12.2 million during the second quarter of 2012 compared to $11.1 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 remained flat at $0.19 per Mcfe.

During the three months ended June 30, 2012, production taxes were $13.4 million compared to $24.8 million during the same period in 2011, or $0.21 per Mcfe compared to $0.42 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 quarter ended June 30, 2012 and 8.9% of revenues for the same period in 2011. 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 June 30, 2012 as compared to the same period in 2011, as well as increased production in Pennsylvania.

Gathering fees increased to $16.8 million for the three months ended June 30, 2012 compared to $13.9 million during the same period in 2011 largely due to increased production volumes. On a per unit basis, gathering fees increased to $0.26 per Mcfe for the three months ended June 30, 2012 as compared to $0.24 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 $21.4 million for the quarter ended June 30, 2012 as compared to $16.3 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 June 30, 2012 as compared to $0.28 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 $114.8 million during the three months ended June 30, 2012 from $79.2 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 $1.76 per Mcfe for the quarter ended June 30, 2012 from $1.34 per Mcfe for the quarter ended June 30, 2011 primarily as a result of increased costs in Pennsylvania.

The Company recorded a $1.8 billion ($1.1 billion, net of tax) non-cash write-down of the carrying value of its proved oil and natural gas properties at June 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 quoted market prices of $3.15 per MMBtu for Henry Hub natural gas and $95.67 per barrel for West Texas Intermediate oil, adjusted for market differentials. The write-down reduced earnings in the second 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 June 30, 2011. See Note 1(d). In addition, the Company recognized impairments of $92.5 million ($54.4 million, net of tax) at June 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 increased to $7.6 million for the quarter ended June 30, 2012 compared to $6.0 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 $0.12 per Mcfe for the quarter ended June 30, 2012 compared to $0.10 per Mcfe for the quarter ended June 30, 2011.

Interest expense increased to $18.7 million during the quarter ended June 30, 2012 compared to $15.6 million during the same period in 2011 as a result of increased borrowings during the period ended June 30, 2012. At June 30, 2012, the Company had $2.1 billion in borrowings outstanding. In addition, the Company capitalized $6.9 million and $7.5 million in interest expense for the quarters ended June 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 June 30, 2012, the Company recognized $4.7 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 quarter ended June 30, 2012, the Company recognized $114.3 million of realized gain on commodity derivatives as compared to $45.1 million of realized gain on commodity derivatives during the quarter ended June 30, 2011. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under these derivative contracts.

During the quarter ended June 30, 2012, the Company recorded $147.6 million in unrealized loss on commodity derivatives as compared to $2.5 million in unrealized gain on commodity derivatives during the quarter ended June 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 $1.9 billion for the quarter ended June 30, 2012 compared with income before income taxes of $161.2 million for the same period in 2011. The decrease in earnings is primarily related to the non-cash ceiling test and other impairments together with decreased average natural gas prices offset in part by the increase in production during the three months ended June 30, 2012 as compared to the same period in 2011.

The income tax benefit recognized for the quarter ended June 30, 2012 was $754.6 million compared with an income tax provision of $57.7 million for the three months ended June 30, 2011 due to a net loss during the quarter ended June 30, 2012 primarily attributable to the non-cash ceiling test and other impairments. The Company’s effective tax rate for the quarter ended June 30, 2012 increased to 38.9% as compared to 35.8% for the quarter ended June 30, 2011. As a result of the tax effect of the ceiling test and other impairments recorded during the quarter ended June 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 $37.8 million as of June 30, 2012. This valuation allowance may be reversed in future periods against future income.

For the three months ended June 30, 2012, the Company recognized net loss of $1.2 billion or ($7.76) per diluted share as compared with net income of $103.5 million or $0.67 per diluted share for the same period in 2011. The decrease is primarily related to the non-cash ceiling test and other impairments together with decreased average natural gas prices offset in part by the increase in production during the three months ended June 30, 2012 as compared to the same period in 2011.

Six Months Ended June 30, 2012 vs. Six Months Ended June 30, 2011

During the six months ended June 30, 2012, production increased 17% on a gas equivalent basis to 133.9 Bcfe from 114.9 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 six months of 2012. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 24% to $3.92 per Mcf in the six months ended June 30, 2012 as compared to $5.15 per Mcf for the same period in 2011. During the six months ended June 30, 2012, the Company’s average price for natural gas was $2.56 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $4.34 per Mcf for the same period in 2011. The decrease in average natural gas prices, offset in part by the increase in production, contributed to a 26% decrease in revenues to $396.4 million as compared to $537.9 million in 2011.

LOE increased to $29.2 million during the six months ended June 30, 2012 compared to $23.5 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 $0.22 per Mcfe at June 30, 2012 compared to $0.20 per Mcfe at June 30, 2011 as a result of higher compression and water disposal costs for Pennsylvania wells and workover expenses in Wyoming.

During the six months ended June 30, 2012, production taxes were $31.6 million compared to $48.1 million during the same period in 2011, or $0.24 per Mcfe compared to $0.42 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 8.0% of revenues for the six months ended June 30, 2012 and 8.9% of revenues for the same period in 2011. 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 six months ended June 30, 2012 as compared to the same period in 2011 as well as increased production in Pennsylvania.

Gathering fees increased to $36.3 million for the six months ended June 30, 2012 compared to $26.9 million during the same period in 2011 largely due to increased production volumes. On a per unit basis, gathering fees increased to $0.27 per Mcfe for the six months ended June 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 $42.4 million for the six months ended June 30, 2012 as compared to $32.4 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 six months ended June 30, 2012 as compared to $0.28 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 $227.5 million during the six months ended June 30, 2012 from $153.0 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 $1.70 per Mcfe for the six months ended June 30, 2012 from $1.33 per Mcfe for the six months ended June 30, 2011 primarily as a result of increased costs in Pennsylvania.

The Company recorded a $1.8 billion ($1.1 billion, net of tax) non-cash write-down of the carrying value of its proved oil and natural gas properties at June 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 quoted market prices of $3.15 per MMBtu for Henry Hub natural gas and $95.67 per barrel for West Texas Intermediate oil, adjusted for market differentials. The write-down reduced earnings in the second 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 six months ended June 30, 2011. See Note 1(d). In addition, the Company recognized impairments of $92.5 million ($54.4 million, net of tax) at June 30, 2012

General and administrative expenses decreased to $12.6 million for the six months ended June 30, 2012 compared to $13.1 million for the same period in 2011. The decrease in general and administrative expenses is primarily attributable to lower incentive compensation costs offset in part by increased headcount and related compensation. On a per unit basis, general and administrative expenses were $0.09 per Mcfe for the six months ended June 30, 2012 compared to $0.11 per Mcfe for the period ended June 30, 2011.

Interest expense increased to $37.0 million during the six months ended June 30, 2012 compared to $30.2 million during the same period in 2011 as a result of increased borrowings during the period ended June 30, 2012. At June 30, 2012, the Company had $2.1 billion in borrowings outstanding. In addition, the Company capitalized $14.0 million and $15.5 million in interest expense for the six months ended June 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 six months ended June 30, 2012, the Company recognized $9.5 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 six months ended June 30, 2012, the Company recognized $176.8 million of realized gain on commodity derivatives as compared to $90.1 million of realized gain on commodity derivatives during the six months ended June 30, 2011. The realized gain on commodity derivatives relates to actual amounts received or paid under these derivative contracts.

During the six months ended June 30, 2012, the Company recorded $89.8 million in unrealized loss on commodity derivatives as compared to $26.9 million in unrealized loss on commodity derivatives during the six months ended June 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 $1.8 billion for the six months ended June 30, 2012 compared with income before income taxes of $273.9 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 six months ended June 30, 2012.

The income tax benefit recognized for the six months ended June 30, 2012 was $709.2 million compared with an income tax provision of $101.7 million for the same period in 2011 due to a net loss for the period ended June 30, 2012 primarily as a result of the non-cash ceiling test and other impairments and decreased natural gas prices partially offset by increased production during the six months ended June 30, 2012. The Company’s effective tax rate for the period ended June 30, 2012 increased to 39.1% as compared to 37.1% for the same period in 2011. As a result of the tax effect of the ceiling test and other impairments recorded during the quarter ended June 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 $37.8 million as of June 30, 2012. This valuation allowance may be reversed in future periods against future income.

For the six months ended June 30, 2012, the Company recognized net loss of $1.1 billion or ($7.22) per diluted share as compared with net income of $172.2 million or $1.11 per diluted share for the same period in 2011. The decrease is primarily related to the non-cash ceiling test and other impairments and decreased natural gas prices partially offset by increased production during the six months ended June 30, 2012.

LIQUIDITY AND CAPITAL RESOURCES

During the six month period ended June 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 135 gross (54.1 net) wells that were drilled to total depth and cased in Wyoming and Pennsylvania. For the six month period ended June 30, 2012, total capital expenditures were $560.6 million ($469.3 million related to oil and gas exploration and development expenditures and $91.3 million related to gathering system expenditures).

At June 30, 2012, the Company reported a cash position of $15.7 million compared to $6.7 million at June 30, 2011. Working capital deficit at June 30, 2012 was $300.5 million compared to working capital deficit of $352.9 million at June 30, 2011. At June 30, 2012, the Company had $557.0 million in outstanding borrowings and $443.0 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 $64.2 million at June 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 June 30, 2012, the Company had $557.0 million in outstanding borrowings and $443.0 million of available borrowing capacity under the Credit Facility.

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 June 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).

Operating Activities. During the six months ended June 30, 2012, net cash provided by operating activities was $327.6 million, a 31% decrease from $477.4 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 six months ended June 30, 2012 as compared to the same period in 2011.

Investing Activities. During the six months ended June 30, 2012, net cash used in investing activities was $528.1 million as compared to $690.7 million 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 six months ended June 30, 2012, net cash provided by financing activities was $204.8 million as compared to $149.2 million for the same period in 2011. The increase in net cash provided by financing activities is largely due to increased borrowings in 2012 as compared to 2011.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of June 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

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.

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.


Type	Commodity Reference Price		Remaining Contract Period		Volume - MMBTU/Day		Average Price/MMBTU		Fair Value - June 30, 2012
									Asset (Amounts in 000’s)
Swap		NYMEX		Apr-Dec 2012		500,000	$	4.23	$	116,485
Swap		NYMEX		Apr-Oct 2012		90,000	$	5.00	$	24,091


	For the Three Months Ended June 30,					For the Six Months Ended June 30,
Natural Gas Commodity Derivatives:	2012			2011		2012			2011
	(Amounts in 000’s)
Realized gain on commodity derivatives(1)	$	114,268		$	45,080	$	176,805		$	90,120
Unrealized (loss) gain on commodity derivatives(1)		(147,555	)		2,526		(89,809	)		(26,879	)

Total (loss) gain on commodity derivatives	$	(33,287	)	$	47,606	$	86,996		$	63,241

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

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 June 30, 2012. There were no changes in the Company’s internal control over financial reporting during the six months ended June 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

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
April 2012		—		—		—	$	386.0 million
May 2012		—		—		—	$	386.0 million
June 2012		15	$	18.05		15	$	385.7 million

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

On July 30, 2012, Michael J. Keeffe was appointed as a director of the Company and will serve on the Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee. Mr. Keeffe was a Senior Audit Partner with Deloitte & Touche LLP directing financial statement audits of publicly traded companies, principally in the oil field services and engineering and construction industries, most with significant international operations. He also served as a senior risk management and quality assurance partner in the firm’s consultation network. He is a Certified Public Accountant and holds a Bachelor of Arts and a Masters of Business Administration both from Tulane University.

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.

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: August 2, 2012



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

Date: August 2, 2012

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.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company