ULTRA PETROLEUM CORP - FORM 10-Q

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file	filename
EXCEL - IDEA: XBRL DOCUMENT - ULTRA PETROLEUM CORP	Financial_Report.xls
EX-31.2 - EX-31.2 - ULTRA PETROLEUM CORP	d716334dex312.htm
EX-32.2 - EX-32.2 - ULTRA PETROLEUM CORP	d716334dex322.htm
EX-31.1 - EX-31.1 - ULTRA PETROLEUM CORP	d716334dex311.htm
EX-32.1 - EX-32.1 - ULTRA PETROLEUM CORP	d716334dex321.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended March 31, 2014

¨	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 x 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 x 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 x

The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of April 22, 2014 was 153,140,941.

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 INCOME


	For the Three Months Ended March 31,
	2014			2013
	(Unaudited)
	(Amounts in thousands,
	except per share data)
Revenues:
Natural gas sales	$	271,539		$	202,200
Oil sales		54,760			23,426

Total operating revenues		326,299			225,626

Expenses:
Lease operating expenses		21,013			18,817
Liquids gathering system operating lease expense		5,076			5,000
Production taxes		25,931			16,555
Gathering fees		12,708			11,884
Transportation charges		20,575			20,309
Depletion, depreciation and amortization		63,181			61,468
General and administrative		6,345			5,961

Total operating expenses		154,829			139,994
Operating income		171,470			85,632

Other income (expense), net:
Interest expense		(27,068	)		(25,764	)
(Loss) on commodity derivatives		(45,273	)		(44,715	)
Deferred gain on sale of liquids gathering system		2,638			2,640
Other (expense) income, net		(48	)		8

Total other (expense) income, net		(69,751	)		(67,831	)
Income before income tax provision		101,719			17,801
Income tax provision		4			1,368

Net income	$	101,715		$	16,433

Net income per common share — basic	$	0.66		$	0.11

Net income per common share — fully diluted	$	0.66		$	0.11

Weighted average common shares outstanding — basic		153,042			152,947

Weighted average common shares outstanding — fully diluted		155,049			154,470

ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS


	March 31, 2014			December 31, 2013
	(Unaudited)
	(Amounts in thousands of U.S. dollars, except share data)
ASSETS
Current Assets:
Cash and cash equivalents	$	7,980		$	10,664
Restricted cash		117			119
Oil and gas revenue receivable		118,619			84,095
Joint interest billing and other receivables		15,354			17,725
Derivative assets		290			1,415
Other current assets		15,669			14,613

Total current assets		158,029			128,631
Oil and gas properties, net, using the full cost method of accounting:
Proven		2,078,355			2,008,538
Unproven properties not being amortized		410,264			413,073
Property, plant and equipment, net		217,862			216,909
Deferred tax assets		6			6
Deferred financing costs and other		17,326			18,162

Total assets	$	2,881,842		$	2,785,319

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	51,759		$	54,806
Accrued liabilities		89,395			79,811
Current portion of long-term debt		100,000			—
Production taxes payable		43,863			40,538
Interest payable		16,366			31,865
Derivative liabilities		62,486			27,291
Capital cost accrual		168,970			173,165

Total current liabilities		532,839			407,476
Long-term debt		2,325,000			2,470,000
Deferred gain on sale of liquids gathering system		144,762			147,401
Other long-term obligations		106,939			91,932
Commitments and contingencies
Shareholders’ equity:
Common stock — no par value; authorized — unlimited; issued and outstanding — 153,121,591 and 152,990,123 at March 31, 2014 and December 31, 2013, respectively		490,748			487,273
Treasury stock		(1,451	)		(1,961	)
Retained loss		(716,995	)		(816,802	)

Total shareholders’ deficit		(227,698	)		(331,490	)

Total liabilities and shareholders’ equity	$	2,881,842		$	2,785,319

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF CASH FLOW


	Three Months Ended March 31,
	2014			2013
	(Unaudited)
	(Amounts in thousands of U.S. dollars)
Cash provided by (used in):
Operating activities:
Net income for the period	$	101,715		$	16,433
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		63,181			61,468
Unrealized loss on commodity derivatives		36,319			44,715
Deferred gain on sale of liquids gathering system		(2,638	)		(2,640	)
Stock compensation		2,505			3,008
Other		1,043			539
Net changes in operating assets and liabilities:
Restricted cash		2			2
Accounts receivable		(32,153	)		8,357
Other current assets		(628	)		298
Accounts payable		(3,047	)		(8,247	)
Accrued liabilities		11,141			(34,907	)
Production taxes payable		3,325			68
Interest payable		(15,499	)		(21,190	)
Other long-term obligations		11,553			9,238
Current taxes payable/receivable		(1,244	)		(9,282	)

Net cash provided by operating activities		175,575			67,860
Investing Activities:
Oil and gas property expenditures		(123,595	)		(107,395	)
Gathering system expenditures		(2,319	)		(1,006	)
Change in capital cost accrual		(4,195	)		(49,420	)
Proceeds from sale of oil and gas properties		—			(27	)
Inventory		(911	)		529
Purchase of capital assets		(676	)		(10	)

Net cash used in investing activities		(131,696	)		(157,329	)
Financing activities:
Borrowings on long-term debt		195,000			314,000
Payments on long-term debt		(240,000	)		(218,000	)
Deferred financing costs		(164	)		—
Repurchased shares/net share settlements		(1,738	)		(5,085	)
Proceeds from exercise of options		339			—

Net cash (used in) provided by financing activities		(46,563	)		90,915
(Decrease) increase in cash during the period		(2,684	)		1,446
Cash and cash equivalents, beginning of period		10,664			12,921

Cash and cash equivalents, end of period	$	7,980		$	14,367

SUPPLEMENTAL INFORMATION:
Non-cash investing activities — oil and gas properties	$	—			12,650

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 owns and operates oil-producing properties and undeveloped acreage in the Uinta Basin in east Utah.

1. SIGNIFICANT ACCOUNTING POLICIES:

The accompanying financial statements, other than the balance sheet data as of December 31, 2013, 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, 2013 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 their respective 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, which are downstream of the Company’s well pads, 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.

(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,

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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 did not incur a ceiling test write-down for the three months ended March 31, 2014 or 2013.

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

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

(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
	March 31, 2014		March 31, 2013
	(Share amounts in 000’s)
Net income	$	101,715	$	16,433

Weighted average common shares outstanding — basic		153,042		152,947
Effect of dilutive instruments		2,007		1,523

Weighted average common shares outstanding — fully diluted		155,049		154,470

Net income per common share — basic	$	0.66	$	0.11

Net income per common share — fully diluted	$	0.66	$	0.11

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		1,701		1,331

(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 revisions of estimated inflation rates, changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations. As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.

(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

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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, if any, 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.

2. OIL AND GAS PROPERTIES AND EQUIPMENT:


	March 31, 2014			December 31, 2013
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs	$	7,946,938		$	7,817,374
Less: Accumulated depletion, depreciation and amortization(1)		(5,868,583	)		(5,808,836	)

Net capitalized costs — oil and gas properties		2,078,355			2,008,538

Unproven Properties:
Acquisition and exploration costs not being amortized(1)		410,264			413,073

	$	2,488,619		$	2,421,611

Property, Plant and Equipment:
Gathering Systems(1)	$	295,481		$	294,356
Less: Accumulated depreciation		(105,696	)		(105,246	)

		189,785			189,110

Other Property and Equipment		15,776			15,198
Less: Accumulated depreciation		(10,058	)		(9,758	)

		5,718			5,440

Land		22,359			22,359

Net capitalized costs — property, plant and equipment	$	217,862		$	216,909

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

(1)

For the three months ended March 31, 2014 and 2013, total interest on outstanding debt was $32.7 million and $26.0 million, respectively, of which, $5.6 million and $0.2 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and on work in process relating to gathering systems.

3. DEBT AND OTHER LONG-TERM OBLIGATIONS:


	March 31, 2014		December 31, 2013
Short-term debt:
Senior Notes due March 2015	$	100,000	$	—
Long-term debt and other obligations:
Bank indebtedness		415,000		460,000
Senior Notes		1,910,000		2,010,000
Other long-term obligations		106,939		91,932

	$	2,531,939	$	2,561,932

Ultra Resources, Inc. Bank Indebtedness: The Company’s subsidiary, Ultra Resources, Inc. (“Ultra Resources”, “Borrower”), is a party to a senior revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the Borrower and with the consent of lenders who are willing to increase their loan commitments, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016. With the majority (over 50%) lender consent, the term of the consenting lenders’ commitments may be extended for up to two successive one-year periods at the Borrower’s request. At March 31, 2014, the Company had $415.0 million in outstanding borrowings and $585.0 million of unused debt capacity under the Credit Agreement.

Loans under the Credit Agreement are unsecured and bear interest, at the Borrower’s option, based on (A) a rate per annum equal to the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 125 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 (225 basis points per annum as of March 31, 2014). The Company also pays commitment fees on the unused commitment under the facility based on a grid of its consolidated leverage ratio.

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 March 31, 2014, the Company was in compliance with all of its debt covenants under the Credit Agreement.

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

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Ultra Petroleum Corp. Senior Notes: On December 12, 2013, the Company issued $450.0 million of 5.75% Senior Notes due 2018 (“Notes”). The Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The Notes are not guaranteed by the Company’s subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. On and after December 15, 2015, the Company may redeem all or, from time to time, a part of the Notes at the following prices expressed as a percentage of principal amount of the Notes: (2015 — 102.875%; 2016 — 101.438%; and 2017 and thereafter — 100.000%). The Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the Notes contain events of default customary for a senior note financing. At March 31, 2014, the Company was in compliance with all of its debt covenants under the 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 March 31,
	2014		2013
Total cost of share-based payment plans	$	3,650	$	4,502
Amounts capitalized in oil and gas properties and equipment	$	1,145	$	1,494
Amounts charged against income, before income tax benefit	$	2,505	$	3,008
Amount of related income tax benefit recognized in income before valuation allowance	$	1,047	$	1,238

Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the three months ended March 31, 2014 and the year ended December 31, 2013:


	Number of Options (000’s)			Weighted Average Exercise Price (US$)
Balance, December 31, 2012		1,357		$	16.97	to	$	98.87

Forfeited		(110	)	$	25.68	to	$	75.18
Exercised		(1	)	$	16.97	to	$	16.97

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

Forfeited		(2	)	$	51.60	to	$	75.18
Exercised		(20	)	$	16.97	to	$	16.97

Balance, March 31, 2014		1,224		$	16.97	to	$	98.87

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

Performance Share Plans:

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

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

For the three months ended March 31, 2014, the Company recognized $2.3 million in pre-tax compensation expense related to the 2012, 2013 and 2014 LTIP awards of restricted stock units as compared to $2.3 million during the three months ended March 31, 2013 related to the 2011, 2012 and 2013 LTIP awards of restricted stock units. The amounts recognized during the three months ended March 31, 2014 assume that maximum performance objectives are attained under each of the LTIP plans. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at March 31, 2014, for each of the three year performance periods is expected to be approximately $12.8 million, $13.3 million, and $14.0 million related to the 2012, 2013 and 2014 LTIP awards of restricted stock units, respectively. The 2011 LTIP award of restricted stock units was paid in shares of the Company’s stock to employees during the first quarter of 2014 and totaled $8.4 million (106,437 net shares).

5. INCOME TAXES:

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

The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of March 31, 2014. Some or all of this valuation allowance may be reversed in future periods against future 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.

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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

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

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

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the balance sheet and the associated unrealized gains and losses are recorded as current income or expense in the Consolidated Statements of Income. 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 March 31, 2014, the Company had the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price and pays the variable price. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.


Natural Gas:

Type	Commodity Reference Price		Remaining Contract Period		Volume - MMBTU/Day		Average Price/MMBTU		Fair Value - March 31, 2014
									(Liability)
Swap		NYMEX-Henry Hub		Apr - Oct 2014		480,000	$	3.90	$	(56,125	)
Swap		NYMEX-Henry Hub		Nov - Dec 2014		85,000	$	4.35	$	(1,074	)

Crude Oil:

Type

Commodity
Reference
Price

Remaining Contract
Period

Volume -
Bbls/Day

Average
Price/Bbl

Fair Value -
March 31,
2014

(Net Liability)

Swap

NYMEX-WTI

Apr - Dec 2014

4,000

93.19

(4,997

)

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

The following table summarizes the pre-tax realized and unrealized loss the Company recognized related to its derivative instruments in the Consolidated Statements of Income for the periods ended March 31, 2014 and 2013:


	For the Three Months Ended March 31,
Commodity Derivatives:	2014			2013
Realized loss on commodity derivatives-natural gas(1)	$	(7,114	)	$	—
Realized loss on commodity derivatives-crude oil(1)		(1,840	)		—
Unrealized loss on commodity derivatives(1)		(36,319	)		(44,715	)

Total loss on commodity derivatives	$	(45,273	)	$	(44,715	)

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

The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts and 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.

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)

(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 March 31, 2014. The Company has no derivative instruments which qualify for cash flow hedge accounting.


	Level 1		Level 2		Level 3		Total
Assets:
Current derivative asset	$	—	$	290	$	—	$	290

Liabilities:
Current derivative liability	$	—	$	62,486	$	—	$	62,486

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 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.


	March 31, 2014				December 31, 2013
	Carrying Amount		Estimated Fair Value		Carrying Amount		Estimated Fair Value
5.45% Notes due March 2015, issued 2008	$	100,000	$	103,491	$	100,000	$	105,913
7.31% Notes due March 2016, issued 2009		62,000		68,071		62,000		70,228
4.98% Notes due January 2017, issued 2010		116,000		123,107		116,000		126,342
5.92% Notes due March 2018, issued 2008		200,000		220,516		200,000		226,127
5.75% Notes due December 2018, issued 2013		450,000		471,614		450,000		466,946
7.77% Notes due March 2019, issued 2009		173,000		205,850		173,000		211,877
5.50% Notes due January 2020, issued 2010		207,000		224,213		207,000		229,068
4.51% Notes due October 2020, issued 2010		315,000		319,195		315,000		323,732
5.60% Notes due January 2022, issued 2010		87,000		94,138		87,000		95,736
4.66% Notes due October 2022, issued 2010		35,000		35,167		35,000		35,494
5.85% Notes due January 2025, issued 2010		90,000		98,209		90,000		99,142
4.91% Notes due October 2025, issued 2010		175,000		175,095		175,000		175,744
Credit Facility due October 2016		415,000		415,000		460,000		460,000

	$	2,425,000	$	2,553,666	$	2,470,000	$	2,626,349

ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

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

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 for oil reserves in the Uinta Basin in Utah and 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. 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. Inflation has not had, nor is it expected to have in the foreseeable future, a material impact on the Company’s results of operations.

The Company currently generates its revenue, earnings and cash flow primarily from the production and sales of natural gas and condensate from its properties in southwest Wyoming with a portion of the Company’s revenues coming from gas sales from wells located in the Appalachian Basin in Pennsylvania. In December 2013, the Company acquired properties in the Uinta Basin in Utah which primarily produce oil resulting in increased oil revenues.

The price of natural gas is a critical factor to the Company’s business and the price of natural gas has historically been volatile, and its volatility could be detrimental to the Company’s financial performance. As a result, and from time to time, the Company tries to limit the impact of this volatility on its results by entering into swap agreements and/or fixed price forward physical delivery contracts for natural gas. (See Note 6).

During the quarter ended March 31, 2014, the average price realization for the Company’s natural gas was $4.96 per Mcf, including realized gains and losses on commodity derivatives. The Company’s average price realization for natural gas was $5.10 per Mcf, excluding the realized gains and losses on commodity derivatives. This compares with $3.50 per Mcf during the first quarter of 2013. There were no realized gains or losses related to commodity derivatives during the quarter ended March 31, 2013. (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. The Company follows 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 Income 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 March 31, 2014 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	$	—	$	290	$	—	$	290

Liabilities:
Current derivative liability	$	—	$	62,486	$	—	$	62,486

(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.

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”). As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.

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 three months ended March 31, 2014 and 2013 was $2.5 million and $3.0 million, respectively. See Note 4 for additional information.

Full Cost Method of Accounting. 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.

The Company did not have any write-downs related to the full cost ceiling limitation during the three months ended March 31, 2014 or 2013.

Capitalized Interest. Interest is capitalized on the cost of unevaluated gas and oil properties that are excluded from amortization and actively being evaluated, if any, as well as on work in process relating to gathering systems that are not currently in service (See Note 2).

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.

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.

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.


	For the Three Months Ended March 31, 2014						% Variance Favorable/ (Unfavorable)
	2014			2013			% Variance Favorable/ (Unfavorable)
	(Amounts in thousands,
	except per unit data)
*Production, Commodity Prices and Revenues:*
Production:
Natural gas (Mcf)		53,292			57,727			-8	%
Crude oil and condensate (Bbls)		658			268			145	%

Total production (Mcfe)		57,240			59,337			-4	%

Commodity Prices:
Natural gas ($/Mcf, including realized hedges)	$	4.96		$	3.50			42	%
Natural gas ($/Mcf, excluding hedges)	$	5.10		$	3.50			46	%
Crude oil and condensate ($/Bbl, including realized hedges)	$	80.42		$	87.33			-8	%
Crude oil and condensate ($/Bbl, excluding hedges)	$	83.22		$	87.33			-5	%

Revenues:
Natural gas sales	$	271,539		$	202,200			34	%
Oil sales	$	54,760		$	23,426			134	%

Total operating revenues	$	326,299		$	225,626			45	%

Derivatives:
Realized (loss) on commodity derviatives-natural gas	$	(7,114	)	$	—			n/a
Realized (loss) on commodity derviatives-crude oil	$	(1,840	)	$	—			n/a
Unrealized (loss) on commodity derivatives	$	(36,319	)	$	(44,715	)		19	%

Total (loss) on commodity derivatives	$	(45,273	)	$	(44,715	)		-1	%

*Operating Costs and Expenses:*
Lease operating expenses	$	21,013		$	18,817			-12	%
Liquids gathering system operating lease expense	$	5,076		$	5,000			-2	%
Production taxes	$	25,931		$	16,555			-57	%
Gathering fees	$	12,708		$	11,884			-7	%
Transportation charges	$	20,575		$	20,309			-1	%
Depletion, depreciation and amortization	$	63,181		$	61,468			-3	%
General and administrative expenses	$	6,345		$	5,961			-6	%

Per Unit Costs and Expenses ($/Mcfe):
Lease operating expenses	$	0.37		$	0.32			-16	%
Liquids gathering system operating lease expense	$	0.09		$	0.08			-13	%
Production taxes	$	0.45		$	0.28			-61	%
Gathering fees	$	0.22		$	0.20			-10	%
Transportation charges	$	0.36		$	0.34			-6	%
Depletion, depreciation and amortization	$	1.10		$	1.04			-6	%
General and administrative expenses	$	0.11		$	0.10			-10	%

Production, Commodity Derivatives and Revenues:

Production. During the quarter ended March 31, 2014, production decreased on a gas equivalent basis to 57.2 Bcfe compared to 59.3 Bcfe for the same quarter in 2013 as a result of decreased capital spending during 2013.

Commodity Prices. Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 42% to $4.96 per Mcf in the first quarter of 2014 as compared to $3.50 per Mcf for the same quarter of 2013. During the three months ended March 31, 2014, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $5.10 per Mcf as compared to $3.50 per Mcf for the same period in 2013.

Revenues. Production from the recently acquired assets in Utah along with the increase in average natural gas prices, excluding the gains and losses on commodity derivatives, partially offset by the decrease in natural gas production resulted in revenues increasing to $326.3 million for the quarter ended March 31, 2014 as compared to $225.6 million in for the same period in 2013.

Operating Costs and Expenses:

Lease Operating Expense. Lease operating expense (“LOE”) increased to $21.0 million during the first quarter of 2014 compared to $18.8 million during the same period in 2013 largely related to the recently acquired assets in Utah. On a unit of production basis, LOE costs increased to $0.37 per Mcfe during the first quarter of 2014 compared to $0.32 per Mcfe during the same period in 2013 as a result of decreased production volumes during the period ended March 31, 2014.

Operating Lease Expense. During December 2012, the Company sold a system of liquids gathering pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years, and annual rent for the initial term under the Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. The Company’s sale leaseback transaction was treated as a “normal leaseback” under the provisions of FASB ASC Topic 840, Leases (“FASB ASC Topic 840”) and qualified for sales recognition. The lease is classified as an operating lease. For the three months ended March 31, 2014, the Company recognized operating lease expense associated with the Lease Agreement of $5.1 million, or $0.09 per Mcfe as compared to $5.0 million, or $0.08 per Mcfe for the same period in 2013.

Production Taxes. During the three months ended March 31, 2014, production taxes were $25.9 million compared to $16.6 million during the same period in 2013, or $0.45 per Mcfe compared to $0.28 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 7.9% of revenues for the quarter ended March 31, 2014 and 7.3% of revenues for the same period in 2013. The increase in per unit taxes is primarily attributable to increased natural gas prices, excluding the effects of commodity derivatives during the quarter ended March 31, 2014 as compared to the same period in 2013.

Gathering Fees. Gathering fees increased slightly to $12.7 million for the three months ended March 31, 2014 compared to $11.9 million during the same period in 2013. On a per unit basis, gathering fees increased to $0.22 per Mcfe for the three months ended March 31, 2014 as compared to $0.20 per Mcfe during the same period in 2013.

Transportation Charges. The Company incurred firm transportation charges totaling $20.6 million for the quarter ended March 31, 2014 as compared to $20.3 million for the same period in 2013 in association with Rockies Express Pipeline (“REX”) transportation charges. On a per unit basis, transportation charges increased to $0.36 per Mcfe (on total company volumes) for the three months ended March 31, 2014 as compared to $0.34 per Mcfe (on total company volumes) for the same period in 2013 primarily due to decreased production volumes during the period ended March 31, 2014.

Depletion, Depreciation and Amortization. DD&A expenses increased to $63.2 million during the three months ended March 31, 2014 from $61.5 million for the same period in 2013, attributable to a higher depletion

rate primarily related to the Utah acquisition. On a unit of production basis, DD&A increased to $1.10 per Mcfe for the quarter ended March 31, 2014 from $1.04 per Mcfe for the quarter ended March 31, 2013.

General and Administrative Expenses. General and administrative expenses increased slightly to $6.3 million for the quarter ended March 31, 2014 compared to $6.0 million for the same period in 2013. On a per unit basis, general and administrative expenses increased to $0.11 per Mcfe for the quarter ended March 31, 2014 compared to $0.10 per Mcfe for the quarter ended March 31, 2013 primarily as a result of decreased production during the period ended March 31, 2014 as compared to the same period in 2013.

Other Income and Expenses:

Interest expense. Interest expense increased to $27.1 million during the quarter ended March 31, 2014 compared to $25.8 million during the same period in 2013 primarily as a result of higher average borrowings outstanding and partially offset by increased amounts of capitalized interest for the quarter ended March 31, 2014 as compared to the same period in 2013. (See Note 2).

Deferred Gain on Sale of Liquids Gathering System. During the quarters ended March 31, 2014 and 2013, the Company recognized $2.6 million in deferred gain on sale of the liquids gathering system relating to the sale of a system of pipelines and central gathering facilities and certain associated real property rights in the Pinedale Anticline in Wyoming during December 2012.

Commodity Derivatives:

(Loss) on Commodity Derivatives. During the quarter ended March 31, 2014, the Company recognized a loss of $45.3 million compared with a loss of $44.7 million during the same period in 2013 related to commodity derivatives. Of this total, the Company recognized $9.0 million of realized loss on commodity derivatives during the quarter ended March 31, 2014. There were no realized gains or losses related to commodity derivatives for the quarter ended March 31, 2013. The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts. This amount also includes an unrealized loss on commodity derivatives of $36.3 million during the quarter ended March 31, 2014 as compared to $44.7 million in unrealized loss on commodity derivatives during the quarter ended March 31, 2013. 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. See Note 6.

Income from Continuing Operations:

Pretax Income. The Company recognized income before income taxes of $101.7 million for the quarter ended March 31, 2014 compared with income before income taxes of $17.8 million for the same period in 2013. The increase in earnings is largely due to increased revenues as a result of increased price realizations during the three months ended March 31, 2014 as compared to the same period in 2013.

Income Taxes. The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of March 31, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.

Net Income. For the three months ended March 31, 2014, the Company recognized net income of $101.7 million or $0.66 per diluted share as compared with net income of $16.4 million or $0.11 per diluted share for the same period in 2013. The increase is largely due to increased revenues as a result of increased price realizations during the three months ended March 31, 2014 as compared to the same period in 2013.

LIQUIDITY AND CAPITAL RESOURCES

During the three month period ended March 31, 2014, 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 45 gross (31.3 net) wells that were drilled to total depth and cased. For the three month period ended March 31, 2014, total capital expenditures were $125.9 million ($123.6 million related to oil and gas exploration and development expenditures and $2.3 million related to gathering system expenditures).

At March 31, 2014, the Company reported a cash position of $8.0 million compared to $14.4 million at March 31, 2013. Working capital deficit at March 31, 2014 was $374.8 million compared to working capital deficit of $293.0 million at March 31, 2013. At March 31, 2014, the Company had $415.0 million in outstanding borrowings and $585.0 million of available borrowing capacity under the Credit Agreement. In addition, the Company had $2.01 billion outstanding in senior notes (See Note 3). Other long-term obligations of $106.9 million at March 31, 2014 were comprised of items payable in more than one year, primarily related to production taxes and asset retirement obligations.

The Company’s cash provided by operating activities, along with availability under the senior revolving credit facility (see Note 3), are projected to be sufficient to meet the Company’s obligations and to fund its budgeted capital investment program for 2014, which is currently projected to be approximately $560.0 million.

Ultra Resources, Inc. Bank Indebtedness: The Company’s subsidiary, Ultra Resources, Inc. (“Ultra Resources”, “Borrower”), is a party to a senior revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the Borrower and with the consent of lenders who are willing to increase their loan commitments, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016. With the majority (over 50%) lender consent, the term of the consenting lenders’ commitments may be extended for up to two successive one-year periods at the Borrower’s request. At March 31, 2014, the Company had $415.0 million in outstanding borrowings and $585.0 million of unused debt capacity under the Credit Agreement.

Ultra Resources, Inc. Senior Notes: Ultra Resources also has outstanding $1.56 billion in principal amount of Senior Notes. Ultra Resources’ Senior Notes rank pari passu with the Company’s Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. The Senior Notes are pre-payable in whole or in part at any time following the payment of a make-whole premium and are subject to representations, warranties, covenants and events of default similar to those in the Credit Facility. At March 31, 2014, the Company was in compliance with all of its debt covenants under the Senior Notes. (See Note 3).

Ultra Petroleum Corp. Senior Notes: On December 12, 2013, the Company issued $450.0 million of 5.75% Senior Notes due 2018 (“Notes”). The Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The Notes are not guaranteed by the

Company’s subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. On and after December 15, 2015, the Company may redeem all or, from time to time, a part of the Notes at the following prices expressed as a percentage of principal amount of the Notes: (2015 — 102.875%; 2016 — 101.438%; and 2017 and thereafter — 100.000%). The Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the Notes contain events of default customary for a senior note financing. At March 31, 2014, the Company was in compliance with all of its debt covenants under the Notes.

Operating Activities. During the three months ended March 31, 2014, net cash provided by operating activities was $175.6 million, a 159% increase from $67.9 million for the same period in 2013. The increase in net cash provided by operating activities is largely attributable to increased revenues as a result of increased price realizations during the three months ended March 31, 2014 as compared to the same period in 2013.

Investing Activities. During the three months ended March 31, 2014, net cash used in investing activities was $131.7 million as compared to $157.3 million for the same period in 2013. The decrease in net cash used in investing activities is largely related to the change in the 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.

Financing Activities. During the three months ended March 31, 2014, net cash used in financing activities was $46.6 million as compared to cash provided by financing activities of $90.9 million for the same period in 2013. The change in net cash used in financing activities is primarily due to decreased net borrowings during the three months ended March 31, 2014 as compared to 2013.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of March 31, 2014.

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, 2013 for additional risks related to the Company’s business.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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 Income. 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.


Natural Gas:

Type	Commodity Reference Price		Remaining Contract Period		Volume - MMBTU/Day	Average Price/MMBTU		Fair Value - March 31, 2014
								(000’s)
								(Liability)
Swap		NYMEX-Henry Hub		Apr - Oct 2014	480,000	$	3.90	$	(56,125	)
Swap		NYMEX-Henry Hub		Nov - Dec 2014	85,000	$	4.35	$	(1,074	)

Crude Oil:

Type

Commodity
Reference
Price

Remaining
Contract Period

Volume -
Bbls/Day

Average
Price/Bbl

Fair Value -
March 31, 2014

(000’s)

(Net Liability)

Swap

NYMEX-WTI

Apr - Dec 2014

4,000

93.19

(4,997

)


	For the Three Months Ended March 31,
Commodity Derivatives (000’s):	2014			2013
Realized loss on commodity derivatives-natural gas(1)	$	(7,114	)	$	—
Realized loss on commodity derivatives-crude oil(1)		(1,840	)		—
Unrealized loss on commodity derivatives(1)		(36,319	)		(44,715	)

Total loss on commodity derivatives	$	(45,273	)	$	(44,715	)

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

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 March 31, 2014. There were no changes in the Company’s internal control over financial reporting during the three months ended March 31, 2014 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, 2013.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

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: May 1, 2014


By:		/s/ Marshall D. Smith


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

Date: May 1, 2014

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

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Smaller reporting company