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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 September 30, 2013

or

 

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

For the transition period from                      to                     

Commission file number 001-33614

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

 

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

(281) 876-0120

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    YES  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):

 

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

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

The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of October 22, 2013 was 152,977,633.

 

 

 

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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			27
ITEM 4.		Controls and Procedures			28
PART II — OTHER INFORMATION
ITEM 1.		Legal Proceedings			29
ITEM 1A.		Risk Factors			29
ITEM 2.		Unregistered Sales of Equity Securities and Use of Proceeds			29
ITEM 3.		Defaults upon Senior Securities			29
ITEM 4.		Mine Safety Disclosures			29
ITEM 5.		Other Information			29
ITEM 6.		Exhibits			30
		Signatures			31
		Exhibit Index			32

 

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PART I — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
		2013				2012				2013				2012
		(Unaudited)
		(Amounts in thousands,
		except per share data)
Revenues:
Natural gas sales		$	191,453			$	169,594			$	628,438			$	501,470
Oil sales			29,752				26,781				79,769				91,319
Total operating revenues			221,205				196,375				708,207				592,789
Expenses:
Lease operating expenses			16,213				16,741				52,544				45,982
Liquids gathering system operating lease expense			5,000				—				15,000				—
Production taxes			18,078				15,047				54,640				46,634
Gathering fees			12,682				10,274				38,400				46,591
Transportation charges			20,955				21,055				61,913				63,477
Depletion, depreciation and amortization			59,401				86,645				180,993				314,115
Ceiling test and other impairments			—				606,827				—				2,475,963
General and administrative			4,060				6,741				15,897				19,308
Total operating expenses			136,389				763,330				419,387				3,012,070
Operating income (loss)			84,816				(566,955	)			288,820				(2,419,281	)
Other income (expense), net:
Interest expense			(25,174	)			(25,369	)			(76,176	)			(62,414	)
Gain (loss) on commodity derivatives			2,074				(9,896	)			(20,551	)			77,100
Deferred gain on sale of liquids gathering system			2,638				—				7,914				—
Contract cancellation fees			—				291				—				(9,220	)
Other expense, net			(63	)			(42	)			(50	)			(27	)
Total other (expense) income, net			(20,525	)			(35,016	)			(88,863	)			5,439
Income (loss) before income tax provision (benefit)			64,291				(601,971	)			199,957				(2,413,842	)
Income tax provision (benefit)			381				175				3,240				(708,977	)
Net income (loss)		$	63,910			$	(602,146	)		$	196,717			$	(1,704,865	)
Net income (loss) per common share — basic		$	0.42			$	(3.94	)		$	1.29			$	(11.16	)
Net income (loss) per common share — fully diluted		$	0.41			$	(3.94	)		$	1.27			$	(11.16	)
Weighted average common shares outstanding — basic			152,976				152,929				152,957				152,817
Weighted average common shares outstanding — fully diluted			154,512				152,929				154,366				152,817

See accompanying notes to consolidated financial statements.

 

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ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS

 

		September 30, 2013				December 31, 2012
		(Unaudited)
		(Amounts in thousands of U.S. dollars, except share data)
ASSETS
Current Assets:
Cash and cash equivalents		$	4,532			$	12,921
Restricted cash			119				121
Oil and gas revenue receivable			74,104				81,143
Joint interest billing and other receivables			12,067				26,712
Derivative assets			1,239				—
Prepaid drilling costs and other current assets			3,999				4,951
Total current assets			96,060				125,848
Oil and gas properties, net, using the full cost method of accounting:
Proven			1,750,694				1,657,500
Property, plant and equipment, net			212,185				212,372
Deferred financing costs and other			10,017				11,625
Total assets		$	2,068,956			$	2,007,345
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	44,198			$	67,489
Accrued liabilities			77,669				121,124
Production taxes payable			38,224				47,745
Interest payable			8,568				30,093
Derivative liabilities			716				—
Capital cost accrual			170,539				247,641
Total current liabilities			339,914				514,092
Long-term debt			1,860,000				1,837,000
Deferred gain on sale of liquids gathering system			150,039				158,082
Other long-term obligations			95,843				76,038
Commitments and contingencies
Shareholders’ equity:
Common stock — no par value; authorized — unlimited; issued and outstanding — 152,977,633 and 152,929,907 at September 30, 2013 and December 31, 2012, respectively			482,949				474,016
Treasury stock			(2,205	)			(13	)
Retained loss			(857,584	)			(1,051,870	)
Total shareholders’ deficit			(376,840	)			(577,867	)
Total liabilities and shareholders’ equity		$	2,068,956			$	2,007,345

See accompanying notes to consolidated financial statements.

 

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ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		Nine Months Ended September 30,
		2013				2012
		(Unaudited)
		(Amounts in thousands of U.S. dollars)
Cash provided by (used in):
Operating activities:
Net income for the period		$	196,717			$	(1,704,865	)
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization			180,993				314,115
Ceiling test and other impairments			—				2,475,963
Deferred income tax benefit			—				(712,363	)
Unrealized (gain)/loss on commodity derivatives			(523	)			183,139
Deferred gain on sale of liquids gathering system			(7,914	)			—
Reduction in tax benefits from stock based compensation			—				4,215
Stock compensation			6,625				7,830
Other			1,678				1,663
Net changes in operating assets and liabilities:
Restricted cash			2				—
Accounts receivable			22,314				86,560
Prepaid expenses and other			510				1,418
Accounts payable and accrued liabilities			(45,902	)			(151,016	)
Production taxes payable			(9,521	)			(2,033	)
Interest payable			(21,525	)			(21,811	)
Other long-term obligations			12,745				(1,747	)
Current taxes payable			(9,128	)			(993	)
Net cash provided by operating activities			327,071				480,075
Investing Activities:
Oil and gas property expenditures			(283,621	)			(588,808	)
Gathering system expenditures			(5,137	)			(115,972	)
Change in capital cost accrual			(64,451	)			30,368
Proceeds from sale of oil and gas properties			(129	)			—
Inventory			617				(1,035	)
Purchase of capital assets			(415	)			(4,133	)
Net cash used in investing activities			(353,136	)			(679,580	)
Financing activities:
Borrowings on long-term debt			653,000				749,000
Payments on long-term debt			(630,000	)			(492,000	)
Repurchased shares/net share settlements			(5,324	)			(6,550	)
(Reduction in) tax benefits from stock based compensation			—				(4,215	)
Proceeds from exercise of options			—				1,157
Net cash provided by financing activities			17,676				247,392
(Decrease) increase in cash during the period			(8,389	)			47,887
Cash and cash equivalents, beginning of period			12,921				11,307
Cash and cash equivalents, end of period		$	4,532			$	59,194
SUPPLEMENTAL INFORMATION:
Non-cash investing activities — oil and gas properties		$	12,651				—

See accompanying notes to consolidated financial statements.

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

DESCRIPTION OF THE BUSINESS:

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

1. SIGNIFICANT ACCOUNTING POLICIES:

The accompanying financial statements, other than the balance sheet data as of December 31, 2012, 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, 2012 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, Extractive Activities — Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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 nine months ended September 30, 2013. The Company recorded a $2.9 billion non-cash write-down of the carrying value of its proved oil and natural gas properties during the year ended December 31, 2012 as a result of ceiling test limitations.

(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 Operations as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

likely than not” criteria described in FASB ASC Topic 740, Income Taxes. In addition, the Company recognizes the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit.

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

 

		Three Months Ended								Nine Months Ended
		September 30, 2013				September 30, 2012				September 30, 2013				September 30, 2012
		(Share amounts in 000’s)
Net income (loss)		$	63,910			$	(602,146	)		$	196,717			$	(1,704,865	)
Weighted average common shares outstanding — basic			152,976				152,929				152,957				152,817
Effect of dilutive instruments			1,536				—				1,409				—
Weighted average common shares outstanding — fully diluted			154,512				152,929				154,366				152,817
Net income (loss) per common share — basic		$	0.42			$	(3.94	)		$	1.29			$	(11.16	)
Net income (loss) per common share — fully diluted		$	0.41			$	(3.94	)		$	1.27			$	(11.16	)
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			1,340				1,373				1,353				1,893

(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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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 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.

(o) Recent Accounting Pronouncements: In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”), which finalizes Proposed ASU No. 2012-250 and clarifies the scope of transactions that are subject to disclosures concerning offsetting. Update 2013-01 addresses implementation issues regarding the scope of ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, issued in December 2011. Update 2013-01 clarifies that the scope of the disclosures under U.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are offset either in accordance with FASB ASC Section 210-20-45, Balance Sheet — Offsetting — Other Presentation Matters, or FASB ASC Section 815-10-45, Derivatives and Hedging — Overall — Other Presentation Matters, or are subject to a master netting arrangement or similar agreement. Update 2013-01 requires an entity (1) to apply the amendments for annual reporting periods beginning on or after January 1, 2013 and (2) to provide the required disclosures retrospectively for all comparative periods presented. The implementation of the disclosure requirement did not have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

2. OIL AND GAS PROPERTIES AND EQUIPMENT:

 

		September 30, 2013				December 31, 2012
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs		$	7,500,559			$	7,235,765
Less: Accumulated depletion, depreciation and amortization(1)(2)			(5,749,865	)			(5,578,265	)
Net capitalized costs — oil and gas properties			1,750,694				1,657,500
Property, Plant and Equipment:
Gathering Systems(1)		$	288,015			$	282,879
Less: Accumulated depreciation(3)			(103,725	)			(99,312	)
			184,290				183,567
Other Property and Equipment			14,903				14,772
Less: Accumulated depreciation			(9,367	)			(8,326	)
			5,536				6,446
Land			22,359				22,359
Net capitalized costs — property, plant and equipment		$	212,185			$	212,372

 

(1)

For the nine months ended September 30, 2013 and 2012, total interest on outstanding debt was $76.7 million and $77.2 million, respectively, of which, $0.5 million and $14.8 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and on work in process relating to gathering systems.

(2)	The Company recorded a $2.9 billion non-cash write-down of the carrying value of its proved oil and natural gas properties for the year ended December 31, 2012 as a result of ceiling test limitations.

(3)

The Company recognized impairments of $92.5 million during the year ended December 31, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of a decrease in forecast 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:

 

		September 30, 2013				December 31, 2012
Bank indebtedness		$	300,000			$	277,000
Senior Notes			1,560,000				1,560,000
Other long-term obligations			95,843				76,038
		$	1,955,843			$	1,913,038

Bank indebtedness: The Company (through its subsidiary, Ultra Resources, Inc.) is a party to a senior revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the borrower and with the 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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

successive one-year periods at the Borrower’s request and with the lenders’ consent). At September 30, 2013, the Company had $300.0 million in outstanding borrowings and $700.0 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 September 30, 2013). 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 September 30, 2013, 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 with the first maturity date occurring in March 2015 (See Note 7). 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, subject to payment of a make-whole provision, and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At September 30, 2013, 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 September 30,								Nine Months Ended September 30,
		2013				2012				2013				2012
Total cost of share-based payment plans		$	601			$	4,497			$	9,458			$	11,513
Amounts capitalized in oil and gas properties and equipment		$	37			$	1,448			$	2,833			$	3,683
Amounts charged against income, before income tax benefit		$	564			$	3,049			$	6,625			$	7,830
Amount of related income tax benefit recognized in income before valuation allowance		$	232			$	1,255			$	2,728			$	3,224

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the nine months ended September 30, 2013 and the year ended December 31, 2012:

 

		Number of Options (000’s)				Weighted Average Exercise Price (US$)
Balance, December 31, 2011			1,459			$	16.97				to			$	98.87
Forfeited			(68	)		$	25.08				to			$	75.18
Exercised			(34	)		$	16.97				to			$	19.18
Balance, December 31, 2012			1,357			$	16.97				to			$	98.87
Forfeited			(69	)		$	25.68				to			$	75.18
Exercised			—			$	—				to			$	—
Balance, September 30, 2013			1,288			$	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 2011, 2012 and 2013, 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 2011 and 2012, the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth. For the LTIP awards in 2013, the Committee established the following performance measures: return on capital employed, debt level, reserve replacement ratio, and total shareholder return (officers only).

For the nine months ended September 30, 2013, the Company recognized $4.5 million in pre-tax compensation expense related to the 2011, 2012 and 2013 LTIP awards of restricted stock units as compared to $5.6 million during the nine months ended September 30, 2012 related to the 2010, 2011 and 2012 LTIP awards of restricted stock units. The amounts recognized during the nine months ended September 30, 2013 assume that target performance objectives are attained for the 2011 LTIP and maximum performance objectives are attained under the 2012 LTIP and 2013 LTIP plans. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at September 30, 2013, for each of the three year performance periods is expected to be approximately $8.2 million, $12.4 million, and $15.2 million related to the 2011, 2012 and 2013 LTIP awards of restricted stock units, respectively. The 2010 LTIP award of restricted stock units was paid in shares of the Company’s stock to employees during the first quarter of 2013 and totaled $11.7 million (153,511 net shares).

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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.

As a result of the ceiling test and other impairments recorded during the year ended December 31, 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 $380.3 million as of September 30, 2013. This valuation allowance may be reversed in future periods against future taxable income.

6. DERIVATIVE FINANCIAL INSTRUMENTS:

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

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

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

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

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the balance sheet and the associated unrealized gains and losses are recorded as current income or expense in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement. See Note 7 for the detail of the fair value of the following derivatives.

Commodity Derivative Contracts: At September 30, 2013, the Company had the following open commodity derivative contracts to manage price risk on a portion of its natural gas production whereby the Company receives the fixed price and pays the variable price. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties.

 

Type

Commodity Reference Price

Remaining Contract Period

Volume - MMBTU/Day

Average Price/MMBTU

Fair Value - September 30, 2013

Asset

Swap

NYMEX

Oct-13

390,000

$

3.54

$

523

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The following table summarizes the pre-tax realized and unrealized gains and (losses) the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the periods ended September 30, 2013 and 2012:

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
Natural Gas Commodity Derivatives:		2013				2012				2013				2012
Realized (loss) gain on commodity derivatives(1)		$	(1,310	)		$	83,433			$	(21,074	)		$	260,239
Unrealized gain (loss) on commodity derivatives(1)			3,384				(93,329	)			523				(183,139	)
Total gain (loss) on commodity derivatives		$	2,074			$	(9,896	)		$	(20,551	)		$	77,100

 

(1)	Included in gain (loss) 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).

The following table presents for each hierarchy level the Company’s assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis, as of September 30, 2013. The Company has no derivative instruments which qualify for cash flow hedge accounting.

 

		Level 1				Level 2				Level 3				Total
Assets:
Current derivative asset		$	—			$	1,239			$	—			$	1,239
Liabilities:
Current derivative liability		$	—			$	716			$	—			$	716

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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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.

 

		September 30, 2013								December 31, 2012
		Carrying Amount				Estimated Fair Value				Carrying Amount				Estimated Fair Value
Long-Term Debt:
5.45% Notes due 2015, issued 2008		$	100,000			$	105,421			$	100,000			$	107,801
7.31% Notes due 2016, issued 2009			62,000				69,765				62,000				72,046
4.98% Notes due 2017, issued 2010			116,000				125,335				116,000				127,109
5.92% Notes due 2018, issued 2008			200,000				224,213				200,000				230,062
7.77% Notes due 2019, issued 2009			173,000				209,877				173,000				219,045
5.50% Notes due 2020, issued 2010			207,000				225,420				207,000				234,552
4.51% Notes due 2020, issued 2010			315,000				316,920				315,000				331,329
5.60% Notes due 2022, issued 2010			87,000				92,500				87,000				98,526
4.66% Notes due 2022, issued 2010			35,000				33,955				35,000				36,361
5.85% Notes due 2025, issued 2010			90,000				93,841				90,000				102,096
4.91% Notes due 2025, issued 2010			175,000				165,595				175,000				179,677
Credit Facility			300,000				300,000				277,000				277,000
		$	1,860,000			$	1,962,842			$	1,837,000			$	2,015,604

8. LEGAL PROCEEDINGS:

The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position or results of operations.

9. SUBSEQUENT EVENTS:

The Company has evaluated the period subsequent to September 30, 2013 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events other than those discussed below arose that should be disclosed in order to keep the financial statements from being misleading.

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

On October 18, 2013, a wholly owned subsidiary of Ultra Petroleum Corp. entered into a purchase and sale agreement with a private seller (the “PSA”) to acquire oil-producing properties and undeveloped acreage in Utah for an initial purchase price of $650.0 million, effective as of October 1, 2013. The PSA provides for ordinary and customary adjustments for due diligence items, including title and environmental matters, and other matters. In the PSA, both the Company and the seller make customary representations and warranties. The Company expects to close the transaction in December 2013.

 

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

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

Overview

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

The Company currently conducts operations exclusively in the United States. Substantially all of its oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect only the Company’s proportionate interest in such activities. Inflation has not had a material impact on the Company’s results of operations and is not expected to in the foreseeable 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 oil from its property in southwest Wyoming with an increasing portion of the Company’s cash flow coming from gas sales from wells located in the Appalachian Basin in Pennsylvania.

Part of the Company’s business strategy includes proactive and regular review of its portfolio of investment opportunities with a focus on investments that produce positive returns. Accordingly, in response to the current reduced natural gas price environment, the Company has concurrently reduced capital expenditures by reducing the number of drilling rigs operating in its Wyoming fields down to two and reducing drilling activity in Pennsylvania.

The price of natural gas is a critical factor to the Company’s business. 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.

During the quarter ended September 30, 2013, the average price realization for the Company’s natural gas was $3.41 per Mcf, including realized gains and losses on commodity derivatives. The Company’s average price realization for natural gas was $3.44 per Mcf, excluding the realized gains and losses on commodity derivatives. This compares with $4.13 per Mcf, including realized gains and losses on commodity derivatives, and $2.77 per Mcf, excluding such realized gains during the third quarter of 2012. (See Note 6).

Critical Accounting Policies

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

 

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Derivative Instruments and Hedging Activities. 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 Operations as an unrealized gain or loss on commodity derivatives.

Fair Value Measurements. The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”). Under FASB ASC 820, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at measurement date and establishes a three level hierarchy for measuring fair value. The valuation assumptions utilized to measure the fair value of the Company’s commodity derivatives were observable inputs based on market data obtained from independent sources and are considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market-corroborated inputs).

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

The fair values summarized below were determined in accordance with the requirements of FASB ASC 820 and the Company aligned the categories below with the Level 1, 2, and 3 fair value measurements as defined by FASB ASC 820. The balance of net unrealized gains and losses recognized for the Company’s energy-related derivative instruments at September 30, 2013 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		$	—			$	1,239			$	—			$	1,239
Liabilities:
Current derivative liability		$	—			$	716			$	—			$	716

 

(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.

 

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Share-Based Payment Arrangements. The Company applies FASB ASC Topic 718, Compensation — Stock Compensation (“FASB ASC 718”), which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized for the nine months ended September 30, 2013 and 2012 was $6.6 million and $7.8 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 nine months ended September 30, 2013. During the second, third and fourth quarters of 2012, the Company recorded an aggregate $2.9 billion in non-cash write-downs of the carrying value of its proved oil and natural gas properties as a result of ceiling test limitations. The ceiling test was calculated based upon the average of quoted market prices in effect on the first day of the month for the twelve month period preceding the end of such quarters, respectively.

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

 

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determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue.

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

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

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

As a result of the tax effect of the ceiling test and other impairments recorded during the year ended December 31, 2012, the Company’s previously recorded net deferred tax liability fully reversed into a net deferred tax asset. The Company recorded a full valuation allowance against its net deferred tax asset balance of $377.2 million as of September 30, 2013. This valuation allowance may be reversed in future periods against future taxable income.

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

Recent accounting pronouncements. In January 2013, the FASB issued Accounting Standards Update No. 2013-01, Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (“Update 2013-01”), which finalizes Proposed ASU No. 2012-250 and clarifies the scope of transactions that are subject to disclosures concerning offsetting. Update 2013-01 addresses implementation issues regarding the scope of ASU No. 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities, issued in December 2011. Update 2013-01 clarifies that the scope of the disclosures under U.S. GAAP is limited to derivatives, repurchase agreements and reverse purchase agreements, and securities borrowing and securities lending transactions that are offset either in accordance with FASB ASC Section 210-20-45, Balance Sheet — Offsetting — Other Presentation Matters, or FASB ASC Section 815-10-45, Derivatives and Hedging — Overall — Other Presentation Matters, or are subject to a master netting arrangement or similar agreement. Update 2013-01 requires an entity (1) to apply the amendments for annual reporting periods beginning on or after January 1, 2013 and (2) to provide the required disclosures retrospectively for all comparative periods presented. The implementation of the disclosure requirement did not have a material impact on the Company’s consolidated results of operations, financial position or cash flows.

 

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RESULTS OF OPERATIONS

Quarter Ended September 30, 2013 vs. Quarter Ended September 30, 2012

During the quarter ended September 30, 2013, production decreased on a gas equivalent basis to 57.5 Bcfe compared to 63.1 Bcfe for the same quarter in 2012 as a result of decreased capital spending in response to reduced natural gas prices. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 17% to $3.41 per Mcf in the third quarter of 2013 as compared to $4.13 per Mcf for the same quarter of 2012. During the three months ended September 30, 2013, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $3.44 per Mcf as compared to $2.77 per Mcf for the same period in 2012. The increase in average natural gas prices, excluding the gains and losses on commodity derivatives, partially offset by the decrease in production resulted in revenues increasing to $221.2 million for the quarter ended September 30, 2013 as compared to $196.4 million in for the same period in 2012.

Lease operating expense (“LOE”) decreased slightly to $16.2 million during the third quarter of 2013 compared to $16.7 million during the same period in 2012. On a unit of production basis, LOE costs increased to $0.28 per Mcfe during the third quarter of 2013 compared to $0.27 per Mcfe during the same period in 2012 as a result of decreased production volumes during the period ended September 30, 2013.

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 September 30, 2013, the Company recognized operating lease expense associated with the Lease Agreement of $5.0 million, or $0.09 per Mcfe.

During the three months ended September 30, 2013, production taxes were $18.1 million compared to $15.0 million during the same period in 2012, or $0.31 per Mcfe compared to $0.24 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 8.2% of revenues for the quarter ended September 30, 2013 and 7.7% of revenues for the same period in 2012. The increase in per unit taxes is primarily attributable to increased natural gas prices, excluding the effects of commodity derivatives during the quarter ended September 30, 2013 as compared to the same period in 2012.

Gathering fees increased to $12.7 million for the three months ended September 30, 2013 compared to $10.3 million during the same period in 2012 largely due to increased gathering rates and compression charges in Pennsylvania. On a per unit basis, gathering fees increased to $0.22 per Mcfe for the three months ended September 30, 2013 as compared to $0.16 per Mcfe during the same period in 2012.

The Company incurred firm transportation charges totaling $21.0 million for the quarter ended September 30, 2013 as compared to $21.1 million for the same period in 2012 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 September 30, 2013 as compared to $0.33 per Mcfe (on total company volumes) for the same period in 2012 primarily due to decreased production volumes during the period ended September 30, 2013.

DD&A expenses decreased to $59.4 million during the three months ended September 30, 2013 from $86.6 million for the same period in 2012, attributable to a lower depletion rate due mainly to a lower depletable base as a result of the ceiling test write-downs during the year ended December 31, 2012 and decreased

 

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production volumes during the quarter ended September 30, 2013 as compared to the same period in 2012. On a unit of production basis, DD&A decreased to $1.03 per Mcfe for the quarter ended September 30, 2013 from $1.37 per Mcfe for the quarter ended September 30, 2012.

The Company recorded a $606.8 million non-cash write-down of the carrying value of its proved oil and natural gas properties during the three months ended September 30, 2012, which is reflected with ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The Company did not have any write-downs related to the full cost ceiling limitation during the third quarter of 2013.

General and administrative expenses decreased to $4.1 million for the quarter ended September 30, 2013 compared to $6.7 million for the same period in 2012. The decrease in general and administrative expenses is largely attributable to lower employee-related and consultant costs. On a per unit basis, general and administrative expenses decreased to $0.07 per Mcfe for the quarter ended September 30, 2013 compared to $0.11 per Mcfe for the quarter ended September 30, 2012 primarily as a result of lower employee-related and consultant costs during the period ended September 30, 2013 as compared to the same period in 2012.

Interest expense remained flat at $25.2 million during the quarter ended September 30, 2013 compared to $25.4 million during the same period in 2012.

During the quarter ended September 30, 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. The net proceeds received for the assets were $224.2 million.

During the quarter ended September 30, 2013, the Company recognized $1.3 million of realized loss on commodity derivatives as compared to $83.4 million of realized gain on commodity derivatives during the same period in 2012. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts.

During the quarter ended September 30, 2013, the Company recorded $3.4 million in unrealized gain on commodity derivatives as compared to $93.3 million in unrealized loss on commodity derivatives during the quarter ended September 30, 2012. 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 income before income taxes of $64.3 million for the quarter ended September 30, 2013 compared with a loss before income taxes of $602.0 million for the same period in 2012. The increase in earnings is largely due to the non-cash ceiling test and other impairments and decreased DD&A expense as a result of a lower depletable base offset in part by changes in unrealized gains/losses associated with commodity derivatives and reduced realizations associated with realized gains and losses on commodity derivatives during the three months ended September 30, 2013 as compared to the same period in 2012.

As a result of the non-cash ceiling test and other impairments recorded during the year ended December 31, 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 $380.3 million as of September 30, 2013. This valuation allowance may be reversed in future periods against future taxable income. The income tax provision recognized for the quarter ended September 30, 2013 was $0.4 million compared with an income tax provision of $0.2 million for the three months ended September 30, 2012.

For the three months ended September 30, 2013, the Company recognized net income of $63.9 million or $0.41 per diluted share as compared with net loss of $602.1 million or ($3.94) per diluted share for the same period in 2012. The increase is largely due to the non-cash ceiling test and other impairments and decreased DD&A expense as a result of a lower depletable base offset in part by changes in unrealized gains/losses

 

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associated with commodity derivatives and reduced realizations associated with realized gains and losses on commodity derivatives during the three months ended September 30, 2013 as compared to the same period in 2012.

Nine Months Ended September 30, 2013 vs. Nine Months Ended September 30, 2012

During the nine months ended September 30, 2013, production decreased on a gas equivalent basis to 175.3 Bcfe compared to 196.9 Bcfe for the same period in 2012 as a result of decreased capital spending in response to reduced natural gas prices. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 11% to $3.57 per Mcf in the nine months of 2013 as compared to $3.99 per Mcf for the same period in 2012. During the nine months ended September 30, 2013, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $3.70 per Mcf as compared to $2.63 per Mcf for the same period in 2012. The increase in average natural gas prices, excluding the gains and losses on commodity derivatives, partially offset by the decrease in production resulted in revenues increasing to $708.2 million for the nine ended September 30, 2013 as compared to $592.8 million in for the same period in 2012.

LOE increased to $52.5 million during the nine months ended September 30, 2013 compared to $46.0 million during the same period in 2012 primarily due to increased well counts. On a unit of production basis, LOE costs increased to $0.30 per Mcfe during the nine months ended September 30, 2013 compared to $0.23 per Mcfe during the same period in 2012 as a result of decreased production volumes and increased costs during the period ended September 30, 2013.

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 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 and qualified for sales recognition. The lease is classified as an operating lease. For the nine months ended September 30, 2013, the Company recognized operating lease expense associated with the Lease Agreement of $15.0 million, or $0.09 per Mcfe.

During the nine months ended September 30, 2013, production taxes were $54.6 million compared to $46.6 million during the same period in 2012, or $0.31 per Mcfe compared to $0.24 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 7.7% of revenues for the nine months ended September 30, 2013 and 7.9% of revenues for the same period in 2012. The increase in per unit taxes is primarily attributable to increased natural gas prices, excluding the effects of commodity derivatives, during the nine months ended September 30, 2013 as compared to the same period in 2012.

Gathering fees decreased to $38.4 million for the nine months ended September 30, 2013 compared to $46.6 million during the same period in 2012 largely due to ownership participation in the Anadarko gathering system beginning in the second quarter of 2012 as well as a higher percentage of production in Pennsylvania in areas where the Company does not incur third party gathering fees. On a per unit basis, gathering fees decreased to $0.22 per Mcfe for the nine months ended September 30, 2013 as compared to $0.24 per Mcfe during the same period in 2012.

The Company incurred firm transportation charges totaling $61.9 million for the nine months ended September 30, 2013 as compared to $63.5 million for the same period in 2012 in association with Rockies Express Pipeline (“REX”) transportation charges. On a per unit basis, transportation charges increased to $0.35 per Mcfe (on total company volumes) for the nine months ended September 30, 2013 as compared to $0.32 per Mcfe (on total company volumes) for the same period in 2012 primarily due to decreased production volumes during the period ended September 30, 2013.

 

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DD&A expenses decreased to $181.0 million during the nine months ended September 30, 2013 from $314.1 million for the same period in 2012, attributable to a lower depletion rate due mainly to a lower depletable base as a result of the ceiling test write-downs during the year ended December 31, 2012 and decreased production volumes during the period ended September 30, 2013 as compared to the same period in 2012. On a unit of production basis, DD&A decreased to $1.03 per Mcfe for the nine months ended September 30, 2013 from $1.60 per Mcfe for the nine months ended September 30, 2012.

The Company recorded a $2.4 billion non-cash write-down of the carrying value of its proved oil and natural gas properties at September 30, 2012, which is reflected with ceiling test and other impairments in the accompanying Consolidated Statements of Operations. The Company did not have any write-downs related to the full cost ceiling limitation during the nine months ended September 30, 2013. In addition, the Company recognized impairments of $92.5 million at September 30, 2012 related to the decline in fair value as defined in FASB ASC 820 as a result of decreased throughput volumes on its gathering facilities in Pennsylvania due to the decline in commodity prices. The Company did not have any write-downs related to the decline in fair value on its gathering assets during the nine months ended September 30, 2013.

General and administrative expenses decreased to $15.9 million for the nine months ended September 30, 2013 compared to $19.3 million for the same period in 2012. The decrease in general and administrative expenses is largely attributable to lower employee-related and consultant costs. On a per unit basis, general and administrative expenses decreased to $0.09 per Mcfe for the nine months ended September 30, 2013 compared to $0.10 per Mcfe for the nine months ended September 30, 2012 primarily as a result of lower employee-related and consultant costs during the period ended September 30, 2013, offset in part by decreased production volumes during the period ended September 30, 2013 as compared to the same period in 2012.

Interest expense increased to $76.2 million during the nine months ended September 30, 2013 compared to $62.4 million during the same period in 2012 primarily related to lower amounts of capitalized interest related to unevaluated oil and gas properties that are excluded from amortization. The Company capitalized $0.5 million and $14.8 million in interest expense for the nine months ended September 30, 2013 and 2012, respectively, related to unevaluated oil and gas properties and on work in process relating to gathering systems (See Note 2).

During the nine months ended September 30, 2013, the Company recognized $7.9 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. The net proceeds received for the assets were $224.2 million.

During the nine months ended September 30, 2012, the Company recognized $9.2 million in rig cancellation fees related to reduction of drilling rig count down to two rigs during the year ended December 31, 2012. There were no rig cancellation fees recorded during the nine months ended September 30, 2013.

During the nine months ended September 30, 2013, the Company recognized $21.1 million of realized loss on commodity derivatives as compared to $260.2 million of realized gain on commodity derivatives during the same period in 2012. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under the Company’s derivative contracts.

During the nine months ended September 30, 2013, the Company recorded $0.5 million in unrealized gain on commodity derivatives as compared to $183.1 million in unrealized loss on commodity derivatives during the nine months ended September 30, 2012. 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 income before income taxes of $200.0 million for the nine months ended September 30, 2013 compared with a loss before income taxes of $2.4 billion for the same period in 2012. The increase in earnings is largely due to the non-cash ceiling test and other impairments and decreased DD&A

 

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expense as a result of a lower depletable base offset in part by changes in unrealized losses associated with commodity derivatives and reduced realizations associated with realized gains and losses on commodity derivatives during the nine months ended September 30, 2013 as compared to the same period in 2012.

As a result of the non-cash ceiling test and other impairments recorded during the year ended December 31, 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 $380.3 million as of September 30, 2013. This valuation allowance may be reversed in future periods against future taxable income. The income tax provision recognized for the nine months ended September 30, 2013 was $3.2 million compared with an income tax benefit of $709.0 million for the nine months ended September 30, 2012.

For the nine months ended September 30, 2013, the Company recognized net income of $196.7 million or $1.27 per diluted share as compared with net loss of $1.7 billion or ($11.16) per diluted share for the same period in 2012. The increase is largely due to the non-cash ceiling test and other impairments and decreased DD&A expense as a result of a lower depletable base offset in part by changes in unrealized losses associated with commodity derivatives and reduced realizations associated with realized gains and losses on commodity derivatives during the nine months ended September 30, 2013 as compared to the same period in 2012.

LIQUIDITY AND CAPITAL RESOURCES

During the nine month period ended September 30, 2013, 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 121 gross (56.2 net) wells that were drilled to total depth and cased. For the nine month period ended September 30, 2013, total capital expenditures were $288.7 million ($283.6 million related to oil and gas exploration and development expenditures and $5.1 million related to gathering system expenditures).

At September 30, 2013, the Company reported a cash position of $4.5 million compared to $59.2 million at September 30, 2012. Working capital deficit at September 30, 2013 was $243.9 million compared to working capital deficit of $266.6 million at September 30, 2012. At September 30, 2013, the Company had $300.0 million in outstanding borrowings and $700.0 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 $95.8 million at September 30, 2013 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 2013, which is currently projected to be approximately $385.0 million.

Bank indebtedness: The Company (through its subsidiary, Ultra Resources, Inc.) is a party to a senior revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the borrower and with the lenders’ consent, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016 (which term may be extended for up to two successive one-year periods at the Borrower’s request and with the lenders’ consent). At September 30, 2013, the Company had $300.0 million in outstanding borrowings and $700.0 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 September 30, 2013). The Company also pays commitment fees on the unused commitment under the facility based on a grid of its consolidated leverage ratio.

 

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The Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The Credit Agreement includes restrictive covenants requiring the Borrower to maintain a consolidated leverage ratio of no greater than three and one half times to one and, as long as the Company’s debt rating is below investment grade, the maintenance of an annual ratio of the net present value of the Company’s oil and gas properties to total funded debt of no less than one and one half times to one. At September 30, 2013, 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, subject to payment of a make-whole provision, and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At September 30, 2013, 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 nine months ended September 30, 2013, net cash provided by operating activities was $327.1 million, a 32% decrease from $480.1 million for the same period in 2012. The decrease in net cash provided by operating activities is largely attributable to decreased realized prices, including realized gains on commodity derivatives, and lower production during the nine months ended September 30, 2013 as compared to the same period in 2012.

Investing Activities. During the nine months ended September 30, 2013, net cash used in investing activities was $353.1 million as compared to $679.6 million for the same period in 2012. The decrease in net cash used in investing activities is largely related to decreased capital investments associated with the Company’s drilling activities in 2013 as compared to 2012.

Financing Activities. During the nine months ended September 30, 2013, net cash provided by financing activities was $17.7 million as compared to $247.4 million for the same period in 2012. The decrease in net cash provided by financing activities is primarily due to decreased net borrowings in 2013 as compared to 2012.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of September 30, 2013.

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,

 

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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, 2012 for additional risks related to the Company’s business.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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 expense or income in the Consolidated Statements of Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and does not impact operating cash flows on the cash flow statement. See Note 7 for the detail of the fair value of the following derivatives.

Commodity Derivative Contracts: At September 30, 2013, the Company had the following open commodity derivative contracts to manage price risk on a portion of its natural gas production whereby the Company receives the fixed price and pays the variable price. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties.

 

Type

Commodity Reference Price

Remaining Contract Period

Volume - MMBTU/Day

Average Price/MMBTU

Fair Value - September 30, 2013

Asset

(Amounts in 000’s)

Swap

NYMEX

Oct-13

390,000

$

3.54

$

523

 

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The following table summarizes the pre-tax realized and unrealized gains and (losses) the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the periods ended September 30, 2013 and 2012:

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
Natural Gas Commodity Derivatives:		2013				2012				2013				2012
		(Amounts in 000’s)
Realized (loss) gain on commodity derivatives(1)		$	(1,310	)		$	83,433			$	(21,074	)		$	260,239
Unrealized gain (loss) on commodity derivatives(1)			3,384				(93,329	)			523				(183,139	)
Total gain (loss) on commodity derivatives		$	2,074			$	(9,896	)		$	(20,551	)		$	77,100

 

(1)	Included in gain (loss) 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 September 30, 2013. There were no changes in the Company’s internal control over financial reporting during the nine months ended September 30, 2013 that have materially affected or are reasonably likely to affect, the Company’s internal control over financial reporting.

 

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PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Company is currently involved in various routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, the Company believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Company’s financial position, or results of operations.

ITEM 1A. RISK FACTORS

There have been no material changes with respect to the risk factors disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2012.

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.

 

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ITEM 6. EXHIBITS

(a) Exhibits

 

3.1		Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
3.2		By-Laws of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
3.3		Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005.)
4.1		Specimen Common Share Certificate — (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
10.1		Purchase and Sale Agreement dated October 18, 2013 between UPL Three Rivers Holdings, LLC and Axia Energy, LLC (incorporated by reference to Exhibit 1.1 of the Company’s Report on Form 8K filed on October 24, 2013).
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.

 

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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.

 

Date: November 1, 2013

 

Date: November 1, 2013

 

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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.)
10.1		Purchase and Sale Agreement dated October 18, 2013 between UPL Three Rivers Holdings, LLC and Axia Energy, LLC (incorporated by reference to Exhibit 1.1 of the Company’s Report on Form 8K filed on October 24, 2013).
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.

 

32