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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, 2014

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, 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 21, 2014 was 153,210,602.

 

 

 

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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			19
ITEM 3.		Quantitative and Qualitative Disclosures About Market Risk			32
ITEM 4.		Controls and Procedures			33
PART II — OTHER INFORMATION
ITEM 1.		Legal Proceedings			34
ITEM 1A.		Risk Factors			34
ITEM 2.		Unregistered Sales of Equity Securities and Use of Proceeds			34
ITEM 3.		Defaults upon Senior Securities			34
ITEM 4.		Mine Safety Disclosures			34
ITEM 5.		Other Information			34
ITEM 6.		Exhibits			35
		Signatures			36
		Exhibit Index			37

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PART I — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF INCOME

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
		2014				2013				2014				2013
		(Unaudited)
		(Amounts in thousands, except per share data)
Revenues:
Natural gas sales		$	211,853			$	191,453			$	711,965			$	628,438
Oil sales			76,755				29,752				199,005				79,769
Total operating revenues			288,608				221,205				910,970				708,207
Expenses:
Lease operating expenses			23,392				16,213				67,363				52,544
Liquids gathering system operating lease expense			5,076				5,000				15,229				15,000
Production taxes			23,729				18,078				74,254				54,640
Gathering fees			14,916				12,682				41,073				38,400
Transportation charges			20,034				20,955				57,882				61,913
Depletion, depreciation and amortization			76,289				59,401				204,810				180,993
General and administrative			6,233				4,060				14,736				15,897
Total operating expenses			169,669				136,389				475,347				419,387
Operating income			118,939				84,816				435,623				288,820
Other income (expense), net:
Interest expense			(29,599	)			(25,174	)			(83,960	)			(76,176	)
Gain (loss) on commodity derivatives			32,052				2,074				(28,323	)			(20,551	)
Deferred gain on sale of liquids gathering system			2,638				2,638				7,915				7,914
Other (expense) income, net			(56	)			(63	)			(54	)			(50	)
Total other income (expense), net			5,035				(20,525	)			(104,422	)			(88,863	)
Income before income tax (benefit) provision			123,974				64,291				331,201				199,957
Income tax (benefit) provision			(1,383	)			381				(1,924	)			3,240
Net income		$	125,357			$	63,910			$	333,125			$	196,717
Net income per common share — basic		$	0.82			$	0.42			$	2.18			$	1.29
Net income per common share — fully diluted		$	0.81			$	0.41			$	2.15			$	1.27
Weighted average common shares outstanding — basic			153,213				152,976				153,145				152,957
Weighted average common shares outstanding — fully diluted			154,859				154,512				154,771				154,366

See accompanying notes to consolidated financial statements.

 

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ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS

 

		September 30, 2014				December 31, 2013
		(Unaudited)
		(Amounts in thousands of U.S. dollars, except share data)
ASSETS
Current Assets:
Cash and cash equivalents		$	1,398			$	10,664
Restricted cash			117				119
Oil and gas revenue receivable			96,080				84,095
Joint interest billing and other receivables			19,456				17,725
Derivative assets			2,859				1,415
Other current assets			16,967				14,613
Total current assets			136,877				128,631
Oil and gas properties, net, using the full cost method of accounting:
Proven			3,420,119				2,008,538
Unproven properties not being amortized			385,843				413,073
Property, plant and equipment, net			32,575				216,909
Deferred income taxes			6				6
Deferred financing costs and other			28,507				18,162
Total assets		$	4,003,927			$	2,785,319
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	75,806			$	54,806
Accrued liabilities			80,412				79,811
Current portion of long-term debt			100,000				—
Production taxes payable			46,227				40,538
Interest payable			18,052				31,865
Derivative liabilities			2,116				27,291
Capital cost accrual			51,844				173,165
Total current liabilities			374,457				407,476
Long-term debt			3,326,000				2,470,000
Deferred gain on sale of liquids gathering system			139,486				147,401
Other long-term obligations			158,786				91,932
Commitments and contingencies
Shareholders’ equity:
Common stock — no par value; authorized — unlimited; issued and outstanding — 153,206,710 and 152,990,123 at September 30, 2014 and December 31, 2013, respectively			493,086				487,273
Treasury stock			(277	)			(1,961	)
Retained loss			(487,611	)			(816,802	)
Total shareholders’ equity (deficit)			5,198				(331,490	)
Total liabilities and shareholders’ equity		$	4,003,927			$	2,785,319

See accompanying notes to consolidated financial statements.

 

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ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		Nine Months Ended September 30,
		2014				2013
		(Unaudited)
		(Amounts in thousands of U.S. dollars)
Cash provided by (used in):
Operating activities:
Net income for the period		$	333,125			$	196,717
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization			204,810				180,993
Unrealized gain on commodity derivatives			(26,620	)			(523	)
Deferred gain on sale of liquids gathering system			(7,915	)			(7,914	)
Stock compensation			3,500				6,625
Other			3,204				1,678
Net changes in operating assets and liabilities:
Restricted cash			2				2
Accounts receivable			(18,230	)			22,314
Other current assets			(5,871	)			510
Accounts payable			26,205				(23,292	)
Accrued liabilities			(11,897	)			(22,610	)
Production taxes payable			5,757				(9,521	)
Interest payable			(13,813	)			(21,525	)
Other long-term obligations			17,401				12,745
Current taxes payable/receivable			5,504				(9,128	)
Net cash provided by operating activities			515,162				327,071
Investing Activities:
Acquisition of oil and gas properties, net of divestitures			(891,075	)			—
Oil and gas property expenditures			(441,798	)			(283,621	)
Gathering system expenditures			(6,842	)			(5,137	)
Change in capital cost accrual			(120,639	)			(64,451	)
Proceeds from sale of oil and gas properties			—				(129	)
Inventory			815				617
Purchase of capital assets			(5,327	)			(415	)
Net cash used in investing activities			(1,464,866	)			(353,136	)
Financing activities:
Borrowings on long-term debt			833,000				653,000
Payments on long-term debt			(727,000	)			(630,000	)
Proceeds from issuance of Senior Notes			850,000				—
Deferred financing costs			(13,317	)			—
Repurchased shares/net share settlements			(3,015	)			(5,324	)
Proceeds from exercise of options			770				—
Net cash provided by financing activities			940,438				17,676
(Decrease) in cash during the period			(9,266	)			(8,389	)
Cash and cash equivalents, beginning of period			10,664				12,921
Cash and cash equivalents, end of period		$	1,398			$	4,532
SUPPLEMENTAL INFORMATION:
Non-cash investing activities — oil and gas properties		$	20,000				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 Yukon, Canada. The Company’s principal business activities are developing its long-life natural gas reserves in the Green River Basin of Wyoming — the Pinedale and Jonah fields, its oil reserves in the Uinta Basin in Utah and its natural gas reserves in the Appalachian Basin of Pennsylvania.

1. SIGNIFICANT ACCOUNTING POLICIES:

The accompanying financial statements, other than the balance sheet data as of December 31, 2013, are unaudited and were prepared from the Company’s records, but do not include all disclosures required by U.S. Generally Accepted Accounting Principles (“GAAP”). Balance sheet data as of December 31, 2013 was derived from the Company’s audited financial statements. The Company’s management believes that these financial statements include all adjustments necessary for a fair presentation of the Company’s financial position and results of operations. All adjustments are of a normal and recurring nature unless specifically noted. The Company prepared these statements on a basis consistent with the Company’s annual audited statements and Regulation S-X. Regulation S-X allows the Company to omit some of the footnote and policy disclosures required by generally accepted accounting principles and normally included in annual reports on Form 10-K. You should read these interim financial statements together with the financial statements, summary of significant accounting policies and notes to the Company’s most recent annual report on Form 10-K.

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

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

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

(c) Property, Plant and Equipment: Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. Previously, gathering system expenditures were recorded at cost and depreciated separately from proven oil and gas properties using the straight-line method due to the expectation that they would be used to transport production from probable and possible reserves, as well as from third parties. However, subsequent to the SWEPI Transaction (See Note 8), the Company’s remaining gathering systems are expected to only be used to transport the Company’s proved volumes and as a result, $91.8 million has been transferred to proven oil and gas properties.

(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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Activities — Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

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

Under the full cost method, costs of unevaluated properties and major development projects expected to require significant future costs may be excluded from capitalized costs being amortized. The Company excludes significant costs until proved reserves are found or until it is determined that the costs are impaired. Excluded costs, if any, are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized.

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10%, plus the lower of cost or market value of unproved properties, less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower depletion, depreciation and amortization (“DD&A”) rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not incur a ceiling test write-down for the nine months ended September 30, 2014 or 2013.

(e) Derivative Instruments and Hedging Activities: The Company follows FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability in the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Income as an unrealized gain or loss on commodity derivatives. The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 6).

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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

 

		Three Months Ended								Nine Months Ended
		September 30, 2014				September 30, 2013				September 30, 2014				September 30, 2013
		(Share amounts in 000’s)
Net income		$	125,357			$	63,910			$	333,125			$	196,717
Weighted average common shares outstanding — basic			153,213				152,976				153,145				152,957
Effect of dilutive instruments			1,646				1,536				1,626				1,409
Weighted average common shares outstanding — fully diluted			154,859				154,512				154,771				154,366
Net income per common share — basic		$	0.82			$	0.42			$	2.18			$	1.29
Net income per common share — fully diluted		$	0.81			$	0.41			$	2.15			$	1.27
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			1,295				1,340				1,747				1,353

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

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

(j) Fair Value Accounting: The Company follows FASB ASC Topic 820, Fair Value Measurements and Disclosures (“FASB ASC 820”), which defines fair value, establishes a framework for measuring fair value under GAAP, and expands disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. See Note 7 for additional information.

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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

2. OIL AND GAS PROPERTIES AND EQUIPMENT:

 

		September 30, 2014				December 31, 2013
Proven Properties:
Acquisition, equipment, exploration, drilling and environmental costs		$	9,429,430			$	7,817,374
Less: Accumulated depletion, depreciation and amortization(1)			(6,009,311	)			(5,808,836	)
			3,420,119				2,008,538
Unproven Properties:
Acquisition and exploration costs not being amortized(1)			385,843				413,073
Net capitalized costs — oil and gas properties		$	3,805,962			$	2,421,611

 

(1)

For the nine months ended September 30, 2014 and 2013, total interest on outstanding debt was $100.0 million and $76.7 million, respectively, of which, $16.1 million and $0.5 million, respectively, was capitalized on the cost of unevaluated oil and natural gas properties and on work in process relating to gathering systems.

3. DEBT AND OTHER LONG-TERM OBLIGATIONS:

 

		September 30, 2014				December 31, 2013
Short-term debt:
Senior Notes due March 2015		$	100,000			$	—
Long-term debt and other obligations:
Bank indebtedness			566,000				460,000
Senior Notes			2,760,000				2,010,000
Other long-term obligations			158,786				91,932
		$	3,584,786			$	2,561,932

Ultra Resources, Inc. Bank Indebtedness —

The Company’s subsidiary, Ultra Resources, Inc. (“Ultra Resources”, or “Borrower”), is a party to a senior revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”). The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the Borrower and with the consent of lenders who are willing to increase their loan commitments, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016. With majority (over 50%) lender consent, the term of the consenting lenders’ commitments may be extended for up to two successive one-year periods at the Borrower’s request. At September 30, 2014, the Company had $566.0 million in outstanding borrowings and $434.0 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 100 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the Borrower’s consolidated leverage ratio (200 basis points per annum as of September 30, 2014). 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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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

Ultra Resources, Inc. Senior Notes —

Ultra Resources also has outstanding $1.56 billion in principal amount of Senior Notes. Ultra Resources’ Senior Notes rank pari passu with the Company’s Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. The Senior Notes are pre-payable in whole or in part at any time following the payment of a make-whole premium and are subject to representations, warranties, covenants and events of default similar to those in the Credit Facility. At September 30, 2014, the Company was in compliance with all of its debt covenants under the Senior Notes.

Ultra Petroleum Corp. Senior Notes —

Senior Notes due 2024: On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”). The 2024 Notes are general, unsecured senior obligations of the Company and mature on October 1, 2024. The 2024 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2024 Notes are not guaranteed by the Company’s subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. On and after October 1, 2019, the Company may redeem all or, from time to time, a part of the 2024 Notes at the following prices expressed as a percentage of principal amount of the 2024 Notes: (2019 — 103.063%; 2020 — 102.042%; 2021 — 101.021%; and 2022 and thereafter — 100.000%). The 2024 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the 2024 Notes contain events of default customary for a senior note financing. At September 30, 2014, the Company was in compliance with all of its debt covenants under the 2024 Notes.

Senior Notes due 2018: On December 12, 2013, the Company issued $450.0 million of 5.75% Senior Notes due 2018 (“2018 Notes”). The 2018 Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The 2018 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2018 Notes are not guaranteed by the Company’s subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. On and after December 15, 2015, the Company may redeem all or, from time to time, a part of the 2018 Notes at the following prices expressed as a percentage of principal amount of the 2018 Notes: (2015 — 102.875%; 2016 — 101.438%; and 2017 and thereafter — 100.000%). The 2018 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the 2018 Notes contain events of default customary for a senior note financing. At September 30, 2014, the Company was in compliance with all of its debt covenants under the 2018 Notes.

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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

4. SHARE BASED COMPENSATION:

Valuation and Expense Information

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2014				2013				2014				2013
Total cost of share-based payment plans		$	3,896			$	601			$	5,635			$	9,458
Amounts capitalized in oil and gas properties and equipment		$	1,425			$	37			$	2,135			$	2,833
Amounts charged against income, before income tax benefit (provision)		$	2,471			$	564			$	3,500			$	6,625
Amount of related income tax (expense) benefit recognized in income before valuation allowance		$	1,033			$	232			$	1,463			$	2,728

Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the nine months ended September 30, 2014 and the year ended December 31, 2013:

 

		Number of Options (000’s)				Weighted Average Exercise Price (US$)
Balance, December 31, 2012			1,357			$	16.97				to			$	98.87
Forfeited			(110	)		$	25.68				to			$	75.18
Exercised			(1	)		$	16.97				to			$	16.97
Balance, December 31, 2013			1,246			$	16.97				to			$	98.87
Forfeited			(246	)		$	40.34				to			$	75.18
Exercised			(44	)		$	16.97				to			$	25.68
Balance, September 30, 2014			956			$	25.68				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 2012, 2013 and 2014, the Compensation Committee (the “Committee”) approved an award consisting of performance-based restricted stock units to be awarded to each participant.

For each LTIP award, the Committee establishes performance measures at the beginning of each three-year performance period. Under each LTIP, the Committee also establishes a percentage of base salary for each participant which is multiplied by the participant’s base salary at the beginning of the performance period and individual performance level to derive a Long Term Incentive Value as a “target” value. This “target” value corresponds to the number of shares of the Company’s common stock the participant is eligible to receive if the participant is employed by the Company through the date the award vests and if the target level for all performance measures is met. In addition, each participant is assigned threshold and maximum award levels in the event the Company’s actual performance is below or above the target levels. For the LTIP awards in 2012,

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth. For the LTIP awards in 2013 and 2014, the Committee established the following performance measures: return on capital employed, debt level, reserve replacement ratio, and total shareholder return (officers only).

For the nine months ended September 30, 2014, the Company recognized $4.7 million in pre-tax compensation expense related to the 2012, 2013 and 2014 LTIP awards of restricted stock units as compared to $4.5 million during the nine months ended September 30, 2013 related to the 2011, 2012 and 2013 LTIP awards of restricted stock units. The amounts recognized during the nine months ended September 30, 2014 assume that maximum performance objectives are attained under each of the LTIP plans. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at September 30, 2014, for each of the three year performance periods is expected to be approximately $10.3 million, $12.2 million, and $12.7 million related to the 2012, 2013 and 2014 LTIP awards of restricted stock units, respectively. The 2011 LTIP award of restricted stock units was paid in shares of the Company’s stock to employees during the first quarter of 2014 and totaled $8.4 million (106,437 net shares).

5. INCOME TAXES:

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

The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of September 30, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.

6. DERIVATIVE FINANCIAL INSTRUMENTS:

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

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 Consolidated Balance Sheets as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments.

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the Consolidated Balance Sheets and the associated unrealized gains and losses are recorded as current income or expense in the Consolidated Statements of Income. Unrealized gains or losses on

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

 

Natural Gas:

Type

Commodity Reference Price

Remaining Contract Period

Volume - MMBTU/ Day

Average Price/ MMBTU

Fair Value - September 30, 2014

Asset/(Liability)

Fixed price swap

NYMEX-Henry Hub

Oct-14

480,000

$

3.90

$

(1,321

)

Fixed price swap

NYMEX-Henry Hub

Nov - Dec 2014

85,000

$

4.35

$

967

Crude Oil:

Type

Commodity Reference Price

Remaining Contract Period

Volume - Bbls/Day

Average Price/Bbl

Fair Value - September 30, 2014

Asset

Fixed price swap

NYMEX-WTI

Oct - Dec 2014

4,000

$

93.19

$

1,097

Subsequent to September 30, 2014 and through October 30, 2014, the Company has entered into 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:

 

Type

Commodity Reference Price

Remaining Contract Period

Volume - MMBTU/ Day

Average Price/ MMBTU

Fixed price swap

NYMEX-Henry Hub

Apr - Oct 2015

20,000

$

3.88

The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Consolidated Statements of Income for the periods ended September 30, 2014 and 2013:

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
Commodity Derivatives:		2014				2013				2014				2013
Realized loss on commodity derivatives-natural gas(1)		$	(7,219	)		$	(1,310	)		$	(48,062	)		$	(21,074	)
Realized loss on commodity derivatives-crude oil(1)			(1,479	)			—				(6,881	)			—
Unrealized gain on commodity derivatives(1)			40,750				3,384				26,620				523
Total gain (loss) on commodity derivatives		$	32,052			$	2,074			$	(28,323	)		$	(20,551	)

 

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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

7. FAIR VALUE MEASUREMENTS:

As required by FASB ASC 820, the Company defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date and establishes a three level hierarchy for measuring fair value. Fair value measurements are classified and disclosed in one of the following categories:

 

Level 1:		Quoted prices (unadjusted) in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
Level 2:		Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.
Level 3:		Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

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

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

 

		Level 1				Level 2				Level 3				Total
Current derivative asset		$	—			$	2,859			$	—			$	2,859
Current derivative liability		$	—			$	2,116			$	—			$	2,116

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

Fair Value of Financial Instruments

The estimated fair value of financial instruments is the estimated amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the Consolidated Balance Sheets for cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. The Company uses available market data and

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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, 2014								December 31, 2013
		Carrying Amount				Estimated Fair Value				Carrying Amount				Estimated Fair Value
5.45% Notes due March 2015, issued 2008		$	100,000			$	101,604			$	100,000			$	105,913
7.31% Notes due March 2016, issued 2009			62,000				66,118				62,000				70,228
4.98% Notes due January 2017, issued 2010			116,000				120,363				116,000				126,342
5.92% Notes due March 2018, issued 2008			200,000				214,234				200,000				226,127
5.75% Notes due December 2018, issued 2013			450,000				460,511				450,000				466,946
7.77% Notes due March 2019, issued 2009			173,000				198,868				173,000				211,877
5.50% Notes due January 2020, issued 2010			207,000				217,388				207,000				229,068
4.51% Notes due October 2020, issued 2010			315,000				310,157				315,000				323,732
5.60% Notes due January 2022, issued 2010			87,000				91,048				87,000				95,736
4.66% Notes due October 2022, issued 2010			35,000				34,055				35,000				35,494
6.125% Notes due October 2024, issued 2014			850,000				814,958				—				—
5.85% Notes due January 2025, issued 2010			90,000				94,835				90,000				99,142
4.91% Notes due October 2025, issued 2010			175,000				169,089				175,000				175,744
Credit Facility due October 2016			566,000				566,000				460,000				460,000
		$	3,426,000			$	3,459,228			$	2,470,000			$	2,626,349

8. COMPLETION OF ACQUISITION AND DISPOSITION OF ASSETS:

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

On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”) in order to finance a portion of the purchase price of the SWEPI Transaction. The remainder of the cash payment was funded through borrowings under the Company’s senior revolving credit facility. See Note 3.

The costs related to the issuance of the 2024 Notes of $13.2 million are included with deferred financing costs and other on the Consolidated Balance Sheets and will be amortized over the term of the 2024 Notes. Additionally, the Company incurred $0.5 million of costs associated with the acquisition, which are included with general and administrative expenses in the Consolidated Statements of Income.

The SWEPI Properties that we acquired consist primarily of 19,600 net mineral acres in Wyoming and associated oil and gas production and wells and the Pennsylvania Properties that we sold consist primarily of 155,000 net acres in Pennsylvania and associated oil and gas production and wells. The transaction is a strategic

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

repositioning of the Company’s portfolio, and the Company expects the acquisition will lead to improved returns, increased reserves, increased percentage of sales in higher value markets, increased operatorship and increased control of capital allocation.

The transaction was accounted for as a business combination and after customary effective-date adjustments and closing adjustments, the adjusted cash payment on the closing date of September 25, 2014 was $890.8 million and is subject to further post-closing adjustments. The adjusted cash payment was allocated to assets and liabilities based upon fair values at the closing date as follows:

 

Adjusted cash payment		$	890,785
Assets:
Joint interest billing and other receivables — SWEPI Properties			(4,182	)
Other current assets:
Acquired condensate inventory — SWEPI Properties			819
Acquired yard inventory — SWEPI Properties			3,515
Subtotal — Other current assets			4,334
Proven oil and gas properties			1,033,960
Property, plant and equipment:
Divested gathering system — Pennsylvania Properties			(98,580	)
Acquired other fixed assets — SWEPI Properties			869
Divested other fixed assets — Pennsylvania Properties			(50	)
Subtotal — Property, plant and equipment			(97,761	)
Total assets acquired, net of divested assets		$	936,351
Liabilities:
Current liabilities — Pennsylvania Properties			8,657
Current liabilities — SWEPI Properties			(601	)
Subtotal — Current liabilities		$	8,056
Other long-term obligations:
Acquired asset retirement obligations — SWEPI Properties			53,270
Divested asset retirement obligations — Pennsylvania Properties			(15,760	)
Subtotal — Other long-term obligations			37,510
Total liabilities, net		$	45,566

Contingent consideration

As part of the SWEPI Transaction, the Company agreed to attempt to extend or renew certain expiring leases in Pennsylvania at its expense.

Pro Forma Operating Results

The following pro forma combined results for the three and nine months ended September 30, 2014 and 2013 reflect the consolidated results of operations of the Company as if the SWEPI Transaction and related financing had occurred on January 1, 2013. The pro forma information includes adjustments primarily for revenues and expenses from the acquired SWEPI Properties less revenues and expenses from the divested Pennsylvania Properties as well as depreciation, depletion, amortization and accretion, and interest expense associated with the financing related to the SWEPI Transaction.

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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

 

•

The acquisition and divestiture of oil and gas properties in the SWEPI Transaction completed on September 25, 2014

 

•

Issuance of $850.0 million of 6.125% senior notes due 2024 to finance a portion of the SWEPI Transaction, and the related adjustments to interest expense

 

•

Increase in borrowings under the Credit Agreement to finance a portion of the SWEPI Transaction, and the related adjustments to interest expense

 

•

Includes transportation charges of $24.4 million and $26.3 million for the three months ended September 30, 2014 and 2013, respectively, and $74.6 million and $86.9 million for the nine months ended September 30, 2014 and 2013, respectively, incurred with respect to operation of the properties acquired in the SWEPI Transaction that will not be incurred by the Company.

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

 

		Three Months Ended September 30,								Nine Months Ended September 30,
		2014				2013				2014				2013
Revenues		$	352,236			$	279,240			$	1,102,487			$	886,347
Net income		$	127,535			$	47,925			$	319,702			$	139,620

Post-Acquisition Operating Results

The amounts of revenues and earnings included in the Company’s Consolidated Statements of Income for the three and nine months ended September 30, 2014 related to the SWEPI Transaction represent activity from September 25, 2014 through September 30, 2014 and are immaterial to the Company’s reported results.

9. 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.

10. SUBSEQUENT EVENTS:

The Company has evaluated the period subsequent to September 30, 2014 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events arose that should be disclosed in order to keep the financial statements from being misleading.

 

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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 — its oil reserves in the Uinta Basin in Utah and its natural gas reserves 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. The Company continues to focus on improving its drilling and production results through gaining efficiencies with the use of advanced technologies, detailed technical analysis of its properties and leveraging its experience into improved operational efficiencies. Inflation has not had, nor is it expected to have in the foreseeable future, a material impact on the Company’s results of operations.

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

The prices of oil and natural gas are critical factors to the Company’s business. The prices of oil and natural gas have historically been volatile, and this 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 and oil. (See Note 6).

During the quarter ended September 30, 2014, the average price realization for the Company’s natural gas was $3.59 per Mcf, including realized gains and losses on commodity derivatives compared with $3.41 per Mcf during the quarter ended September 30, 2013. The Company’s average price realization for natural gas was $3.72 per Mcf, excluding the realized gains and losses on commodity derivatives. This compares with $3.44 per Mcf during the third quarter of 2013.

During the quarter ended September 30, 2014, the average price realization for the Company’s oil was $81.18 per barrel, including realized gains and losses on commodity derivatives compared with $100.06 per barrel during the quarter ended September 30, 2013. The Company’s average price realization for oil was $82.77 per barrel, excluding the realized gains and losses on commodity derivatives. This compares with $100.06 per barrel during the third quarter of 2013.

Recent Transaction

On September 25, 2014, a wholly owned subsidiary of Ultra Petroleum Corp. completed the acquisition of all producing and non-producing properties (including gathering systems) in the Pinedale field in Sublette County, Wyoming (the “SWEPI Properties”) from SWEPI, LP, an affiliate of Royal Dutch Shell, plc in exchange for certain of the Company’s producing and non-producing properties (including gathering systems) in Pennsylvania (the “Pennsylvania Properties”) and a cash payment of $925.0 million (the “SWEPI Transaction”) pursuant to a Purchase and Sale Agreement dated August 13, 2014. The effective date of the transaction is April 1, 2014. See Note 8.

 

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

On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”) in order to finance a portion of the purchase price of the SWEPI Transaction. The remainder of the cash payment was funded through borrowings under the Company’s senior revolving credit facility. See Note 3.

Critical Accounting Policies

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

Derivative Instruments and Hedging Activities. The Company follows Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Income as an unrealized gain or loss on commodity derivatives.

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

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, 2014 is summarized in the following table based on the inputs used to determine fair value:

 

		Level 1 (a)				Level 2 (b)				Level 3 (c)				Total
		(Amounts in 000’s)
Current derivative asset		$	—			$	2,859			$	—			$	2,859
Current derivative liability		$	—			$	2,116			$	—			$	2,116

 

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(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 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, amounts and timing of settlements, the credit-adjusted, risk-free rate to be used, inflation rates, and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through depletion, depreciation and amortization (“DD&A”). As a full cost company, settlements for asset retirement obligations for abandonment are adjusted to the full cost pool. The asset retirement obligation is included within other long-term obligations in the accompanying Consolidated Balance Sheets.

Share-Based Payment Arrangements. The Company applies FASB ASC Topic 718, Compensation – Stock Compensation (“FASB ASC 718”), which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized for the nine months ended September 30, 2014 and 2013 was $3.5 million and $6.6 million, respectively. See Note 4 for additional information.

Property, Plant and Equipment. Capital assets are recorded at cost and depreciated using the declining-balance method based on their respective useful life. Previously, gathering system expenditures were recorded at cost and depreciated separately from proven oil and gas properties using the straight-line method due to the expectation that they would be used to transport production from probable and possible reserves, as well as from third parties. However, subsequent to the SWEPI Transaction (See Note 8), the Company’s remaining gathering systems are expected to only be used to transport the Company’s proved volumes and as a result, $91.8 million has been transferred to proven oil and gas properties.

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

 

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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, 2014 or 2013.

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

Revenue Recognition. The Company generally sells natural gas and condensate under both long-term and short-term agreements at prevailing market prices and under multi-year contracts that provide for a fixed price of oil and natural gas. The Company recognizes revenues when the oil and natural gas is delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectability is reasonably assured. The Company accounts for oil and natural gas sales using the “entitlements method.” Under the entitlements method, revenue is recorded based upon the Company’s ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue.

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.

The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of September 30, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.

 

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

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

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.

 

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RESULTS OF OPERATIONS:

 

		For the Three Months Ended September 30,								% Variance				For the Nine Months Ended September 30,								% Variance
		2014				2013				F/(U)				2014				2013				F/(U)
		(Amounts in thousands, except per unit data)
Production, Commodity Prices and Revenues:
Production:
Natural gas (Mcf)			56,984				55,718				2	%			164,269				170,070				-3	%
Crude oil and condensate (Bbls)			927				297				212	%			2,344				865				171	%
Total production (Mcfe)			62,548				57,502				9	%			178,334				175,258				2	%
Commodity Prices:
Natural gas ($/Mcf, including realized hedges)		$	3.59			$	3.41				5	%		$	4.04			$	3.57				13	%
Natural gas ($/Mcf, excluding hedges)		$	3.72			$	3.44				8	%		$	4.33			$	3.70				17	%
Oil and condensate ($/Bbl, incl realized hedges)		$	81.18			$	100.06				-19	%		$	81.96			$	92.25				-11	%
Oil and condensate ($/Bbl, excl realized hedges)		$	82.77			$	100.06				-17	%		$	84.89			$	92.25				-8	%
Revenues:
Natural gas sales		$	211,853			$	191,453				11	%		$	711,965			$	628,438				13	%
Oil sales			76,755				29,752				158	%			199,005				79,769				149	%
Total operating revenues		$	288,608			$	221,205				30	%		$	910,970			$	708,207				29	%
Derivatives:
Realized (loss) on commodity derviatives-natural gas		$	(7,219	)		$	(1,310	)			-451	%		$	(48,062	)		$	(21,074	)			-128	%
Realized (loss) on commodity derviatives-crude oil			(1,479	)			—				n/a				(6,881	)			—				n/a
Unrealized gain on commodity derivatives			40,750				3,384				1104	%			26,620				523				4990	%
Total gain (loss) on commodity derivatives		$	32,052			$	2,074				1445	%		$	(28,323	)		$	(20,551	)			-38	%
Operating Costs and Expenses:
Lease operating expenses		$	23,392			$	16,213				-44	%		$	67,363			$	52,544				-28	%
Liquids gathering system operating lease expense		$	5,076			$	5,000				-2	%		$	15,229			$	15,000				-2	%
Production taxes		$	23,729			$	18,078				-31	%		$	74,254			$	54,640				-36	%
Gathering fees		$	14,916			$	12,682				-18	%		$	41,073			$	38,400				-7	%
Transportation charges		$	20,034			$	20,955				4	%		$	57,882			$	61,913				7	%
Depletion, depreciation and amortization		$	76,289			$	59,401				-28	%		$	204,810			$	180,993				-13	%
General and administrative expenses		$	6,233			$	4,060				-54	%		$	14,736			$	15,897				7	%
Per Unit Costs and Expenses ($/Mcfe):
Lease operating expenses		$	0.37			$	0.28				-32	%		$	0.38			$	0.30				-27	%
Liquids gathering system operating lease expense		$	0.08			$	0.09				11	%		$	0.09			$	0.09				0	%
Production taxes		$	0.38			$	0.31				-23	%		$	0.42			$	0.31				-35	%
Gathering fees		$	0.24			$	0.22				-9	%		$	0.23			$	0.22				-5	%
Transportation charges		$	0.32			$	0.36				11	%		$	0.32			$	0.35				9	%
Depletion, depreciation and amortization		$	1.22			$	1.03				-18	%		$	1.15			$	1.03				-12	%
General and administrative expenses		$	0.10			$	0.07				-43	%		$	0.08			$	0.09				11	%

 

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Quarter Ended September 30, 2014 vs. Quarter Ended September 30, 2013

Production, Commodity Derivatives and Revenues:

Production. During the quarter ended September 30, 2014, total production increased on a gas equivalent basis to 62.5 Bcfe compared to 57.5 Bcfe for the same quarter in 2013. The increase is primarily attributable to the acquisition of the Uinta Basin properties in December 2013 and our drilling program, offset by expected production declines. Additionally, on an Mcfe basis, oil production increased from 3.1% of total production during the third quarter of 2013 to 8.9% of total production during the third quarter of 2014, primarily as a result of the acquisition of the Uinta Basin properties.

Commodity Prices — Natural Gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 5% to $3.59 per Mcf in the third quarter of 2014 as compared to $3.41 per Mcf for the same quarter of 2013. During the three months ended September 30, 2014, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $3.72 per Mcf as compared to $3.44 per Mcf for the same period in 2013.

Commodity Prices — Oil. During the quarter ended September 30, 2014, the average price realization for the Company’s oil was $81.18 per barrel, including realized gains and losses on commodity derivatives compared with $100.06 per barrel during the quarter ended September 30, 2013. The Company’s average price realization for oil was $82.77 per barrel, excluding the realized gains and losses on commodity derivatives. This compares with $100.06 per barrel during the third quarter of 2013.

Revenues. Oil production from the recently acquired assets in Utah along with the increase in average natural gas prices, excluding the gains and losses on commodity derivatives, resulted in revenues increasing to $288.6 million for the quarter ended September 30, 2014 as compared to $221.2 million for the same period in 2013.

Operating Costs and Expenses:

Lease Operating Expense. Lease operating expense (“LOE”) increased to $23.4 million during the third quarter of 2014 compared to $16.2 million during the same period in 2013 largely related to the recently acquired assets in Utah. On a unit of production basis, LOE costs increased to $0.37 per Mcfe during the third quarter of 2014 compared to $0.28 per Mcfe during the same period in 2013 as a result of increased costs associated with the Utah acquisition during the period ended September 30, 2014.

Operating Lease Expense. During December 2012, the Company sold a system of liquids gathering pipelines and central gathering facilities (the “LGS”) and certain associated real property rights in the Pinedale Anticline in Wyoming. The Company entered into a long-term, triple net lease agreement with the buyer relating to the use of the LGS (the “Lease Agreement”). The Lease Agreement provides for an initial term of 15 years, and annual rent for the initial term under the Lease Agreement is $20.0 million (as adjusted annually for changes based on the consumer price index) and may increase if certain volume thresholds are exceeded. The Company’s sale leaseback transaction was treated as a “normal leaseback” under the provisions of FASB ASC Topic 840, Leases (“FASB ASC Topic 840”) and qualified for sales recognition. The lease is classified as an operating lease. For the three months ended September 30, 2014, the Company recognized operating lease expense associated with the Lease Agreement of $5.1 million, or $0.08 per Mcfe as compared to $5.0 million, or $0.09 per Mcfe for the same period in 2013.

Production Taxes. During the three months ended September 30, 2014, production taxes were $23.7 million compared to $18.1 million during the same period in 2013, or $0.38 per Mcfe compared to $0.31 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 8.2% of revenues for the quarter ended September 30, 2014 and 8.2% of revenues for the same period in 2013. The increase in per unit taxes is primarily attributable to increased natural gas prices, excluding the effects of commodity derivatives during the quarter ended September 30, 2014 as compared to the same period in 2013.

 

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Gathering Fees. Gathering fees increased to $14.9 million for the three months ended September 30, 2014 compared to $12.7 million during the same period in 2013 largely due to production increases in Wyoming. On a per unit basis, gathering fees increased to $0.24 per Mcfe for the three months ended September 30, 2014 as compared to $0.22 per Mcfe during the same period in 2013.

Transportation Charges. The Company incurred firm transportation charges totaling $20.0 million for the quarter ended September 30, 2014 as compared to $21.0 million for the same period in 2013 in association with Rockies Express Pipeline (“REX”) transportation charges. On a per unit basis, transportation charges decreased to $0.32 per Mcfe (on total company volumes) for the three months ended September 30, 2014 as compared to $0.36 per Mcfe (on total company volumes) for the same period in 2013 primarily as a result of increased production volumes.

Depletion, Depreciation and Amortization. DD&A expenses increased to $76.3 million during the three months ended September 30, 2014 from $59.4 million for the same period in 2013, attributable to a higher depletion rate primarily related to the Utah acquisition. On a unit of production basis, DD&A increased to $1.22 per Mcfe for the quarter ended September 30, 2014 from $1.03 per Mcfe for the quarter ended September 30, 2013.

General and Administrative Expenses. General and administrative expenses increased to $6.2 million for the quarter ended September 30, 2014 compared to $4.1 million for the same period in 2013 primarily related to increased headcount and related compensation. On a per unit basis, general and administrative expenses increased to $0.10 per Mcfe for the quarter ended September 30, 2014 compared to $0.07 per Mcfe for the quarter ended September 30, 2013.

Other Income and Expenses:

Interest Expense. Interest expense increased to $29.6 million during the quarter ended September 30, 2014 compared to $25.2 million during the same period in 2013 primarily as a result of higher average borrowings outstanding and partially offset by increased amounts of capitalized interest for the quarter ended September 30, 2014 as compared to the same period in 2013. (See Note 2).

Deferred Gain on Sale of Liquids Gathering System. During the quarters ended September 30, 2014 and 2013, the Company recognized $2.6 million in deferred gain on sale of the liquids gathering system relating to the sale of a system of pipelines and central gathering facilities and certain associated real property rights in the Pinedale Anticline in Wyoming during December 2012.

Commodity Derivatives:

Gain on Commodity Derivatives. During the quarter ended September 30, 2014, the Company recognized a gain of $32.1 million compared with a gain of $2.1 million during the same period in 2013 related to commodity derivatives. Of this total, the Company recognized $8.7 million of realized loss on commodity derivatives during the quarter ended September 30, 2014 compared with $1.3 million of realized loss on commodity derivatives during the three months ended September 30, 2013. The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts. This amount also includes an unrealized gain on commodity derivatives of $40.8 million during the quarter ended September 30, 2014 as compared to $3.4 million in unrealized gain on commodity derivatives during the quarter ended September 30, 2013. The unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract. See Note 6.

Income from Continuing Operations:

Pretax Income. The Company recognized income before income taxes of $124.0 million for the quarter ended September 30, 2014 compared with income before income taxes of $64.3 million for the same period in 2013. The increase in earnings is primarily due to increased revenues as a result of increased production during the three months ended September 30, 2014 as compared to the same period in 2013.

 

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Income Taxes. The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of September 30, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.

Net Income. For the three months ended September 30, 2014, the Company recognized net income of $125.4 million or $0.81 per diluted share as compared with net income of $63.9 million or $0.41 per diluted share for the same period in 2013. The increase is primarily due to increased revenues as a result of increased production during the three months ended September 30, 2014 as compared to the same period in 2013.

Nine Months Ended September 30, 2014 vs. Nine Months Ended September 30, 2013

Production, Commodity Derivatives and Revenues:

Production. During the nine months ended September 30, 2014, production increased on a gas equivalent basis to 178.3 Bcfe compared to 175.3 Bcfe for the same period in 2013 as a result of increased oil production during 2014 associated with the Utah acquisition and offset by decreased natural gas production in 2014 due to decreased capital spending during 2013. On an Mcfe basis, oil production increased from 3.0% of total production during the nine months ended September 30, 2013 to 7.9% of total production during the nine months ended September 30, 2014.

Commodity Prices — Natural Gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 13% to $4.04 per Mcf during the nine months ended September 30, 2014 as compared to $3.57 per Mcf during 2013. During the nine months ended September 30, 2014, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $4.33 per Mcf as compared to $3.70 per Mcf for the same period in 2013.

Commodity Prices — Oil. During the nine months ended September 30, 2014, the average price realization for the Company’s oil was $81.96 per barrel, including realized gains and losses on commodity derivatives compared with $92.25 per barrel during the nine months ended September 30, 2013. The Company’s average price realization for oil was $84.89 per barrel, excluding the realized gains and losses on commodity derivatives. This compares with $92.25 per barrel during the nine months ended September 30, 2013.

Revenues. Oil production from the recently acquired assets in Utah along with the increase in average natural gas prices, excluding gains and losses on commodity derivatives, partially offset by the decrease in natural gas production resulted in revenues increasing to $911.0 million for the nine months ended September 30, 2014 as compared to $708.2 million for the same period in 2013.

Operating Costs and Expenses:

Lease Operating Expense. LOE increased to $67.4 million during the nine months ended September 30, 2014 compared to $52.5 million during the same period in 2013 largely related to the recently acquired assets in Utah. On a unit of production basis, LOE costs increased to $0.38 per Mcfe during the nine months ended September 30, 2014 compared to $0.30 per Mcfe during the same period in 2013 as a result of increased costs related to the recently acquired assets in Utah.

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

 

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For the nine months ended September 30, 2014, the Company recognized operating lease expense associated with the Lease Agreement of $15.2 million, or $0.09 per Mcfe as compared to $15.0 million, or $0.09 per Mcfe for the same period in 2013.

Production Taxes. During the nine months ended September 30, 2014, production taxes were $74.3 million compared to $54.6 million during the same period in 2013, or $0.42 per Mcfe compared to $0.31 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 8.2% of revenues for the nine months ended September 30, 2014 and 7.7% of revenues for the same period in 2013. The increase in per unit taxes is primarily attributable to increased natural gas prices, excluding the effects of commodity derivatives, during the nine months ended September 30, 2014 as compared to the same period in 2013.

Gathering Fees. Gathering fees increased to $41.1 million for the nine months ended September 30, 2014 compared to $38.4 million during the same period in 2013 largely related to production increases in Wyoming. On a per unit basis, gathering fees increased slightly to $0.23 per Mcfe for the nine months ended September 30, 2014 as compared to $0.22 per Mcfe during the same period in 2013.

Transportation Charges. The Company incurred firm transportation charges totaling $57.9 million for the nine months ended September 30, 2014 as compared to $61.9 million for the same period in 2013 in association with REX transportation charges. Transportation charges decreased due to a refund during the second quarter of 2014 for over collection of tariffs related to fuel, loss and unaccounted-for-gas applicable to transport on REX’s system. On a per unit basis, transportation charges decreased to $0.32 per Mcfe (on total company volumes) for the nine months ended September 30, 2014 as compared to $0.35 per Mcfe (on total company volumes) for the same period in 2013.

Depletion, Depreciation and Amortization. DD&A expenses increased to $204.8 million during the nine months ended September 30, 2014 from $181.0 million for the same period in 2013, attributable to a higher depletion rate primarily related to the Utah acquisition. On a unit of production basis, DD&A increased to $1.15 per Mcfe for the nine months ended September 30, 2014 from $1.03 per Mcfe for the nine months ended September 30, 2013.

General and Administrative Expenses. General and administrative expenses decreased to $14.7 million for the nine months ended September 30, 2014 compared to $15.9 million for the same period in 2013 primarily due to decreased incentive compensation expense. On a per unit basis, general and administrative expenses decreased to $0.08 per Mcfe for the nine months ended September 30, 2014 compared to $0.09 per Mcfe for the nine months ended September 30, 2013.

Other Income and Expenses:

Interest Expense. Interest expense increased to $84.0 million during the nine months ended September 30, 2014 compared to $76.2 million during the same period in 2013 primarily as a result of higher average borrowings outstanding and partially offset by increased amounts of capitalized interest for the nine months ended September 30, 2014 as compared to the same period in 2013. (See Note 2).

Deferred Gain on Sale of Liquids Gathering System. During the nine months ended September 30, 2014 and 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.

Commodity Derivatives:

(Loss) on Commodity Derivatives. During the nine months ended September 30, 2014, the Company recognized a loss of $28.3 million compared with a loss of $20.6 million during the same period in 2013 related to commodity derivatives. Of this total, the Company recognized $54.9 million of realized loss on commodity

 

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derivatives during the nine months ended September 30, 2014 compared with $21.1 million of realized loss on commodity derivatives during nine months ended September 30, 2013. The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts. This amount also includes an unrealized gain on commodity derivatives of $26.6 million during the nine months ended September 30, 2014 as compared to $0.5 million in unrealized gain on commodity derivatives during the nine months ended September 30, 2013. The unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract. See Note 6.

Income from Continuing Operations:

Pretax Income. The Company recognized income before income taxes of $331.2 million for the nine months ended September 30, 2014 compared with income before income taxes of $200.0 million for the same period in 2013. The increase in earnings is largely due to increased revenues as a result of increased natural gas price realizations and increased oil production during the nine months ended September 30, 2014 as compared to the same period in 2013.

Income Taxes. The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of September 30, 2014. Some or all of this valuation allowance may be reversed in future periods against future income.

Net Income. For the nine months ended September 30, 2014, the Company recognized net income of $333.1 million or $2.15 per diluted share as compared with net income of $196.7 million or $1.27 per diluted share for the same period in 2013. The increase is largely due to increased revenues as a result of increased natural gas price realizations and increased oil production during the nine months ended September 30, 2014 as compared to the same period in 2013.

LIQUIDITY AND CAPITAL RESOURCES

During the nine month period ended September 30, 2014, the Company relied on cash provided by operations along with borrowings under the Credit Agreement (defined below) to finance its capital expenditures. In addition, the Company completed the issuance of $850.0 million of senior notes in September 2014 in order to finance a portion of the purchase price of the SWEPI Transaction (See Note 8).

For the nine month period ended September 30, 2014, total capital expenditures, excluding the SWEPI Transaction (See Note 8), were $448.6 million. During this period, the Company participated in 185 gross (134.9 net) wells that were drilled to total depth and cased.

At September 30, 2014, the Company reported a cash position of $1.4 million compared to $4.5 million at September 30, 2013. Working capital deficit at September 30, 2014 was $237.6 million compared to working capital deficit of $243.9 million at September 30, 2013. At September 30, 2014, the Company had $566.0 million in outstanding borrowings and $434.0 million of available borrowing capacity under the Credit Agreement. In addition, the Company had $2.86 billion outstanding in senior notes (See Note 3). Other long-term obligations of $158.8 million at September 30, 2014 were comprised of items payable in more than one year, primarily related to production taxes and asset retirement obligations.

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

Ultra Resources, Inc. Bank Indebtedness —

The Company’s subsidiary, Ultra Resources, Inc. (“Ultra Resources”, or “Borrower”), is a party to a senior revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. (the “Credit Agreement”).

 

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The Credit Agreement provides an initial loan commitment of $1.0 billion, which may be increased up to $1.25 billion at the request of the Borrower and with the consent of lenders who are willing to increase their loan commitments, provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in October 2016. With majority (over 50%) lender consent, the term of the consenting lenders’ commitments may be extended for up to two successive one-year periods at the Borrower’s request. At September 30, 2014, the Company had $566.0 million in outstanding borrowings and $434.0 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 100 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the Borrower’s consolidated leverage ratio (200 basis points per annum as of September 30, 2014). The Company also pays commitment fees on the unused commitment under the facility based on a grid of its consolidated leverage ratio.

The Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The Credit Agreement includes restrictive covenants requiring the Borrower to maintain a consolidated leverage ratio of no greater than three and one half times to one and, as long as the Company’s debt rating is below investment grade, the maintenance of an annual ratio of the net present value of the Company’s oil and gas properties to total funded debt of no less than one and one half times to one. At September 30, 2014, the Company was in compliance with all of its debt covenants under the Credit Agreement.

Ultra Resources, Inc. Senior Notes —

Ultra Resources also has outstanding $1.56 billion in principal amount of Senior Notes. Ultra Resources’ Senior Notes rank pari passu with the Company’s Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. The Senior Notes are pre-payable in whole or in part at any time following the payment of a make-whole premium and are subject to representations, warranties, covenants and events of default similar to those in the Credit Facility. At September 30, 2014, the Company was in compliance with all of its debt covenants under the Senior Notes. (See Note 3).

Ultra Petroleum Corp. Senior Notes —

Senior Notes due 2024: On September 18, 2014, the Company issued $850.0 million of 6.125% Senior Notes due 2024 (“2024 Notes”). The 2024 Notes are general, unsecured senior obligations of the Company and mature on October 1, 2024. The 2024 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to the extent of the value of the collateral securing such indebtedness). The 2024 Notes are not guaranteed by the Company’s subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. On and after October 1, 2019, the Company may redeem all or, from time to time, a part of the 2024 Notes at the following prices expressed as a percentage of principal amount of the 2024 Notes: (2019 — 103.063%; 2020 — 102.042%; 2021 — 101.021%; and 2022 and thereafter — 100.000%). The 2024 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the 2024 Notes contain events of default customary for a senior note financing. At September 30, 2014, the Company was in compliance with all of its debt covenants under the 2024 Notes.

Senior Notes due 2018: On December 12, 2013, the Company issued $450.0 million of 5.75% Senior Notes due 2018 (“2018 Notes”). The 2018 Notes are general, unsecured senior obligations of the Company and mature on December 15, 2018. The 2018 Notes rank equally in right of payment to all existing and future senior indebtedness of the Company and effectively rank junior to all future secured indebtedness of the Company (to

 

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the extent of the value of the collateral securing such indebtedness). The 2018 Notes are not guaranteed by the Company’s subsidiaries and so are structurally subordinated to the indebtedness and other obligations of the Company’s subsidiaries. On and after December 15, 2015, the Company may redeem all or, from time to time, a part of the 2018 Notes at the following prices expressed as a percentage of principal amount of the 2018 Notes: (2015 — 102.875%; 2016 — 101.438%; and 2017 and thereafter — 100.000%). The 2018 Notes are subject to covenants that restrict the Company’s ability to incur indebtedness, make distributions and other restricted payments, grant liens, use the proceeds of asset sales, make investments and engage in affiliate transactions. In addition, the 2018 Notes contain events of default customary for a senior note financing. At September 30, 2014, the Company was in compliance with all of its debt covenants under the 2018 Notes.

Operating Activities. During the nine months ended September 30, 2014, net cash provided by operating activities was $515.2 million, a 58% increase from $327.1 million for the same period in 2013. The increase in net cash provided by operating activities is largely attributable to increased revenues as a result of increased natural gas price realizations and increased oil production during the nine months ended September 30, 2014 as compared to the same period in 2013.

Investing Activities. During the nine months ended September 30, 2014, net cash used in investing activities was $1.5 billion as compared to $353.1 million for the same period in 2013. The increase in net cash used in investing activities is largely related to net acquisition costs of $890.8 million associated with the SWEPI Transaction (See Note 8 for a description of the transaction) as well as increased capital investments associated with the Company’s drilling activities in 2014 as compared to 2013.

Financing Activities. During the nine months ended September 30, 2014, net cash provided by financing activities was $940.4 million compared to cash provided by financing activities of $17.7 million for the same period in 2013. The change in net cash provided by financing activities is primarily due to increased net borrowings during the nine months ended September 30, 2014 as compared to 2013, primarily related to the SWEPI Transaction (See Note 8).

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of September 30, 2014.

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

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

Other risks and uncertainties include, but are not limited to, fluctuations in the price the Company receives for oil and gas production, reductions in the quantity of oil and gas sold due to increased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems,

 

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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, 2013 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 Consolidated Balance Sheets as either an asset or liability and be measured at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The Company does not apply hedge accounting to any of its derivative instruments.

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

Commodity Derivative Contracts: At September 30, 2014, the Company had the following open commodity derivative contracts to manage price risk on a portion of its production whereby the Company receives the fixed price for the contract and pays the variable price to the counterparty. The reference prices of these commodity derivative contracts are typically referenced to index prices as published by independent third parties.

 

Natural Gas:

Type

Commodity Reference Price

Remaining Contract Period

Volume - MMBTU/ Day

Average Price / MMBTU

Fair Value- September 30, 2014

(000’s) Asset/(Liability)

Fixed price swap

NYMEX-Henry Hub

Oct-14

480,000

$

3.90

$

(1,321

)

Fixed price swap

NYMEX-Henry Hub

Nov - Dec 2014

85,000

$

4.35

$

967

Crude Oil:

Type

Commodity Reference Price

Remaining Contract Period

Volume - Bbls/Day

Average Price/Bbl

Fair Value - September 30, 2014

(000’s) Asset

Fixed price swap

NYMEX-WTI

Oct -Dec 2014

4,000

$

93.19

$

1,097

 

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Subsequent to September 30, 2014 and through October 30, 2014, the Company has entered into 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:

 

Type

Commodity Reference Price

Remaining Contract Period

Volume- MMBTU/ Day

Average Price/ MMBTU

Fixed price swap

NYMEX-Henry Hub

Apr - Oct 2015

20,000

$

3.88

The following table summarizes the pre-tax realized and unrealized gain (loss) the Company recognized related to its derivative instruments in the Consolidated Statements of Income for the periods ended September 30, 2014 and 2013:

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
Commodity Derivatives (000’s):		2014				2013				2014				2013
Realized loss on commodity derivatives-natural gas(1)		$	(7,219	)		$	(1,310	)		$	(48,062	)		$	(21,074	)
Realized loss on commodity derivatives-crude oil(1)			(1,479	)			—				(6,881	)			—
Unrealized gain on commodity derivatives(1)			40,750				3,384				26,620				523
Total gain (loss) on commodity derivatives		$	32,052			$	2,074			$	(28,323	)		$	(20,551	)

 

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

The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts and the unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

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, 2014. There were no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2014 that have materially affected or are reasonably likely to materially 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, 2013.

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

On May 17, 2006, the Company announced that its Board of Directors authorized a share repurchase program for up to an aggregate $1 billion of the Company’s outstanding common stock which has been and will be funded by cash on hand and the Company’s senior revolving credit facility.

 

Period		Total Number of Shares Purchased (000’s)				Average Price Paid per Share				Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (000’s)				Maximum Number (or Approximate Dollar Value) that may yet be Purchased Under the Plans or Programs
July 2014			—				—				—			$	382.1 million
August 2014			—				—				—			$	382.1 million
September 2014			17			$	25.34				17			$	381.7 million

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

 

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ITEM 6. EXHIBITS

(a) Exhibits

 

3.1		Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
3.2		By-Laws of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
3.3		Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005.)
4.1		Specimen Common Share Certificate — (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
10.1		Purchase and Sale Agreement dated August 13, 2014 between the Ultra Petroleum Corp. and SWEPI LP (incorporated by reference from Exhibit 1.1 of the Company’s Report on Form 8-K filed with the SEC on August 19, 2014.)
10.2		Purchase Agreement, dated September 4, 2014, between Ultra Petroleum Corp. and Goldman, Sachs & Co., as representative of the Initial Purchasers (incorporated by reference from Exhibit 10.1 of the Company’s Report on Form 8-K filed with the SEC on September 5, 2014.)
10.3		Indenture, dated September 18, 2014, between Ultra Petroleum Corp., as Issuer, and U.S. Bank National Association, as Trustee (incorporated by reference from Exhibit 4.1 of the Company’s Report on Form 8-K filed with the SEC on September 22, 2014.)
10.4		Registration Rights Agreement, dated September 18, 2014, between Ultra Petroleum Corp. and Goldman, Sachs & Co., as representative of the Initial Purchasers (incorporated by reference from Exhibit 4.2 of the Company’s Report on Form 8-K filed with the SEC on September 22, 2014.)
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: October 30, 2014

 

Date: October 30, 2014

 

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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 August 13, 2014 between the Ultra Petroleum Corp. and SWEPI LP (incorporated by reference from Exhibit 1.1 of the Company’s Report on Form 8-K filed with the SEC on August 19, 2014.)
10.2		Purchase Agreement, dated September 4, 2014, between Ultra Petroleum Corp. and Goldman, Sachs & Co., as representative of the Initial Purchasers (incorporated by reference from Exhibit 10.1 of the Company’s Report on Form 8-K filed with the SEC on September 5, 2014.)
10.3		Indenture, dated September 18, 2014, between Ultra Petroleum Corp., as Issuer, and U.S. Bank National Association, as Trustee (incorporated by reference from Exhibit 4.1 of the Company’s Report on Form 8-K filed with the SEC on September 22, 2014.)
10.4		Registration Rights Agreement, dated September 18, 2014, between Ultra Petroleum Corp. and Goldman, Sachs & Co., as representative of the Initial Purchasers (incorporated by reference from Exhibit 4.2 of the Company’s Report on Form 8-K filed with the SEC on September 22, 2014.)
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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