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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, 2015

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 22, 2015 was 153,253,518.

 

 

 

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TABLE OF CONTENTS

 

PART I — FINANCIAL INFORMATION
ITEM 1.		Financial Statements			1
ITEM 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			17
ITEM 3.		Quantitative and Qualitative Disclosures About Market Risk			31
ITEM 4.		Controls and Procedures			32
PART II — OTHER INFORMATION
ITEM 1.		Legal Proceedings			33
ITEM 1A.		Risk Factors			33
ITEM 2.		Unregistered Sales of Equity Securities and Use of Proceeds			33
ITEM 3.		Defaults upon Senior Securities			33
ITEM 4.		Mine Safety Disclosures			33
ITEM 5.		Other Information			33
ITEM 6.		Exhibits			34
		Signatures			35
		Exhibit Index			36

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PART I — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF OPERATIONS

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
		2015				2014				2015				2014
		(Unaudited)
		(Amounts in thousands, except per share data)
Revenues:
Natural gas sales		$	188,457			$	211,853			$	536,477			$	711,965
Oil sales			34,046				76,755				113,332				199,005
Total operating revenues			222,503				288,608				649,809				910,970
Expenses:
Lease operating expenses			28,567				23,392				82,464				67,363
Liquids gathering system operating lease expense			5,162				5,076				15,485				15,229
Production taxes			19,813				23,729				56,892				74,254
Gathering fees			23,114				14,916				65,359				41,073
Transportation charges			21,310				20,034				62,577				57,882
Depletion, depreciation and amortization			92,806				76,289				279,762				204,810
General and administrative			4,567				6,233				10,629				14,736
Total operating expenses			195,339				169,669				573,168				475,347
Operating income			27,164				118,939				76,641				435,623
Other income (expense), net:
Interest expense			(43,137	)			(29,599	)			(128,426	)			(83,960	)
Gain (loss) on commodity derivatives			9,390				32,052				42,608				(28,323	)
Deferred gain on sale of liquids gathering system			2,638				2,638				7,915				7,915
Litigation expense			—				—				(4,401	)			—
Other expense, net			(284	)			(56	)			(323	)			(54	)
Total other (expense) income, net			(31,393	)			5,035				(82,627	)			(104,422	)
(Loss) income before income tax benefit			(4,229	)			123,974				(5,986	)			331,201
Income tax benefit			(1,133	)			(1,383	)			(3,405	)			(1,924	)
Net (loss) income		$	(3,096	)		$	125,357			$	(2,581	)		$	333,125
Net (loss) income per common share — basic		$	(0.02	)		$	0.82			$	(0.02	)		$	2.18
Net (loss) income per common share — diluted		$	(0.02	)		$	0.81			$	(0.02	)		$	2.15
Weighted average common shares outstanding — basic			153,250				153,213				153,171				153,145
Weighted average common shares outstanding — diluted			153,250				154,859				153,171				154,771

See accompanying notes to consolidated financial statements.

 

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ULTRA PETROLEUM CORP.

CONSOLIDATED BALANCE SHEETS

 

		September 30, 2015				December 31, 2014
		(Unaudited)
		(Amounts in thousands of U.S. dollars, except share data)
ASSETS
Current Assets:
Cash and cash equivalents		$	25,587			$	8,919
Restricted cash			115				117
Oil and gas revenue receivable			71,477				111,915
Joint interest billing and other receivables			18,780				32,502
Derivative assets			19,515				104,190
Other current assets			13,259				19,495
Total current assets			148,733				277,138
Oil and gas properties, net, using the full cost method of accounting:
Proven			3,760,811				3,636,643
Unproven properties not being amortized			246,922				242,294
Property, plant and equipment, net			9,403				12,186
Deferred income taxes			3,210				30,640
Deferred financing costs and other			22,886				26,789
Total assets		$	4,191,965			$	4,225,690
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	72,702			$	77,580
Accrued liabilities			65,854				89,865
Current portion of long-term debt			62,000				100,000
Production taxes payable			59,370				55,585
Deferred income tax liabilities			3,207				30,638
Interest payable			41,521				46,098
Capital cost accrual			25,366				45,952
Total current liabilities			330,020				445,718
Long-term debt			3,346,000				3,278,000
Deferred income tax liabilities			248				992
Deferred gain on sale of liquids gathering system			128,933				136,848
Other long-term obligations			171,769				152,472
Commitments and contingencies (Note 8)
Shareholders’ equity:
Common stock — no par value; authorized — unlimited; issued and outstanding — 153,253,518 and 152,896,315 at September 30, 2015 and December 31, 2014, respectively			504,335				495,913
Treasury stock			(223	)			(6,213	)
Retained loss			(289,117	)			(278,040	)
Total shareholders’ equity			214,995				211,660
Total liabilities and shareholders’ equity		$	4,191,965			$	4,225,690

See accompanying notes to consolidated financial statements.

 

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ULTRA PETROLEUM CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		Nine Months Ended September 30,
		2015				2014
		(Unaudited)
		(Amounts in thousands of U.S. dollars)
Cash provided by (used in):
Operating activities:
Net (loss) income for the period		$	(2,581	)		$	333,125
Adjustments to reconcile net (loss) income to cash provided by operating activities:
Depletion, depreciation and amortization			279,762				204,810
Deferred income tax benefit			(744	)			—
Unrealized gain (loss) on commodity derivatives			84,675				(26,620	)
Deferred gain on sale of liquids gathering system			(7,915	)			(7,915	)
Stock compensation			5,509				3,500
Other			6,295				3,204
Net changes in operating assets and liabilities:
Restricted cash			2				2
Accounts receivable			49,604				(18,230	)
Other current assets			(616	)			(5,871	)
Accounts payable			(6,898	)			26,205
Accrued liabilities			(4,469	)			(11,897	)
Production taxes payable			3,785				5,757
Interest payable			(4,577	)			(13,813	)
Other long-term obligations			7,040				17,401
Income taxes payable/receivable			2,333				5,504
Net cash provided by operating activities			411,205				515,162
Investing Activities:
Acquisition of oil and gas properties			3,964				(891,075	)
Oil and gas property expenditures			(390,874	)			(441,798	)
Gathering system expenditures			—				(6,842	)
Change in capital cost accrual			(20,585	)			(120,639	)
Inventory			3,177				815
Purchase of capital assets			(669	)			(5,327	)
Net cash used in investing activities			(404,987	)			(1,464,866	)
Financing activities:
Borrowings on long-term debt			936,000				833,000
Payments on long-term debt			(906,000	)			(727,000	)
Proceeds from issuance of Senior Notes			—				850,000
Deferred financing costs			6				(13,317	)
Repurchased shares/net share settlements			(2,507	)			(3,015	)
Payment of contingent consideration			(17,049	)			—
Proceeds from exercise of options			—				770
Net cash provided by financing activities			10,450				940,438
Increase (decrease) in cash and cash equivalents during the period			16,668				(9,266	)
Cash and cash equivalents, beginning of period			8,919				10,664
Cash and cash equivalents, end of period		$	25,587			$	1,398
SUPPLEMENTAL INFORMATION:
Non-cash investing activities — oil and gas properties		$	—				20,000

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, 2014, 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, 2014 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) Accounts Receivable: Accounts receivable are stated at the historical carrying amount net of write-offs and an allowance for uncollectible accounts. The carrying amount of the Company’s accounts receivable approximates fair value because of the short-term nature of the instruments. The Company routinely assesses the collectability of all material trade and other receivables.

(d) 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 acquisition of oil and natural gas properties including certain gas gathering systems in the Pinedale field in Wyoming (the “SWEPI Transaction”) in September 2014, 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 was transferred to proven oil and gas properties at September 30, 2014.

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

(e) Oil and Natural Gas Properties: The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities — Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as oil and gas properties. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and natural gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and natural gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country.

The sum of net capitalized costs and estimated future development costs of oil and natural gas properties are amortized using the units-of-production method based on the Company’s proved reserves. Oil and natural gas reserves and production are converted into equivalent units based on relative energy content. Asset retirement costs 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. The Company reviews its unproved leasehold costs quarterly or when management determines that events or circumstances indicate that the recorded carrying value of the unevaluated properties may not be recoverable. The fair values of unproved properties are evaluated utilizing a discounted net cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. The estimated prices used in the cash flow analysis are determined by management based on forward price curves for the related commodities, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors. 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, 2015 or 2014. However, due to the lower crude oil and natural gas prices prevailing during 2015 and the last three months of 2014, if crude oil and natural gas prices do not recover significantly from current levels, the Company anticipates its capitalized costs will exceed the ceiling in the fourth quarter of 2015, requiring it to write-down the carrying value of its oil and gas properties. The amount of a future write-down is difficult to predict because it depends on

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

the average oil and natural gas prices in effect on the first day of the month for the preceding twelve month period, the net change in proved reserves during the period, and additional capital expenditures made by the Company during the period.

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

(g) 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.

(h) 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, 2015				September 30, 2014				September 30, 2015				September 30, 2014
		(Share amounts in 000’s)
Net (loss) income		$	(3,096	)		$	125,357			$	(2,581	)		$	333,125
Weighted average common shares outstanding — basic			153,250				153,213				153,171				153,145
Effect of dilutive instruments(1)			—				1,646				—				1,626
Weighted average common shares outstanding — diluted			153,250				154,859				153,171				154,771
Net (loss) income per common share — basic		$	(0.02	)		$	0.82			$	(0.02	)		$	2.18
Net (loss) income per common share — diluted		$	(0.02	)		$	0.81			$	(0.02	)		$	2.15
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)			—				1,295				—				1,747

 

(1)	Due to the net loss for the quarter and nine months ended September 30, 2015, 1.6 million and 1.7 million shares, respectively, for options and restricted stock units were anti-dilutive and excluded from the computation of net loss per share.

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

(i) 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.

(j) 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.

(k) 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.

(l) 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.

(m) Revenue Recognition: The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. 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. 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. The Company’s imbalance obligations as of September 30, 2015 and December 31, 2014 were immaterial.

(n) 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.

(o) 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.

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

(p) Recent Accounting Pronouncements: In July 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory (“ASU No. 2015-11”). Public companies will have to apply the amendments for reporting periods that start after December 15, 2016, including interim periods within those fiscal years. This ASU requires an entity to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The company does not expect the adoption of ASU No. 2015-11 to have a material impact on its consolidated financial statements.

In April 2015, the FASB issued an amendment to U.S. GAAP to simplify the balance sheet presentation of the costs for issuing debt. The changes were adopted in ASU No. 2015-03, Interest — Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU No. 2015-3”). Public companies will have to apply the amendments for reporting periods that start after December 15, 2015. The amendment requires adoption by revising the balance sheets for periods prior to the effective date, which makes it easier for investors to evaluate a company’s financial performance. The amendment to FASB ASC 835-30-45, Interest — Imputation of Interest, formerly Accounting Principles Board Opinion No. 21, means that the costs for issuing debt will appear on the balance sheet as a direct deduction of debt. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

In June 2015, the FASB issued a delay by one year of the revenue recognition standard adopted in June 2014. 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. The new proposal related to ASU No. 2014-09 delays the application of the standard to reporting periods beginning after December 15, 2017 instead of December 15, 2016. The Company is still evaluating the impact of ASU No. 2014-09 on its financial position and results of operations.

In August 2014, the FASB issued 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 ASU to have a material impact on its consolidated financial statements.

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

2. OIL AND GAS PROPERTIES AND EQUIPMENT:

 

		September 30, 2015				December 31, 2014
Proven Properties:
Acquisition, equipment, exploration, drilling and abandonment costs		$	10,126,371			$	9,731,407
Less: Accumulated depletion, depreciation and amortization			(6,365,560	)			(6,094,764	)
			3,760,811				3,636,643
Unproven Properties:
Acquisition and exploration costs not being amortized(1)			246,922				242,294
Net capitalized costs — oil and gas properties		$	4,007,733			$	3,878,937

 

(1)

For the nine months ended September 30, 2015 and the year ended December 31, 2014, total interest on outstanding debt was $138.1 million and $146.6 million, respectively, of which, $9.7 million and $20.4 million, respectively, was capitalized on the cost of unproven oil and natural gas properties and on work in process relating to gathering systems.

3. DEBT AND OTHER LONG-TERM OBLIGATIONS:

 

		September 30, 2015				December 31, 2014
Short-term debt:
Senior Notes due March 2016		$	62,000			$	100,000
Long-term debt and other obligations:
Bank indebtedness			648,000				518,000
Senior Notes			2,698,000				2,760,000
Other long-term obligations			171,769				152,472
		$	3,579,769			$	3,530,472

Ultra Resources, Inc. Bank Indebtedness —

Bank indebtedness. The Company (through its subsidiary, Ultra Resources, Inc.) is a party to an unsecured, 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. In anticipation of the upcoming maturity of the Credit Agreement, the Company has begun discussions to renegotiate the Credit Agreement. At September 30, 2015, the Company had $648.0 million in outstanding borrowings and $352.0 million of unused debt capacity under the Credit Agreement.

Loans under the Credit Agreement are unsecured and bear interest, at the Borrower’s option, based on (A) a rate per annum equal to the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 125 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

rate, plus a margin based on a grid of the Borrower’s consolidated leverage ratio (225 basis points per annum as of September 30, 2015). 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, 2015, the Company was in compliance with all of its debt covenants under the Credit Agreement. Further, based on the Company’s current forecast, including its assumptions about commodity prices (which prices have historically been volatile) and activity levels, the Company expects to remain in compliance with all of its debt covenants under the Credit Agreement for the next twelve months. However, if over the next twelve months, crude oil and natural gas prices remain at current levels or fall to lower levels, the Company is likely to generate lower operating cash flows, which would make it more difficult for the Company to remain in compliance with all of its debt covenants under the Credit Agreement, including the covenant requiring the Company to maintain a consolidated leverage ratio of less than three and one half times to one.

Ultra Resources, Inc. Senior Notes —

Ultra Resources also has outstanding $1.46 billion in notes collectively referred to as “Senior Notes”. During March 2015, $100 million of notes matured and were paid in full. 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 including a consolidated leverage ratio of no greater than three and one half times to one. At September 30, 2015, the Company was in compliance with all of its debt covenants under the Senior Notes. Further, based on the Company’s current forecast, including its assumptions about commodity prices (which prices have historically been volatile) and activity levels, the Company expects to remain in compliance with all of its debt covenants under the Senior Notes for the next twelve months. However, if over the next twelve months, crude oil and natural gas prices remain at current levels or fall to lower levels, the Company is likely to generate lower operating cash flows, which would make it more difficult for the Company to remain in compliance with all of its debt covenants under the Senior Notes, including the covenant requiring the Company to maintain a consolidated leverage ratio of less than three and one half times to one.

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

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

transactions. In addition, the 2024 Notes contain events of default customary for a senior note financing. At September 30, 2015, 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, 2015, 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.

4. SHARE BASED COMPENSATION:

Valuation and Expense Information

		Three Months Ended September 30,								Nine Months Ended September 30,
		2015				2014				2015				2014
Total cost of share-based payment plans		$	3,963			$	3,896			$	8,247			$	5,635
Amounts capitalized in oil and gas properties and equipment		$	1,283			$	1,425			$	2,738			$	2,135
Amounts charged against income, before income tax benefit (provision)		$	2,680			$	2,471			$	5,509			$	3,500
Amount of related income tax (expense) benefit recognized in income before valuation allowance		$	1,120			$	1,033			$	2,303			$	1,463

Changes in Stock Options and Stock Options Outstanding

The following table summarizes the changes in stock options for the nine months ended September 30, 2015 and the year ended December 31, 2014:

 

		Number of Options (000’s)				Weighted Average Exercise Price (US Dollars)
Balance, December 31, 2013			1,246			$	16.97				to			$	98.87
Forfeited			(513	)		$	33.57				to			$	75.18
Exercised			(43	)		$	16.97				to			$	25.68
Balance, December 31, 2014			690			$	25.68				to			$	98.87
Expired or forfeited			(105	)		$	25.68				to			$	75.18
Exercised			—			$	0.00				to			$	0.00
Balance, September 30, 2015			585			$	49.05				to			$	98.87

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Performance Share Plans:

Long Term Incentive Plans. The Company offers a Long Term Incentive Plan (“LTIP”) in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. Each LTIP covers a performance period of three years.

Under each LTIP, the Compensation Committee establishes a percentage of base salary for each participant that 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 are 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.

Time-Based Measure and Performance-Based Measures:

For each LTIP award, the Committee establishes time-based and performance-based measures at the beginning of each three-year performance period. For the LTIP awards in 2015, 2014 and 2013, the Committee established the following performance-based measures: return on capital employed, debt level, and reserve replacement ratio. The fair value of the time-based and performance-based component of the LTIP award is based on the average high and low market price of the Company’s common stock on the date of award.

Market-Based Measure:

LTIP awards granted to officers during 2015, 2014 and 2013, include an additional performance metric, Total Shareholder Return. The grant-date fair value related to the market-based condition was calculated using a Monte Carlo simulation.

Valuation Assumptions

The Company estimates the fair value of the market condition related to the LTIP awards on the date of grant using a Monte Carlo simulation with the following assumptions:

 

		2015 LTIP				2014 LTIP				2013 LTIP
Volatility of common stock			40.1	%			39.0	%			39.2	%
Average volatility of peer companies			46.5	%			n/a				n/a
Average correlation coefficient of peer companies			0.454				n/a				n/a
Risk-free interest rate			1.02	%			0.66	%			0.40	%

Stock-Based Compensation Cost:

For the nine months ended September 30, 2015, the Company recognized $4.7 million in pre-tax compensation expense related to the 2013, 2014 and 2015 LTIP awards of restricted stock units as compared to $4.7 million during the nine months ended September 30, 2014 related to the 2012, 2013 and 2014 LTIP awards of restricted stock units. The amounts recognized during the nine months ended September 30, 2015 assume that performance objectives between target and maximum are attained for the 2013 LTIP and maximum performance objectives are attained under the 2014 and 2015 LTIP plans. If the Company ultimately attains these performance

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

objectives, the associated total compensation, estimated at September 30, 2015, for each of the three year performance periods is expected to be approximately $9.7 million, $13.4 million, and $14.4 million related to the 2013, 2014 and 2015 LTIP awards of restricted stock units, respectively. The 2012 LTIP award of restricted stock units was paid in shares of the Company’s stock to employees during the first quarter of 2015 and totaled $9.2 million (232,636 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, the ability to carryback current period losses, state income taxes and other permanent differences.

The Company has recorded a valuation allowance against certain deferred tax assets as of September 30, 2015. 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 Operations. Unrealized gains or losses on commodity derivatives represent the non-cash change in the fair value of these derivative instruments and do not impact operating cash flows on the cash flow statement. See Note 7 for the detail of the fair value of the following derivatives.

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

Commodity Derivative Contracts: At September 30, 2015, 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, 2015

Asset

Fixed price swap

NYMEX-Henry Hub

Oct-15

672,500

$

3.50

$

19,515

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 Operations for the periods ended September 30, 2015 and 2014:

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
Commodity Derivatives:		2015				2014				2015				2014
Realized gain (loss) on commodity derivatives-natural gas(1)		$	45,300			$	(7,219	)		$	127,283			$	(48,062	)
Realized (loss) on commodity derivatives-crude oil(1)			—				(1,479	)			—				(6,881	)
Unrealized (loss) gain on commodity derivatives(1)			(35,910	)			40,750				(84,675	)			26,620
Total gain (loss) on commodity derivatives		$	9,390			$	32,052			$	42,608			$	(28,323	)

 

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

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.

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

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, measured at fair value on a recurring basis, as of September 30, 2015. The Company has no derivative instruments which qualify for cash flow hedge accounting.

 

		Level 1				Level 2				Level 3				Total
Assets:
Current derivative asset		$	—			$	19,515			$	—			$	19,515

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

 

		September 30, 2015								December 31, 2014
		Carrying Amount				Estimated Fair Value				Carrying Amount				Estimated Fair Value
5.45% Notes due March 2015, issued 2008		$	—			$	—			$	100,000			$	101,931
7.31% Notes due March 2016, issued 2009			62,000				61,424				62,000				65,027
4.98% Notes due January 2017, issued 2010			116,000				106,474				116,000				116,240
5.92% Notes due March 2018, issued 2008			200,000				176,918				200,000				203,738
5.75% Notes due December 2018, issued 2013			450,000				345,275				450,000				414,505
7.77% Notes due March 2019, issued 2009			173,000				153,896				173,000				187,105
5.50% Notes due January 2020, issued 2010			207,000				160,809				207,000				201,371
4.51% Notes due October 2020, issued 2010			315,000				217,331				315,000				283,335
5.60% Notes due January 2022, issued 2010			87,000				60,805				87,000				82,581
4.66% Notes due October 2022, issued 2010			35,000				21,520				35,000				30,476
6.125% Notes due October 2024, issued 2014			850,000				510,527				850,000				754,485
5.85% Notes due January 2025, issued 2010			90,000				55,857				90,000				83,876
4.91% Notes due October 2025, issued 2010			175,000				94,362				175,000				147,649
Credit Facility due October 2016			648,000				648,000				518,000				518,000
		$	3,408,000			$	2,613,198			$	3,378,000			$	3,190,319

 

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ULTRA PETROLEUM CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(Unaudited)

 

8. COMMITMENTS AND CONTINGENCIES:

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

 

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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, and gas sales from wells located in the Appalachian Basin in Pennsylvania. In 2014, the Company repositioned its portfolio to higher returning assets in the western U.S. while divesting lower returning assets in the eastern U.S. Additionally, as part of the SWEPI Transaction, the Company acquired contracts related to NGLs providing the opportunity to realize the benefit of the NGLs from the gas it produces in Wyoming beginning in 2017.

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, 2015, the average price realization for the Company’s natural gas was $3.33 per Mcf, including realized gains and losses on commodity derivatives compared with $3.59 per Mcf during the quarter ended September 30, 2014. The Company’s average price realization for natural gas was $2.68 per Mcf, excluding the realized gains and losses on commodity derivatives. This compares with $3.72 per Mcf during the third quarter of 2014.

During the quarter ended September 30, 2015, the average price realization for the Company’s oil was $39.43 per barrel. The Company does not currently have any open derivative contracts for oil production. 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 and $82.77 per barrel, excluding realized gains and losses on commodity derivatives.

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

 

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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 our financial statements which we believe 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 Operations.

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, 2015 is summarized in the following table based on the inputs used to determine fair value:

 

		Level 1 (a)				Level 2 (b)				Level 3 (c)				Total
		(Amounts in 000’s)
Assets:
Current derivative asset		$	—			$	19,515			$	—			$	19,515

 

(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

 

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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, 2015 and 2014 was $5.5 million and $3.5 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 in September 2014, 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 was transferred to proven oil and gas properties at September 30, 2014.

Full Cost Method of Accounting. The Company uses the full cost method of accounting for oil and gas exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and FASB ASC Topic 932, Extractive Activities — Oil and Gas (“FASB ASC 932”). Under the full cost method of accounting, all costs associated with the exploration for and development of oil and gas reserves are capitalized on a country-by-country basis. Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling both productive and non-productive wells and overhead charges directly related to acquisition, exploration and development activities. Substantially all of the oil and gas activities are conducted jointly with others and, accordingly, the amounts reflect only the Company’s proportionate interest in such activities.

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

The calculation of the ceiling test is based upon estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting the future rates of production and in the timing of development activities. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

 

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The Company did not have any write-downs related to the full cost ceiling limitation during the nine months ended September 30, 2015 or 2014. However, due to the lower crude oil and natural gas prices prevailing during 2015 and the last three months of 2014, if crude oil and natural gas prices do not recover significantly from current levels, the Company anticipates its capitalized costs will exceed the ceiling in the fourth quarter of 2015, requiring it to write-down the carrying value of its oil and gas properties. The amount of a future write-down is difficult to predict because it depends on the average oil and natural gas prices in effect on the first day of the month for the preceding twelve month period, the net change in proved reserves during the period, and additional capital expenditures made by the Company during the period.

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 (See Note 2).

Revenue Recognition. The Company generally sells oil and natural gas under both long-term and short-term agreements at prevailing market prices. 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.

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 imbalance. The Company’s imbalance obligations as of September 30, 2015 and December 31, 2014 were immaterial.

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 certain of its deferred tax assets as of September 30, 2015. Some or all of this valuation allowance may be reversed in future periods against future income.

Recent accounting pronouncements. In July 2015, the FASB issued Accounting Standards Update (“ASU”) 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory (“ASU No. 2015-11”). Public companies will have to apply the amendments for reporting periods that start after December 15, 2016, including interim periods within those fiscal years. This ASU requires an entity to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. The company does not expect the adoption of ASU No. 2015-11 to have a material impact on its consolidated financial statements.

In April 2015, the FASB issued an amendment to U.S. GAAP to simplify the balance sheet presentation of the costs for issuing debt. The changes were adopted in ASU No. 2015-03, Interest — Imputation of Interest

 

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(Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs (“ASU No. 2015-3”). Public companies will have to apply the amendments for reporting periods that start after December 15, 2015. The amendment requires adoption by revising the balance sheets for periods prior to the effective date, which makes it easier for investors to evaluate a company’s financial performance. The amendment to FASB ASC 835-30-45, Interest —Imputation of Interest, formerly Accounting Principles Board (APB) Opinion No. 21, means that the costs for issuing debt will appear on the balance sheet as a direct deduction of debt. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.

In June 2015, the FASB issued a delay by one year of the revenue recognition standard adopted in June 2014. 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. The new proposal related to ASU No. 2014-09 delays the application of the standard to reporting periods beginning after December 15, 2017 instead of December 15, 2016. The Company is still evaluating the impact of ASU No. 2014-09 on its financial position and results of operations.

In August 2014, the FASB issued 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 ASU to have a material impact on its consolidated financial statements.

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
		2015				2014								2015				2014
		(Amounts in thousands, except per unit data)
Production, Commodity Prices and Revenues:
Production:
Natural gas (Mcf)			70,194				56,984				23	%			200,039				164,269				22	%
Crude oil and condensate (Bbls)			863				927				-7	%			2,714				2,344				16	%
Total production (Mcfe)			75,372				62,548				21	%			216,323				178,334				21	%
Commodity Prices:
Natural gas ($/Mcf, including realized hedges)		$	3.33			$	3.59				-7	%		$	3.32			$	4.04				-18	%
Natural gas ($/Mcf, excluding hedges)		$	2.68			$	3.72				-28	%		$	2.68			$	4.33				-38	%
Oil and condensate ($/Bbl, incl realized hedges)		$	39.43			$	81.18				-51	%		$	41.75			$	81.96				-49	%
Oil and condensate ($/Bbl, excl realized hedges)		$	39.43			$	82.77				-52	%		$	41.75			$	84.89				-51	%
Revenues:
Natural gas sales		$	188,457			$	211,853				-11	%		$	536,477			$	711,965				-25	%
Oil sales			34,046				76,755				-56	%			113,332				199,005				-43	%
Total operating revenues		$	222,503			$	288,608				-23	%		$	649,809			$	910,970				-29	%
Derivatives:
Realized gain (loss) on commodity derivatives-natural gas		$	45,300			$	(7,219	)			728	%		$	127,283			$	(48,062	)			365	%
Realized (loss) on commodity derivatives-oil			—				(1,479	)			100	%			—				(6,881	)			100	%
Unrealized (loss) gain on commodity derivatives			(35,910	)			40,750				188	%			(84,675	)			26,620				418	%
Total gain (loss) on commodity derivatives		$	9,390			$	32,052				71	%		$	42,608			$	(28,323	)			250	%
Operating Costs and Expenses:
Lease operating expenses		$	28,567			$	23,392				22	%		$	82,464			$	67,363				22	%
Liquids gathering system operating lease expense		$	5,162			$	5,076				2	%		$	15,485			$	15,229				2	%
Production taxes		$	19,813			$	23,729				-17	%		$	56,892			$	74,254				-23	%
Gathering fees		$	23,114			$	14,916				55	%		$	65,359			$	41,073				59	%
Transportation charges		$	21,310			$	20,034				6	%		$	62,577			$	57,882				8	%
Depletion, depreciation and amortization		$	92,806			$	76,289				22	%		$	279,762			$	204,810				37	%
General and administrative expenses		$	4,567			$	6,233				-27	%		$	10,629			$	14,736				-28	%
Per Unit Costs and Expenses ($/Mcfe):
Lease operating expenses		$	0.38			$	0.37				3	%		$	0.38			$	0.38				0	%
Liquids gathering system operating lease expense		$	0.07			$	0.08				-13	%		$	0.07			$	0.09				-22	%
Production taxes		$	0.26			$	0.38				-32	%		$	0.26			$	0.42				-38	%
Gathering fees		$	0.31			$	0.24				29	%		$	0.30			$	0.23				30	%
Transportation charges		$	0.28			$	0.32				-13	%		$	0.29			$	0.32				-9	%
Depletion, depreciation and amortization		$	1.23			$	1.22				1	%		$	1.29			$	1.15				12	%
General and administrative expenses		$	0.06			$	0.10				-40	%		$	0.05			$	0.08				-38	%

 

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Quarter Ended September 30, 2015 vs. Quarter Ended September 30, 2014

Production, Commodity Derivatives and Revenues:

Production. During the quarter ended September 30, 2015, total production increased 21% on a gas equivalent basis to 75.4 Bcfe compared to 62.5 Bcfe for the same quarter in 2014. The increase is primarily attributable to the acquisition of the SWEPI properties in September 2014 and our drilling program.

Commodity Prices — Natural Gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 7% to $3.33 per Mcf in the third quarter of 2015 as compared to $3.59 per Mcf for the same quarter of 2014. During the three months ended September 30, 2015, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $2.68 per Mcf as compared to $3.72 per Mcf for the same period in 2014.

Commodity Prices — Oil. During the quarter ended September 30, 2015, the average price realization for the Company’s oil was $39.43 per barrel. The Company does not currently have any open derivative contracts for oil production. For 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 and $82.77 per barrel, excluding realized gains and losses on commodity derivatives.

Revenues. The decrease in average oil and natural gas prices, excluding the gains and losses on commodity derivatives offset by increased production from the properties acquired in the SWEPI Transaction and our drilling program resulted in revenues decreasing to $222.5 million for the quarter ended September 30, 2015 as compared to $288.6 million for the same period in 2014.

Operating Costs and Expenses:

Lease Operating Expense. Lease operating expense (“LOE”) increased to $28.6 million during the third quarter of 2015 compared to $23.4 million during the same period in 2014 largely related to the increased production associated with the SWEPI Transaction and our drilling program. On a unit of production basis, LOE costs remained relatively flat at $0.38 per Mcfe during the third quarter of 2015 compared with $0.37 per Mcfe during the third quarter of 2014.

Liquids Gathering System 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 lease is classified as an operating lease. For the three months ended September 30, 2015, the Company recognized operating lease expense associated with the Lease Agreement of $5.2 million, or $0.07 per Mcfe as compared to $5.1 million, or $0.08 per Mcfe for the same period in 2014.

Production Taxes. During the three months ended September 30, 2015, production taxes were $19.8 million compared to $23.7 million during the same period in 2014, or $0.26 per Mcfe compared to $0.38 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 8.9% of revenues for the quarter ended September 30, 2015 and 8.2% of revenues for the same period in 2014. The decrease in per unit taxes is primarily attributable to decreased oil and natural gas prices, excluding the effects of commodity derivatives during the quarter ended September 30, 2015 as compared to the same period in 2014.

Gathering Fees. Gathering fees increased to $23.1 million for the three months ended September 30, 2015 compared to $14.9 million during the same period in 2014 largely due to production increases in Wyoming. On a

 

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per unit basis, gathering fees increased to $0.31 per Mcfe for the three months ended September 30, 2015 as compared to $0.24 per Mcfe during the same period in 2014 primarily due to higher gathering rates in Wyoming as compared to Pennsylvania.

Transportation Charges. The Company incurred firm transportation charges totaling $21.3 million for the quarter ended September 30, 2015 as compared to $20.0 million for the same period in 2014 in association with Rockies Express Pipeline (“REX”) transportation charges. On a per unit basis, transportation charges decreased to $0.28 per Mcfe (on total company volumes) for the quarter ended September 30, 2015 compared with $0.32 per Mcfe (on total company volumes) for the quarter ended September 30, 2014 primarily as a result of increased production volumes.

Depletion, Depreciation and Amortization. DD&A expenses increased to $92.8 million during the three months ended September 30, 2015 from $76.3 million for the same period in 2014, attributable to increased production. On a unit of production basis, DD&A remained relatively flat at $1.23 per Mcfe for the quarter ended September 30, 2015 compared to $1.22 per Mcfe for the quarter ended September 30, 2014.

General and Administrative Expenses. General and administrative expenses decreased to $4.6 million for the quarter ended September 30, 2015 compared to $6.2 million for the same period in 2014. The decrease in general and administrative expenses is primarily attributable to personnel and overhead charges allocated to the increased wells as a result of the SWEPI Transaction. On a per unit basis, general and administrative expenses decreased to $0.06 per Mcfe for the quarter ended September 30, 2015 compared to $0.10 per Mcfe for the quarter ended September 30, 2014 as a result of decreased costs and increased production.

Other Income and Expenses:

Interest Expense. Interest expense increased to $43.1 million during the quarter ended September 30, 2015 compared to $29.6 million during the same period in 2014 primarily as a result of higher average borrowings outstanding for the quarter ended September 30, 2015 as compared to the same period in 2014. (See Note 3).

Deferred Gain on Sale of Liquids Gathering System. During the quarters ended September 30, 2015 and 2014, 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/(Loss) on Commodity Derivatives. During the quarter ended September 30, 2015, the Company recognized a gain of $9.4 million compared with a gain of $32.1 million during the same period in 2014 related to commodity derivatives. Of this total, the Company recognized $45.3 million of realized gain on commodity derivatives during the quarter ended September 30, 2015 compared with $8.7 million of realized loss on commodity derivatives during the three months ended September 30, 2014. The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts. This amount also includes an unrealized loss on commodity derivatives of $35.9 million during the quarter ended September 30, 2015 as compared to $40.8 million in unrealized gain on commodity derivatives during the quarter ended September 30, 2014. 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.

(Loss) Income from Continuing Operations:

Pretax (Loss) Income. The Company recognized a net loss before income taxes of $4.2 million for the quarter ended September 30, 2015 compared with income before income taxes of $124.0 million for the same

 

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period in 2014. The decrease in earnings is primarily due to decreased revenues as a result of decreased oil and natural gas prices partially offset by increased production during the three months ended September 30, 2015 as compared to the same period in 2014.

Income Taxes. The Company has recorded a valuation allowance against certain deferred tax assets as of September 30, 2015. Some or all of this valuation allowance may be reversed in future periods against future income.

Net (Loss) Income. For the three months ended September 30, 2015, the Company recognized net loss of $3.1 million or $0.02 per diluted share as compared with net income of $125.4 million or $0.81 per diluted share for the same period in 2014. The decrease is primarily due to decreased revenues as a result of decreased oil and natural gas prices partially offset by increased production during the three months ended September 30, 2015 as compared to the same period in 2014.

Nine Months Ended September 30, 2015 vs. Nine Months Ended September 30, 2014

Production, Commodity Derivatives and Revenues:

Production. During the nine months ended September 30, 2015, production increased on a gas equivalent basis to 216.3 Bcfe compared to 178.3 Bcfe for the same period in 2014. The increase is primarily attributable to the SWEPI Transaction in September 2014 and our drilling program.

Commodity Prices — Natural Gas. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 18% to $3.32 per Mcf during the nine months ended September 30, 2015 as compared to $4.04 per Mcf during 2014. During the nine months ended September 30, 2015, the Company’s average price for natural gas excluding realized gains and losses on commodity derivatives was $2.68 per Mcf as compared to $4.33 per Mcf for the same period in 2014.

Commodity Prices — Oil. During the nine months ended September 30, 2015, the average price realization for the Company’s oil was $41.75 per barrel compared with $81.96 per barrel during the nine months ended September 30, 2014. The Company does not currently have any open derivative contracts for oil production. During the nine months ended September 30, 2014, the average price realization for the Company’s oil was $84.89 per barrel, including realized gains and losses on commodity derivatives.

Revenues. The decrease in average oil and natural gas prices, excluding the gains and losses on commodity derivatives offset by increased production from the properties acquired in the SWEPI Transaction and our drilling program resulted in revenues decreasing to $649.8 million for the nine months ended September 30, 2015 as compared to $911.0 million for the same period in 2014.

Operating Costs and Expenses:

Lease Operating Expense. LOE increased to $82.5 million during the nine months ended September 30, 2015 compared to $67.4 million during the same period in 2014 largely related to increased production associated with the SWEPI transaction and our drilling program. On a unit of production basis, LOE costs remained flat at $0.38 per Mcfe during the nine months ended September 30, 2015 and 2014.

Liquids Gathering System 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

 

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exceeded. For the nine months ended September 30, 2015, the Company recognized operating lease expense associated with the Lease Agreement of $15.5 million, or $0.07 per Mcfe as compared to $15.2 million, or $0.09 per Mcfe for the same period in 2014.

Production Taxes. During the nine months ended September 30, 2015, production taxes were $56.9 million compared to $74.3 million during the same period in 2014, or $0.26 per Mcfe compared to $0.42 per Mcfe. Production taxes are primarily calculated based on a percentage of revenue from production in Wyoming and Utah after certain deductions and were 8.8% of revenues for the nine months ended September 30, 2015 and 8.2% of revenues for the same period in 2014. The decrease in per unit taxes is primarily attributable to decreased natural gas prices, excluding the effects of commodity derivatives, during the nine months ended September 30, 2015 as compared to the same period in 2014.

Gathering Fees. Gathering fees increased to $65.4 million for the nine months ended September 30, 2015 compared to $41.1 million during the same period in 2014 largely related to production increases in Wyoming. On a per unit basis, gathering fees increased to $0.30 per Mcfe for the nine months ended September 30, 2015 as compared to $0.23 per Mcfe during the same period in 2014 primarily due to higher gathering rates in Wyoming as compared to Pennsylvania.

Transportation Charges. The Company incurred firm transportation charges totaling $62.6 million for the nine months ended September 30, 2015 as compared to $57.9 million for the same period in 2014 in association with REX transportation charges. Transportation charges increased due to a refund received 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 $0.29 per Mcfe (on total company volumes) for the nine months ended September 30, 2015 as compared to $0.32 per Mcfe (on total company volumes) for the same period in 2014 primarily as a result of increased production volumes.

Depletion, Depreciation and Amortization. DD&A expenses increased to $279.8 million during the nine months ended September 30, 2015 from $204.8 million for the same period in 2014, attributable to a higher depletion rate and increased production. On a unit of production basis, DD&A increased to $1.29 per Mcfe for the nine months ended September 30, 2015 from $1.15 per Mcfe for the nine months ended September 30, 2014 primarily related to forecasted increased future development costs.

General and Administrative Expenses. General and administrative expenses decreased to $10.6 million for the nine months ended September 30, 2015 compared to $14.7 million for the same period in 2014.The decrease in general and administrative expenses is primarily attributable to personnel and overhead charges allocated to the increased wells as a result of the SWEPI transaction. On a per unit basis, general and administrative expenses decreased to $0.05 per Mcfe for the nine months ended September 30, 2015 compared to $0.08 per Mcfe for the nine months ended September 30, 2014 as a result of decreased costs and increased production.

Other Income and Expenses:

Interest Expense. Interest expense increased to $128.4 million during the nine months ended September 30, 2015 compared to $84.0 million during the same period in 2014 primarily as a result of higher average borrowings outstanding for the nine months ended September 30, 2015 as compared to the same period in 2014. (See Note 3).

Litigation Expense. During the nine months ended September 30, 2015, the Company recognized litigation expenses of $4.4 million related to the resolution of litigation matters.

Deferred Gain on Sale of Liquids Gathering System. During the nine months ended September 30, 2015 and 2014, 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.

 

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Commodity Derivatives:

Gain (Loss) on Commodity Derivatives. During the nine months ended September 30, 2015, the Company recognized a gain of $42.6 million compared with a loss of $28.3 million during the same period in 2014 related to commodity derivatives. Of this total, the Company recognized $127.3 million of realized gain on commodity derivatives during the nine months ended September 30, 2015 compared with $54.9 million of realized loss on commodity derivatives during nine months ended September 30, 2014. The realized gain or loss on commodity derivatives relates to actual amounts received or paid or to be received or paid under the Company’s derivative contracts. This amount also includes an unrealized loss on commodity derivatives of $84.7 million during the nine months ended September 30, 2015 as compared to $26.6 million in unrealized gain on commodity derivatives during the nine months ended September 30, 2014. 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 (Loss) Income. The Company recognized a loss before income taxes of $6.0 million for the nine months ended September 30, 2015 compared with income before income taxes of $331.2 million for the same period in 2014. The decrease in earnings is largely due to decreased revenues as a result of decreased oil and natural gas prices partially offset by increased production during the nine months ended September 30, 2015 as compared to the same period in 2014.

Income Taxes. The Company has recorded a valuation allowance against substantially all of its net deferred tax asset balance as of September 30, 2015. 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, 2015, the Company recognized net loss of $2.6 million or $0.02 per diluted share as compared with net income of $333.1 million or $2.15 per diluted share for the same period in 2014. The decrease is largely due to decreased revenues as a result of decreased oil and natural gas prices partially offset by increased production during the nine months ended September 30, 2015 as compared to the same period in 2014.

LIQUIDITY AND CAPITAL RESOURCES

During the nine month period ended September 30, 2015, the Company relied on cash provided by operations along with borrowings under the Credit Agreement (defined below) to finance its capital expenditures. For the nine month period ended September 30, 2015, total capital expenditures were $390.9 million. During this period, the Company participated in 157 gross (105.3 net) wells in Wyoming and 19 gross (19.0 net) wells in Utah that were drilled to total depth and cased. No wells are scheduled to be drilled in Pennsylvania during 2015.

At September 30, 2015, the Company reported a cash position of $25.6 million compared to $1.4 million at September 30, 2014. Working capital deficit at September 30, 2015 was $181.3 million compared to working capital deficit of $237.6 million at September 30, 2014. At September 30, 2015, the Company had $648.0 million in outstanding borrowings and $352.0 million of available borrowing capacity under the Credit Agreement. In addition, the Company had $2.76 billion outstanding in senior notes (See Note 3). Other long-term obligations of $171.8 million at September 30, 2015 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 Credit Agreement (See Note 3), are projected to be sufficient to meet the Company’s obligations and to fund its budgeted capital investment program for 2015, which is currently projected to be approximately $500.0 million.

 

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Ultra Resources, Inc. Bank Indebtedness —

Bank indebtedness. The Company (through its subsidiary, Ultra Resources, Inc.) is a party to an unsecured, 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. In anticipation of the upcoming maturity of the Credit Agreement, the Company has begun discussions to renegotiate the Credit Agreement. At September 30, 2015, the Company had $648.0 million in outstanding borrowings and $352.0 million of unused debt capacity under the Credit Agreement.

Loans under the Credit Agreement are unsecured and bear interest, at the Borrower’s option, based on (A) a rate per annum equal to the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 125 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, plus a margin based on a grid of the Borrower’s consolidated leverage ratio (225 basis points per annum as of September 30, 2015). 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, 2015, the Company was in compliance with all of its debt covenants under the Credit Agreement. Further, based on the Company’s current forecast, including its assumptions about commodity prices (which prices have historically been volatile) and activity levels, the Company expects to remain in compliance with all of its debt covenants under the Credit Agreement for the next twelve months. However, if over the next twelve months, crude oil and natural gas prices remain at current levels or fall to lower levels, the Company is likely to generate lower operating cash flows, which would make it more difficult for the Company to remain in compliance with all of its debt covenants under the Credit Agreement, including the covenant requiring the Company to maintain a consolidated leverage ratio of less than three and one half times to one.

Ultra Resources, Inc. Senior Notes —

At September 30, 2015, Ultra Resources also has outstanding $1.46 billion in notes collectively referred to as “Senior Notes”. During March 2015, $100 million of notes matured and were paid in full. 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, 2015, the Company was in compliance with all of its debt covenants under the Senior Notes. Further, based on the Company’s current forecast, including its assumptions about commodity prices (which prices have historically been volatile) and activity levels, the Company expects to remain in compliance with all of its debt covenants under the Senior Notes for the next twelve months. However, if over the next twelve months, crude oil and natural gas prices remain at current levels or fall to lower levels, the Company is likely to generate lower operating cash flows, which would make it more difficult for the Company to remain in compliance with all of its debt covenants under the Senior Notes, including the covenant requiring the Company to maintain a consolidated leverage ratio of less than three and one half times to one. (See Note 3).

 

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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, 2015, 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, 2015, the Company was in compliance with all of its debt covenants under the 2018 Notes.

Operating Activities. During the nine months ended September 30, 2015, net cash provided by operating activities was $411.2 million, a 20% decrease from $515.2 million for the same period in 2014. The decrease in net cash provided by operating activities is largely attributable to decreased revenues as a result of decreased oil and natural gas price realizations partially offset by increased oil and natural gas production during the nine months ended September 30, 2015 as compared to the same period in 2014.

Investing Activities. During the nine months ended September 30, 2015, net cash used in investing activities was $405.0 million as compared to $1,464.9 million for the same period in 2014. The decrease in net cash used in investing activities is largely related to acquisition costs of $891.1 million associated with the SWEPI Transaction during 2014, decreased capital investments associated with the Company’s drilling activities and the change in the capital cost accrual. The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.

Financing Activities. During the nine months ended September 30, 2015, net cash provided by financing activities was $10.5 million compared to $940.4 million for the same period in 2014. The change in net cash provided by financing activities is primarily due to increased borrowings during 2014 related to the closing of the SWEPI Transaction in September 2014.

Outlook

During 2015, we have continued to focus on operational efficiencies in an effort to reduce our overall well costs and, due in part to the decline in commodity prices over the past several months, we have been able to

 

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negotiate reductions in service costs with our vendors. We expect that our operational efficiencies, combined with our service costs reductions, will lower our overall well costs and help us to maintain our low-cost structure. We intend to continue to monitor pricing and cost developments and make adjustments to our future capital expenditure programs as warranted.

While our net cash provided by operating activities has been and will continue to be negatively affected by low commodity prices, if commodity prices remain at current levels, we believe that we will continue to generate positive cash flow from operations. We expect this positive cash flow, along with availability under our Credit Agreement (See Note 3), will provide sufficient liquidity to fund our capital investments and operations over the next twelve months. We continue to monitor and evaluate the impact of reduced commodity prices in order to determine the appropriate size and nature of our capital investment program.

Although we believe our available cash, our existing credit facility and the cash generated from operations should be sufficient for us to meet our obligations, the global economic outlook, including capital markets and the commodity price environment, are uncertain. If crude oil and natural gas prices remain at current levels for longer than we expect, or fall to lower levels, we may not be able to maintain the level of liquidity we are currently anticipating, and financing alternatives may become more expensive or unavailable, which could have a material adverse effect on our financial condition and operations.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of September 30, 2015.

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

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

Other risks and uncertainties include, but are not limited to, fluctuations in the price the Company receives for oil and gas production, reductions in the quantity of oil and gas sold due to increased industry-wide demand and/or curtailments in production from specific properties due to mechanical, marketing or other problems, operating and capital expenditures that are either significantly higher or lower than anticipated because the actual cost of identified projects varied from original estimates and/or from the number of exploration and development opportunities being greater or fewer than currently anticipated and increased financing costs due to a significant increase in interest rates. See the Company’s annual report on Form 10-K for the year ended December 31, 2014 for additional risks related to the Company’s business.

 

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

Commodity Derivative Contracts: At September 30, 2015, 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, 2015

(000’s) Asset

Fixed price swap

NYMEX-Henry Hub

Oct-15

672,500

$

3.50

$

19,515

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 Operations for the periods ended September 30, 2015 and 2014:

 

		For the Three Months Ended September 30,								For the Nine Months Ended September 30,
Commodity Derivatives (000’s):		2015				2014				2015				2014
Realized gain (loss) on commodity derivatives-natural gas(1)		$	45,300			$	(7,219	)		$	127,283			$	(48,062	)
Realized (loss) on commodity derivatives-crude oil(1)			—				(1,479	)			—				(6,881	)
Unrealized (loss) gain on commodity derivatives(1)			(35,910	)			40,750				(84,675	)			26,620
Total gain (loss) on commodity derivatives		$	9,390			$	32,052			$	42,608			$	(28,323	)

 

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

 

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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, 2015. There were no changes in the Company’s internal control over financial reporting during the quarter ended September 30, 2015 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, 2014.

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

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

 

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ITEM 6. EXHIBITS

(a) Exhibits

 

3.1		Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
3.2		By-Laws of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
3.3		Articles of Amendment to Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.3 of the Company’s Report on Form 10-K/A for the period ended December 31, 2005.)
4.1		Specimen Common Share Certificate — (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)
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.

 

				ULTRA PETROLEUM CORP.
				By:		/s/ Michael D. Watford
						Name:		Michael D. Watford
						Title:		Chairman, President and
								Chief Executive Officer
Date: October 29, 2015
				By:		/s/ Garland R. Shaw
						Name:		Garland R. Shaw
						Title:		Senior Vice President and
								Chief Financial Officer

Date: October 29, 2015

 

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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.)
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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