UNITED STATES SECURITIES AND EXCHANGE COMMISSION

 

Washington, D.C. 20549

 

Form 10-Q

 

 

 

 

Commission file number 001-33614

 

 

ULTRA PETROLEUM CORP.

(Exact name of registrant as specified in its charter)

 

 

 

(281) 876-0120
(Registrant’s telephone number, including area code)

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  YES þ     NO o

 

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  YES þ     NO o

 

 

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):

 

 

(Do not check if a smaller reporting company)

 

 

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

 

 

The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of October 25, 2011 was 152,717,724.

 

 

 

TABLE OF CONTENTS

 

 

 

ULTRA PETROLEUM CORP.

 

CONSOLIDATED STATEMENTS OF INCOME

 

 

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

 

CONSOLIDATED BALANCE SHEETS

 

 

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

 

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

 

DESCRIPTION OF THE BUSINESS:

 

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

 

 

The accompanying financial statements, other than the balance sheet data as of December 31, 2010, 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, 2010 was derived from the Company’s audited financial statements. The Company’s management believes that these financial statements include all adjustments necessary for a fair presentation of the Company’s financial position and results of operations. All adjustments are of a normal and recurring nature unless specifically noted. The Company prepared these statements on a basis consistent with the Company’s annual audited statements and Regulation S-X. Regulation S-X allows the Company to omit some of the footnote and policy disclosures required by generally accepted accounting principles and normally included in annual reports on Form 10-K. You should read these interim financial statements together with the financial statements, summary of significant accounting policies and notes to the Company’s most recent annual report on Form 10-K.

 

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

 

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

 

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

 

(c) Property, Plant and Equipment:  Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life. Gathering system expenditures are recorded at cost and depreciated using the straight-line method based on a 30-year useful life.

 

(d) Oil and Natural Gas Properties:  The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”) Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”) and Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities — Oil and Gas (“FASB ASC 932”). Under this method of accounting, the costs of 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.

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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

 

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

 

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

 

(e) Inventories:  Materials and supplies inventories are carried at lower of cost or market. Inventory costs include expenditures and other charges directly and indirectly incurred in bringing the inventory to its existing condition and location. The Company uses the weighted average method of recording its inventory. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. At September 30, 2011, inventory of $1.5 million primarily included the cost of pipe and production equipment that are expected to be utilized during the 2011 and 2012 drilling programs.

 

(f) Derivative Instruments and Hedging Activities:  Currently, the Company largely relies on commodity derivative contracts to manage its exposure to commodity price risk. These commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties. Additionally, and from time to time, the Company enters into physical, fixed price forward natural gas sales in order to mitigate its commodity price exposure on a portion of its natural gas production. These fixed price forward natural gas sales are considered normal sales in the ordinary course of business and outside the scope of FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”). The Company does not offset the value of its derivative arrangements with the same counterparty. (See Note 6).

 

(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

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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.

 

 

(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 changes in service and equipment costs and changes in the estimated timing of settling asset retirement obligations.

 

(m) Revenue Recognition:  Natural gas revenues are recorded based on the entitlement method. Under the entitlement method, revenue is recorded when title passes based on the Company’s net revenue interest. The Company initially records its entitled share of revenues based on estimated production volumes. Subsequently, these estimated volumes are adjusted to reflect actual volumes that are supported by third party pipeline statements

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

or cash receipts. Since there is a ready market for natural gas, the Company sells the majority of its products immediately after production at various locations at which time title and risk of loss pass to the buyer. Gas imbalances occur when the Company sells more or less than its entitled ownership percentage of total gas production. 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.

 

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

 

(o) Capital Cost Accrual:  The Company accrues for exploration and development costs in the period incurred, while payment may occur in a subsequent period.

 

 

 

 

 

 

 

Bank indebtedness:  At September 30, 2011, the Company (through its subsidiary, Ultra Resources) was a party to a revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. which was to mature in April 2012 (the “2007 Credit Agreement”). On October 6, 2011, in anticipation of the upcoming maturity of the 2007 Credit Agreement, the Company, through Ultra Resources (the “Borrower”), replaced the 2007 Credit Agreement in its entirety with a senior unsecured revolving credit facility with JP Morgan Chase Bank, N.A. as administrative agent, and the lenders party thereto (the “2011 Credit Agreement”) and repaid all amounts outstanding under the 2007 Credit Agreement with proceeds of loans drawn under the 2011 Credit Agreement. (For a description of the 2011 Credit Agreement, see Note 9).

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The 2007 Credit Agreement provided an initial loan commitment of $500.0 million. Loans under the 2007 Credit Agreement were unsecured and bore interest, at the Company’s option, based on (A) a rate per annum equal to the higher of the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 50 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 (125 basis points per annum as of September 30, 2011).

 

At September 30, 2011, the Company had $278.0 million in outstanding borrowings and $222.0 million of available borrowing capacity under the 2007 Credit Agreement.

 

The 2007 Credit Agreement had restrictive covenants that included the maintenance of a ratio of consolidated funded debt to EBITDAX (earnings before interest, taxes, DD&A and other non-cash charges) not to exceed three and one half times; and as long as the Company’s debt rating was 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 at least 1.75 to 1.00. At September 30, 2011, the Company was in compliance with all of its debt covenants under the 2007 Credit Agreement.

 

Senior Notes:  The Senior Notes rank pari passu with the Company’s 2007 Credit Agreement and the 2011 Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. The Senior Notes are pre-payable in whole or in part at any time and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At September 30, 2011, the Company was in compliance with all of its debt covenants under the Master Note Purchase Agreement for Senior Notes.

 

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

 

 

Valuation and Expense Information

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Changes in Stock Options and Stock Options Outstanding

 

The following table summarizes the changes in stock options for the nine months ended September 30, 2011 and the year ended December 31, 2010:

 

 

PERFORMANCE SHARE PLANS:

 

Long Term Incentive Plans.  The Company offers a Long Term Incentive Plan (“LTIP”) in order to further align the interests of key employees with shareholders and to give key employees the opportunity to share in the long-term performance of the Company when specific corporate financial and operational goals are achieved. Each LTIP covers a performance period of three years. In 2009, 2010 and 2011, the Compensation Committee (the “Committee”) approved an award consisting of performance-based restricted stock units to be awarded to each participant.

 

For each LTIP award, the Committee establishes performance measures at the beginning of each performance period. Under each LTIP, the Committee establishes a percentage of base salary for each participant which is multiplied by the participant’s base salary to derive a Long Term Incentive Value as a “target” value which corresponds to the number of shares of the Company’s common stock the participant is eligible to receive if the target level for all performance measures is met. In addition, each participant is assigned threshold and maximum award levels in the event that actual performance is below or above target levels. For LTIP awards in each of 2009, 2010, and 2011 the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth.

 

For the nine months ended September 30, 2011, the Company recognized $7.5 million in pre-tax compensation expense related to the 2009, 2010 and 2011 LTIP awards of restricted stock units as compared to $5.9 million during the nine months ended September 30, 2010 related to the 2008, 2009 and 2010 LTIP awards of restricted stock units. The amounts recognized during the nine months ended September 30, 2011 assumes that maximum performance objectives are attained. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at September 30, 2011, for each of the three year performance periods is expected to be approximately $23.8 million, $11.5 million, and $11.2 million related to the 2009, 2010 and 2011 LTIP awards of restricted stock units, respectively. The 2008 LTIP award of restricted stock units was paid in shares of the Company’s stock to employees during the first quarter of 2011 and totaled $4.3 million (41,443 net shares).

 

 

During the quarter ended September 30, 2011, the Company recorded an income tax provision of $81.7 million, or 35.4% of income before income tax provision. This compares to an income tax provision of $88.1 million, or 35.1% of income before income tax provision for the quarter ended September 30, 2010. The effective tax rate

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

increased over the comparable prior period primarily due to elevated activity levels in the higher state tax jurisdiction of Pennsylvania and offset in part due to certain reconciling items related to the filing of the 2010 U.S. Income Tax return in the third quarter of 2011.

 

During the nine months ended September 30, 2011, the Company recorded an income tax provision of $183.4 million, or 36.3% of income before income tax provision. This compares to an income tax provision of $238.5 million, or 35.9% of income before income tax provision for the nine months ended September 30, 2010. The effective tax rate increased over the comparable prior period primarily due to elevated activity levels in the higher state tax jurisdiction of Pennsylvania as the higher effective tax rate is now being applied to the Company’s prior temporary differences which increased the overall effective tax rate.

 

 

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

 

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

 

The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval. The Board has approved hedging greater than 50% of the Company’s forecast 2011 production.

 

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

 

Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at fair value on the balance sheet and the associated unrealized gains and losses are recorded as current income or expense in the income statement. 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, 2011, the Company had the following open commodity derivative contracts to manage price risk on a portion of its natural gas production whereby the Company receives the fixed price and pays the variable price. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties.

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The following table summarizes the pre-tax realized and unrealized gains the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010:

 

 

 

 

 

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

 

Level 1:  Quoted prices (unadjusted) in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.

 

Level 2:  Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter forwards and swaps.

 

Level 3:  Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.

 

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

 

The following table presents for each hierarchy level the Company’s assets, including both current and non-current portions, measured at fair value on a recurring basis, as of September 30, 2011. The Company has no derivative instruments which qualify for cash flow hedge accounting.

 

 

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.

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Fair Value of Financial Instruments

 

The estimated fair value of financial instruments is the estimated amount at which the instrument could be exchanged currently between willing parties. The carrying amounts reported in the consolidated balance sheet for cash and cash equivalents, accounts receivable, accounts payable and current portion of long-term debt 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 debt. 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.

 

 

 

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.

 

 

FASB ASC Topic 855, Subsequent Events (“FASB ASC 855”), sets forth principles and requirements to be applied to the accounting for and disclosure of subsequent events. FASB ASC 855 sets forth the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, the circumstances under which events or transactions occurring after the balance sheet date shall be recognized in the financial statements and the required disclosures about events or transactions that occurred after the balance sheet date. The Company has evaluated the period subsequent to September 30, 2011 for events that did not exist at the balance sheet date but arose after that date and determined that no subsequent events other than those discussed below arose that should be disclosed in order to keep the financial statements from being misleading.

 

On October 6, 2011, in anticipation of the upcoming maturity of the Company’s (through its subsidiary, Ultra Resources) senior unsecured revolving credit agreement dated April 30, 2007 with a syndicate of banks led by JP Morgan Chase Bank, N.A., the Company, through Ultra Resources, replaced the 2007 Credit Agreement in its entirety with a senior unsecured revolving credit facility with JP Morgan Chase Bank, N.A. as administrative agent, and the lenders party thereto and repaid all amounts outstanding under the 2007 Credit Agreement with proceeds of loans drawn under the 2011 Credit Agreement.

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The 2011 Credit Agreement reflects an increased borrowing capacity as compared to the 2007 Credit Agreement with an initial loan commitment of $1.0 billion (which may be increased up to $1.25 billion at the request of the Borrower and with the lenders’ consent), provides for the issuance of letters of credit of up to $250.0 million in aggregate, and matures in five years (which term may be extended for up to two successive one-year periods at the Borrower’s request and with the lenders’ consent).

 

Loans under the 2011 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 50 basis points, or (B) a base Eurodollar rate, substantially equal to the LIBOR rate, in either case plus a margin based on a grid of the Borrower’s consolidated leverage ratio (for Eurodollar borrowings, 175 basis points per annum as of October 6, 2011).

 

The 2011 Credit Agreement contains typical and customary representations, warranties, covenants and events of default. The 2011 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.

 

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

 

Overview

 

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

 

The Company currently conducts operations exclusively in the United States. Substantially all of its oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect only the Company’s proportionate interest in such activities. Inflation has not had a material impact on the Company’s results of operations and is not expected to have a material impact on the Company’s results of operations in the future.

 

The Company currently generates substantially all of its revenue, earnings and cash flow from the production and sales of natural gas and oil. An increasing portion of the Company’s revenues is associated with natural gas sales from wells located in the Appalachian Basin in Pennsylvania.

 

The price of natural gas is a critical factor to the Company’s business and the price of natural gas has historically been volatile. Volatility could be detrimental to the Company’s financial performance. The Company seeks to limit the impact of this volatility on its results by entering into fixed price forward physical delivery contracts and swap agreements for natural gas. During the quarter ended September 30, 2011, the average price realization for the Company’s natural gas was $5.17 per Mcf, including realized gains and losses on commodity derivatives. The Company’s average price realization for natural gas was $4.29 per Mcf, excluding the realized gains and losses on commodity derivatives. (See Note 6).

 

The Company has consistently delivered meaningful reserve and production growth over the past twelve years and management believes it has the ability to continue growing production by drilling already identified locations on its core properties. Ultra maintains a portfolio of properties that provide long-term growth through development in areas that support sustainable, lower-risk, repeatable, high return drilling projects. The Company delivered 14% production growth on a gas equivalent basis during the quarter ended September 30, 2011 as compared to the same quarter in 2010.

 

Critical Accounting Policies

 

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

 

Derivative Instruments and Hedging Activities.  Currently, the Company largely relies on derivative instruments (generally, financial swaps) to manage its exposure to commodity price risk. Additionally, and from time to time, the Company enters into fixed price forward natural gas sales in order to mitigate its commodity price exposure on a portion of its natural gas production. These fixed price forward gas sales are considered normal sales in the ordinary course of business and outside the scope of Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging (“FASB ASC 815”).

The Company records the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, and records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Income as an unrealized gain or loss on commodity derivatives.

 

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

 

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

 

The fair values summarized below were determined in accordance with the requirements of FASB ASC 820 and the Company aligned the categories below with the Level 1, 2, and 3 fair value measurements as defined by FASB ASC 820. The balance of net unrealized gains and losses recognized for the Company’s energy-related derivative instruments at September 30, 2011 is summarized in the following table based on the inputs used to determine fair value:

 

 

 

 

Asset Retirement Obligation.  The Company’s asset retirement obligations (“ARO”) consist primarily of estimated costs of dismantlement, removal, site reclamation and similar activities associated with its oil and natural gas properties. FASB ASC Topic 410, Asset Retirement and Environmental Obligations (“FASB ASC 410”) requires that the discounted fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and natural gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements; the credit-adjusted, risk-free rate to be used; inflation rates, and future advances in technology. In periods subsequent to initial measurement of the ARO, the Company must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to the passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through depletion, depreciation and amortization (“DD&A”).

 

Share-Based Payment Arrangements.  The Company applies FASB ASC Topic 718, Compensation — Stock Compensation (“FASB ASC 718”), which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors, including employee stock options, based on estimated fair values. Share-based compensation expense recognized for the nine months ended September 30, 2011 and 2010 was $9.9 million and $9.1 million, respectively. At September 30, 2011, there was no unrecognized compensation cost related to non-vested share-based compensation arrangements granted under stock option plans. See Note 4 for additional information.

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

 

Companies that use the full cost method of accounting for oil and natural gas exploration and development activities are required to perform a ceiling test calculation each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed quarterly, on a country-by-country basis, utilizing the average of prices in effect on the first day of the month for the preceding twelve month period in accordance with SEC Release No. 33-8995. The ceiling limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved crude oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties less any associated tax effects. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to earnings. Any such write-down will reduce earnings in the period of occurrence and results in a lower DD&A rate in future periods. A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not have any write-downs related to the full cost ceiling limitation during the nine months ended September 30, 2011 or 2010.

 

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

 

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

 

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.

 

RESULTS OF OPERATIONS

 

Quarter Ended September 30, 2011 vs. Quarter Ended September 30, 2010

 

During the quarter ended September 30, 2011, production increased 14% on a gas equivalent basis to 63.4 Bcfe from 55.4 Bcfe for the same quarter in 2010. This increase in production was attributable to the Company’s successful drilling activities during 2010 and in the first nine months of 2011. Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 7% to $5.17 per Mcf in the third quarter of 2011 as compared to $4.84 per Mcf for the same quarter of 2010. During the three months ended September 30, 2011, the Company’s average price for natural gas was $4.29 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $4.08 per Mcf for the same period in 2010. The increase in average natural gas prices together with the increase in production contributed to a 22% increase in revenues to $293.1 million as compared to $240.4 million in 2010.

Lease operating expense (“LOE”) increased to $12.4 million during the third quarter of 2011 compared to $10.9 million during the same period in 2010 primarily due to increased production volumes. On a unit of production basis, LOE costs remained flat at $0.20 per Mcfe at September 30, 2011 compared to September 30, 2010.

 

During the three months ended September 30, 2011, production taxes were $25.7 million compared to $23.2 million during the same period in 2010. Production taxes are calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 8.8% of revenues for the quarter ended September 30, 2011 and 9.6% of revenues for the same period in 2010. During the three months ended September 30, 2011, the Company’s average price for natural gas was $4.29 per Mcf, excluding realized gains and losses on commodity derivatives, as compared to $4.08 per Mcf for the same period in 2010. Production taxes were $0.40 per Mcfe compared to $0.42 per Mcfe for the three months ended September 30, 2011 and 2010, respectively. The decrease in per unit costs is primarily attributable to increased production in Pennsylvania, which is not subject to production taxes.

 

Gathering fees increased to $14.4 million for the three months ended September 30, 2011 compared to $12.6 million during the same period in 2010 largely due to increased production volumes. On a per unit basis, gathering fees remained flat at $0.23 per Mcfe for the three months ended September 30, 2011 and 2010.

 

To secure pipeline infrastructure providing sufficient capacity to transport a portion of the Company’s natural gas production into relatively higher priced Northeastern markets and to provide for reasonable basis differentials for its natural gas, the Company incurred firm transportation charges totaling $16.1 million for the quarter ended September 30, 2011 as compared to $16.2 million for the same period in 2010 in association with Rockies Express Pipeline (“REX”). On a per unit basis, transportation charges decreased to $0.25 per Mcfe (on total company volumes) for the three months ended September 30, 2011 as compared to $0.29 per Mcfe (on total company volumes) for the same period in 2010 due to the increase in production volumes during the quarter ended September 30, 2011.

 

DD&A expenses increased to $85.8 million during the three months ended September 30, 2011 from $59.7 million for the same period in 2010, attributable primarily to increased production volumes and a higher depletion rate. On a unit of production basis, DD&A increased to $1.35 per Mcfe for the quarter ended September 30, 2011 from $1.08 per Mcfe for the quarter ended September 30, 2010 largely as a result of increased well costs in Pennsylvania.

 

General and administrative expenses remained relatively flat at $6.2 million for the quarter ended September 30, 2011 compared to $6.0 million for the same period in 2010. On a per unit basis, general and administrative expenses decreased to $0.10 per Mcfe for the quarter ended September 30, 2011 as compared to $0.11 per Mcfe for the quarter ended September 30, 2010 as a result of increased production volumes during the quarter ended September 30, 2011.

 

Interest expense increased to $15.9 million during the quarter ended September 30, 2011 compared to $11.4 million during the same period in 2010 as a result of increased borrowings outstanding during the period ended September 30, 2011. At September 30, 2011, the Company had $1.8 billion in borrowings outstanding. In addition, the Company capitalized $7.4 million and $6.5 million in interest expense for the quarters ended September 30, 2011 and 2010, respectively, related to unevaluated oil and gas properties and work in process relating to gathering systems that are not currently in service (See Note 2).

 

During the quarter ended September 30, 2011, the Company recognized $53.6 million of realized gain on commodity derivatives as compared to $40.6 million of realized gain on commodity derivatives during the quarter ended September 30, 2010. The realized gain on commodity derivatives relates to actual amounts received under these derivative contracts.

 

During the quarter ended September 30, 2011, the Company recorded $60.5 million in unrealized gain on commodity derivatives as compared to $109.6 million in unrealized gain on commodity derivatives during the quarter ended September 30, 2010. The unrealized gain on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

The Company recognized income before income taxes of $230.9 million for the quarter ended September 30, 2011 compared with income before income taxes of $250.7 million for the same period in 2010. The decrease in earnings is primarily related to the change in the unrealized gain on commodity derivatives during the quarter ended September 30, 2011 as compared to the same period in 2010 and offset in part by the increase in revenues as a result of the increase in production together with increased average natural gas prices and realized gain on commodity derivatives.

 

The income tax provision recognized for the quarter ended September 30, 2011 was $81.7 million compared with $88.1 million for the three months ended September 30, 2010. The decrease is primarily related to the change in the unrealized gain on commodity derivatives during the quarter ended September 30, 2011 as compared to the same period in 2010 offset in part by the increase in revenues as a result of the increase in production together with increased average natural gas prices and realized gain on commodity derivatives. The effective tax rate for the nine months ended September 30, 2011 increased as compared to the prior period primarily due to elevated activity levels in the higher state tax rate jurisdiction of Pennsylvania and offset in part due to certain reconciling items related to the filing of the 2010 U.S. Income Tax return in the third quarter of 2011.

 

For the three months ended September 30, 2011, the Company recognized net income of $149.1 million or $0.97 per diluted share as compared with net income of $162.6 million or $1.05 per diluted share for the same period in 2010. The decrease is primarily related to the change in the unrealized gain on commodity derivatives during the quarter ended September 30, 2011 as compared to the same period in 2010 offset in part by increased revenues as a result of the increase in production together with increased average natural gas prices and realized gain on commodity derivatives.

 

Nine Months Ended September 30, 2011 vs. Nine Months Ended September 30, 2010

 

During the nine months ended September 30, 2011, production increased 14% on a gas equivalent basis to 178.4 Bcfe from 156.4 Bcfe for the same period in 2010 attributable to the Company’s successful drilling activities during 2010 and in the first nine months of 2011. Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 3% to $5.15 per Mcf in the nine months ended September 30, 2011 as compared to $5.00 per Mcf for the same period in 2010. During the nine months ended September 30, 2011, the Company’s average price for natural gas was $4.32 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $4.49 per Mcf for the same period in 2010. The increase in production offset in part by the decrease in average natural gas prices, excluding realized gains and losses on commodity derivatives, contributed to a 12% increase in revenues to $831.0 million as compared to $741.9 million in 2010.

 

LOE increased to $35.9 million during the nine months ended September 30, 2011 compared to $32.7 million during the same period in 2010 largely due to increased production. On a unit of production basis, LOE costs decreased to $0.20 per Mcfe at September 30, 2011 compared to $0.21 per Mcfe at September 30, 2010 primarily due to increased production volumes together with lower water handling costs as a result of the initiation of the second phase of the liquids gathering system of the Company’s condensate and water gathering facilities in Wyoming during 2011.

 

During the nine months ended September 30, 2011, production taxes were $73.8 million compared to $74.1 million during the same period in 2010. Production taxes are calculated based on a percentage of revenue from production in Wyoming after certain deductions and were 8.9% of revenues for the nine months ended September 30, 2011 compared with 10.0% for the same period in 2010. During the nine months ended September 30, 2011, the Company’s average price for natural gas was $4.32 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $4.49 per Mcf for the same period in 2010. Production taxes were $0.41 per Mcfe compared to $0.47 per Mcfe for the nine months ended September 30, 2011 and 2010, respectively. The decrease in per unit taxes is primarily attributable to increased production in Pennsylvania, which is not subject to production taxes, as well as the decrease in average natural gas prices, excluding the effects of commodity derivatives, during the nine months ended September 30, 2011 as compared to the same period in 2010.

 

Gathering fees increased to $41.4 million for the nine months ended September 30, 2011 compared to $37.1 million during the same period in 2010 largely due to increased production volumes. On a per unit basis, gathering fees decreased to $0.23 per Mcfe for the nine months ended September 30, 2011 as compared to $0.24 per

Mcfe during the same period in 2010 as a result of increased production in Pennsylvania, which is subject to lower average gathering fees.

 

To secure pipeline infrastructure providing sufficient capacity to transport a portion of the Company’s natural gas production into relatively higher priced Northeastern markets and to provide for reasonable basis differentials for its natural gas, the Company incurred firm transportation charges totaling $48.5 million and $48.6 million for the nine months ended September 30, 2011 and 2010, respectively, in association with the REX pipeline. On a per unit basis, transportation charges decreased to $0.27 per Mcfe (on total company volumes) for the nine months ended September 30, 2011 as compared to $0.31 per Mcfe (on total company volumes) for the same period in 2010 due to the increase in production volumes during the period ended September 30, 2011.

 

DD&A expenses increased to $238.8 million during the nine months ended September 30, 2011 from $167.8 million for the same period in 2010, attributable primarily to increased production volumes and a higher depletion rate. On a unit of production basis, DD&A increased to $1.34 per Mcfe for the nine months ended September 30, 2011 from $1.07 per Mcfe for the nine months ended September 30, 2010 largely as a result of increased well costs in Pennsylvania.

 

General and administrative expenses increased to $19.3 million for the nine months ended September 30, 2011 compared to $18.5 million for the same period in 2010. The increase in general and administrative expenses is primarily attributable to increased headcount and related compensation. On a per unit basis, general and administrative expenses decreased to $0.11 per Mcfe for the nine months ended September 30, 2011 compared with $0.12 per Mcfe for the same period in 2010 as a result of increased production volumes during the period ended September 30, 2011.

 

Interest expense increased to $46.1 million during the nine months ended September 30, 2011 compared to $34.5 million during the same period in 2010 as a result of increased borrowings outstanding during the period ended September 30, 2011. At September 30, 2011, the Company had $1.8 billion in borrowings outstanding. In addition, the Company capitalized $22.9 million and $13.9 million in interest expense for the nine months ended September 30, 2011 and 2010, respectively, related to unevaluated oil and gas properties and work in process relating to gathering systems that are not currently in service (See Note 2).

 

During the nine months ended September 30, 2011, the Company recognized $143.7 million of realized gain on commodity derivatives as compared to $77.6 million of realized gain on commodity derivatives during the nine months ended September 30, 2010. The realized gain on commodity derivatives relates to actual amounts received under these derivative contracts.

 

During the nine months ended September 30, 2011, the Company recorded $33.7 million in unrealized gain on commodity derivatives as compared to $268.5 million in unrealized gain on commodity derivatives during the nine months ended September 30, 2010. The unrealized gain on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

 

During the nine months ended September 30, 2010, the Company recognized litigation expenses of $9.9 million related to the resolution of litigation matters.

 

The Company recognized income before income taxes of $504.8 million for the nine months ended September 30, 2011 compared with income before income taxes of $665.0 million for the same period in 2010. The decrease in earnings is primarily related to the change in the unrealized gain on commodity derivatives during the nine months ended September 30, 2011 as compared to the same period in 2010 offset in part by increased production and realized gain on commodity derivatives during the nine months ended September 30, 2011.

 

The income tax provision recognized for the nine months ended September 30, 2011 was $183.4 million compared with $238.5 million for the same period in 2010. The decrease is largely a result of the change in the unrealized gain on commodity derivatives during the nine months ended September 30, 2011 as compared to the same period in 2010 offset in part by the increase in production and realized gain on commodity derivatives during the nine months ended September 30, 2011 as compared to the same period in 2010. The effective tax rate for the

nine months ended September 30, 2011 increased as compared to the prior period primarily due to elevated activity levels in the higher state tax rate jurisdiction of Pennsylvania.

 

For the nine months ended September 30, 2011, the Company recognized net income of $321.4 million or $2.08 per diluted share as compared with net income of $426.5 million or $2.77 per diluted share for the same period in 2010. The decrease is primarily attributable to the change in the unrealized gain on commodity derivatives offset in part by increased production and realized gain on commodity derivatives during the nine months ended September 30, 2011 as compared to the same period in 2010.

 

LIQUIDITY AND CAPITAL RESOURCES

 

During the nine month period ended September 30, 2011, the Company relied on cash provided by operations along with borrowings under the 2007 Credit Agreement to finance its capital expenditures. During this period, the Company participated in 355 gross (186.9 net) wells that were drilled to total depth and cased in Wyoming and Pennsylvania. For the nine month period ended September 30, 2011, total capital expenditures were $1.1 billion ($1.08 billion related to oil and gas exploration and development expenditures and $35.2 million related to gathering system expenditures).

 

At September 30, 2011, the Company reported a cash position of $12.3 million compared to $7.2 million at September 30, 2010. Working capital deficit at September 30, 2011 was $454.0 million compared to working capital deficit of $105.5 million at September 30, 2010. At September 30, 2011, the Company had $278.0 million in outstanding borrowings and $222.0 million of available borrowing capacity under the 2007 Credit Agreement (defined below). In addition, the Company had $1.56 billion outstanding under its Senior Notes (See Note 3). Other long-term obligations of $77.0 million at September 30, 2011 was comprised of items payable in more than one year, primarily related to production taxes and asset retirement obligations.

 

The Company’s available cash, credit facility (see Note 9) and cash generated from operations, are projected to be sufficient to meet the Company’s obligations and to fund the budgeted capital investment program for 2011, which is currently projected to be $1.35 billion.

 

Bank indebtedness:  At September 30, 2011, the Company (through its subsidiary, Ultra Resources) was a party to a revolving credit facility with a syndicate of banks led by JP Morgan Chase Bank, N.A. which matures in April 2012 (the “2007 Credit Agreement”). On October 6, 2011, in anticipation of the upcoming maturity of the 2007 Credit Agreement, the Company, through Ultra Resources (the “Borrower”), replaced the 2007 Credit Agreement in its entirety with a senior unsecured revolving credit facility with JP Morgan Chase Bank, N.A. as administrative agent, and the lenders party thereto (the “2011 Credit Agreement”) and repaid all amounts outstanding under the 2007 Credit Agreement with proceeds of loans drawn under the 2011 Credit Agreement. (For a description of the 2011 Credit Agreement, see Note 9 in the Notes to Consolidated Financial Statements herein).

 

The 2007 Credit Agreement provided an initial loan commitment of $500.0 million. Loans under the 2007 Credit Agreement were unsecured and bore interest, at the Company’s option, based on (A) a rate per annum equal to the higher of the prime rate or the weighted average fed funds rate on overnight transactions during the preceding business day plus 50 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 (125 basis points per annum as of September 30, 2011).

 

At September 30, 2011, the Company had $278.0 million in outstanding borrowings and $222.0 million of available borrowing capacity under the 2007 Credit Agreement.

 

The 2007 Credit Agreement had restrictive covenants that included the maintenance of a ratio of consolidated funded debt to EBITDAX (earnings before interest, taxes, DD&A and other non-cash charges) not to exceed three and one half times; and as long as the Company’s debt rating was 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 at least 1.75 to 1.00. At September 30, 2011, the Company was in compliance with all of its debt covenants under the 2007 Credit Agreement.

Senior Notes:  The Senior Notes rank pari passu with the Company’s 2007 Credit Agreement and the 2011 Credit Agreement. Payment of the Senior Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. The Senior Notes are pre-payable in whole or in part at any time and are subject to representations, warranties, covenants and events of default customary for a senior note financing. At September 30, 2011, the Company was in compliance with all of its debt covenants under the Master Note Purchase Agreement (See Note 3).

 

Operating Activities.  During the nine months ended September 30, 2011, net cash provided by operating activities was $719.8 million, a 19% increase from $604.1 million for the same period in 2010. The increase in net cash provided by operating activities is largely attributable to increased production and increased revenues including realized gains on commodity derivatives during the nine months ended September 30, 2011 as compared to the same period in 2010.

 

Investing Activities.  During the nine months ended September 30, 2011, net cash used in investing activities was $1.0 billion as compared to $1.1 billion for the same period in 2010. The decrease in net cash used in investing activities is largely associated with the Pennsylvania Marcellus Shale acquisition in February 2010 and offset by increased capital investments associated with the Company’s drilling activities in 2011 as compared to 2010.

 

Financing Activities.  During the nine months ended September 30, 2011, net cash provided by financing activities was $265.5 million as compared to $527.0 million for the same period in 2010. The decrease in net cash provided by financing activities is largely due to decreased borrowings in 2011 as compared to 2010, primarily attributable to the Senior Notes offering during the nine months ended September 30, 2010.

 

OFF BALANCE SHEET ARRANGEMENTS

 

The Company did not have any off-balance sheet arrangements as of September 30, 2011.

 

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, 2010 for additional risks related to the Company’s business.

 

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.

 

From time to time, the Company may use fixed price forward gas sales to manage its commodity price exposure. These fixed price forward gas sales are considered normal sales in the ordinary course of business and outside the scope of FASB ASC 815, Derivatives and Hedging.

 

The Company’s hedging policy limits the amounts of resources hedged to not more than 50% of its forecast production without Board approval. The Board has approved hedging greater than 50% of the Company’s forecast 2011 production.

 

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

 

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

 

Commodity Derivative Contracts:  At September 30, 2011, the Company had the following open commodity derivative contracts to manage price risk on a portion of its natural gas production whereby the Company receives the fixed price and pays the variable price. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties.

 

 

The following table summarizes the pre-tax realized and unrealized gains the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010:

 

 

 

 

 

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, 2011. There were no changes in the Company’s internal control over financial reporting during the nine months ended September 30, 2011 that have materially affected or are reasonably likely to affect, the Company’s internal control over financial reporting.

 

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.

 

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, 2010.

 

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

 

 

None.

 

On November 2, 2011, Robert E. Rigney, a director of the Company, submitted his resignation to the Board of Directors. Mr. Rigney also resigned from the Company’s Audit Committee and Compensation Committee. Mr. Rigney’s departure is not related to any disagreement with the Company or with the Company’s operations, policies or practices.

 

 

 

 

 

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.

 

Name:     Michael D. Watford

Chief Executive Officer

 

Date: November 4, 2011

 

Name:     Marshall D. Smith

Chief Financial Officer

 

Date: November 4, 2011