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 27, 2010 was 152,481,063.

 

 

TABLE OF CONTENTS

 

 

 

ULTRA PETROLEUM CORP.

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

 

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, 2009, 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, 2009 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.

 

Long-term restricted cash at December 31, 2009 represents cash that was set aside in an escrow account in connection with the purchase of additional acreage in the Marcellus Shale, which closed on February 22, 2010.

 

(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:  On January 6, 2010, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”), Oil and Gas Reserve Estimation and Disclosures. The ASU amends FASB Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities — Oil and Gas (“FASB ASC 932”) to align the reserve calculation and disclosure requirements of FASB ASC 932 with the requirements in the SEC Release No. 33-8995, Modernization of Oil and Gas Reporting Requirements (“SEC Release No. 33-8995”).

 

The ASU was effective for reporting periods ending on or after December 31, 2009. Accordingly, the Company adopted the update to FASB ASC 932 as of December 31, 2009.

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). 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 proved reserves as determined by independent petroleum engineers. 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 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 cost. 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, 2010, drilling and completion supplies inventory of $4.7 million primarily included the cost of pipe and production equipment that are expected to be utilized during the 2010 and 2011 drilling programs.

 

(f) Derivative Instruments and Hedging Activities:  Currently, the Company largely relies on derivative instruments to manage its exposure to commodity price risk. The natural gas reference prices of the Company’s 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 fixed price forward gas sales agreements 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 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 7).

 

(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

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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, we recognize 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.

 

 

 

 

(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 in generally accepted accounting principles, and describes disclosures about fair value measurements. This statement applies under other accounting topics that require or permit fair value measurements. For non-financial assets and liabilities measured or disclosed at fair value on a non-recurring basis, primarily our asset retirement obligation, the respective subtopic of FASB ASC 820, was effective January 1, 2009.

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Implementation of this portion of the standard did not have a material impact on consolidated results of operations, financial position or liquidity. See Note 8 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.

 

(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 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 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) Reclassifications:  Certain amounts in the financial statements of prior periods have been reclassified to conform to the current period financial statement presentation.

 

 

Other comprehensive income (loss) is a term used to define revenues, expenses, gains and losses that under generally accepted accounting principles impact Shareholders’ Equity, excluding transactions with shareholders.

 

 

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

 

 

 

 

Bank indebtedness:  The Company (through its subsidiary) is 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. This agreement provides an initial loan commitment of $500.0 million and may be increased to a maximum aggregate amount of $750.0 million at the request of the Company. Each bank has the right, but not the obligation, to increase the amount of its commitment as requested by the Company. In the event the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to add new financial institutions to the credit facility.

 

Loans under the credit facility are unsecured and bear 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 Company’s consolidated leverage ratio (125.0 basis points per annum as of September 30, 2010).

 

At September 30, 2010, the Company had $291.0 million in outstanding borrowings and $209.0 million of available borrowing capacity under the credit facility.

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The facility has restrictive covenants that include the maintenance of a ratio of consolidated funded debt to EBITDAX (earnings before interest, taxes, DD&A and exploration expense) not to exceed three and one half times; 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 at least 1.75 to 1.00. At September 30, 2010, the Company was in compliance with all of its debt covenants under the credit facility.

 

Senior Notes:  On January 28, 2010, Ultra Resources, Inc., issued $500.0 million of Senior Notes (“the 2010A Senior Notes”) pursuant to a Second Supplement to the Master Note Purchase Agreement between the Company and the purchasers of the Notes. The Senior Notes rank pari passu with the Company’s bank credit facility. 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, 2010, the Company was in compliance with all of its debt covenants under the Master Note Purchase Agreement.

 

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

 

 

The fair value of each share option award is estimated on the date of grant using a Black-Scholes pricing model. The Company’s employee stock options have various restrictions including vesting provisions and restrictions on transfers and hedging, among others, and are often exercised prior to their contractual maturity. Expected volatilities used in the fair value estimates are based on historical volatility of the Company’s stock. The Company uses historical data to estimate share option exercises, expected term and employee departure behavior used in the Black-Scholes pricing model. Groups of employees (executives and non-executives) that have similar historical behavior are considered separately for purposes of determining the expected term used to estimate fair value. The assumptions utilized result from differing pre- and post-vesting behaviors among executive and non-executive groups. The risk-free rate for periods within the contractual term of the share option is based on the U.S. Treasury yield curve in effect at the time of grant. There were no stock options granted during the nine months ended September 30, 2010 or 2009.

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, 2010 and the year ended December 31, 2009:

 

PERFORMANCE SHARE PLANS:

 

Long Term Incentive Plans.  Each year since 2005, the Company has adopted 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. The 2008 LTIP has two components: an “LTIP Stock Option Award” and an “LTIP Common Stock Award.” In 2009 and 2010, the Compensation Committee (the “Committee”) approved an award consisting only of performance-based restricted stock units to be awarded to each participant.

 

Under each LTIP, the Compensation 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. The LTIP Common Stock Award in 2008 and the 2009 and 2010 LTIP award of restricted stock units are performance-based and are measured over a three year performance period. For each LTIP award, the Compensation Committee establishes performance measures at the beginning of each performance period, and each participant is assigned threshold and maximum award levels in the event that actual performance is below or above target levels. For the 2008, 2009 and 2010 LTIP awards, the Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth.

 

For the nine months ended September 30, 2010, the Company recognized $5.9 million in pre-tax compensation expense related to the 2008 LTIP Common Stock Award and 2009 and 2010 LTIP award of restricted stock units. For the nine months ended September 30, 2009, the Company recognized $3.9 million in pre-tax compensation expense related to the 2007 and 2008 LTIP Common Stock Awards and the 2009 LTIP award of restricted stock units. The amounts recognized during the nine months ended September 30, 2010 assumes that maximum performance objectives are attained. If the Company ultimately attains these performance objectives, the associated total compensation, estimated at September 30, 2010, for each of the three year performance periods is expected to be approximately $4.3 million, $22.8 million, and $11.2 million related to the 2008 LTIP Common Stock Award and 2009 and 2010 LTIP award of restricted stock units, respectively. The 2007 LTIP Common Stock Award was paid in shares of the Company’s stock to employees during the first quarter of 2010 and totaled $4.1 million.

 

Best in Class Program.  In May 2008, the Company established the 2008 Best in Class Program for all permanent, full-time employees. Under the 2008 Best in Class Program, participants are eligible to receive a number of shares of the Company’s common stock based on the performance of the Company. As with the

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

LTIP, the 2008 Best in Class Program is measured over a three year performance period. The 2008 Best in Class Program recognizes and financially rewards the collective efforts of all of the Company’s employees in achieving sustained industry leading performance and the enhancement of shareholder value. Under the 2008 Best in Class Program, on January 1, 2008 or the employment date if subsequent to January 1, 2008, eligible employees received a contingent award of stock units of the Company’s common stock based on the average high and low share price on the first day of the performance period. Employees joining the Company after January 1, 2008 participate on a pro-rata basis based on their length of employment during the performance period.

 

The number of contingent units that will become payable and vest upon distribution is based on the Company’s performance relative to the industry during a three year performance period beginning January 1, 2008, and ending December 31, 2010. For each vested unit, the participant will receive one share of common stock. The participant must be employed on the date the awards are distributed in order to receive the award.

 

For the nine months ended September 30, 2010, the Company recognized $0.9 million in pre-tax compensation expense related to the 2008 Best in Class Program. For the nine months ended September 30, 2009, the Company recognized $0.6 million in pre-tax compensation expense related to the 2008 Best in Class Program. The amount recognized for the nine months ended September 30, 2010 assumes that target performance levels are achieved. If the Company ultimately attains the target performance level, the associated total compensation related to the 2008 Best in Class Program is estimated at $4.8 million as of September 30, 2010.

 

 

During the quarter ended September 30, 2010, the Company recorded an income tax provision of $88.1 million, or 35.1% of income before income tax provision. This compares to an income tax benefit of $5.6 million, or 40.3% of the loss before income tax benefit for the quarter ended September 30, 2009. The effective tax rate decreased over the comparable prior year period primarily due certain reconciling items related to the filing of the 2008 U.S. Income Tax return in the third quarter of 2009.

 

During the nine months ended September 30, 2010, the Company recorded an income tax provision of $238.5 million, or 35.9% of income before income tax provision. This compares to an income tax benefit of $296.0 million, or 35.1% of the loss before income tax benefit for the nine months ended September 30, 2009. The effective tax rate increased over the comparable prior year period primarily due to elevated activity levels in the higher state tax rate jurisdiction of Pennsylvania. A one-time catch-up was required during the first quarter of 2010 which caused the effective tax rate for the nine months ended September 30, 2010 to increase.

 

 

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.

 

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.

 

Commodity Derivative Contracts:  During the first quarter of 2009, the Company converted its physical, fixed price, forward natural gas sales to physical, indexed natural gas sales combined with financial swaps whereby the Company receives the fixed price and pays the variable price. This change provides operational flexibility to curtail gas production in the event of continued declines in natural gas prices. The contracts were converted at no cost to the Company and the conversion of these contracts to derivative instruments was

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

effective upon entering into these transactions in March 2009, with upcoming settlements for production months through December 2010. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties.

 

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.

 

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. The application of hedge accounting was discontinued by the Company for periods beginning on or after November 3, 2008.

 

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 income statement. 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.

 

At September 30, 2010, 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. See Note 8 for the detail of the asset and liability values of the following derivatives.

 

 

The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the nine months and quarters ended September 30, 2010 and 2009 (refer to Note 2 for details of unrealized gains or losses included in accumulated other comprehensive income in the Consolidated Balance Sheets):

 

 

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

As required by the Fair Value Measurements and Disclosure Topic of the FASB Accounting Standards Codification, we define 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:

 

 

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

 

The following table presents for each hierarchy level the Company’s assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis, as of September 30, 2010. 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.

 

For non-financial assets and liabilities measured or disclosed at fair value on a non-recurring basis, primarily the Company’s asset retirement obligation, this respective subtopic of FASB ASC 820 was effective January 1, 2009. Implementation of this portion of the standard did not have a material impact on the Company’s consolidated results of operations, financial position or liquidity.

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Fair Value of Financial Instruments

 

The estimated fair value of financial instruments is the 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, and accounts payable approximate fair value due to the immediate or short-term maturity of these financial instruments. We use 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 FASB issued ASU No 2010-09, Subsequent Events - Amendments to Certain Recognition and Disclosure Requirements, on February 24, 2010, in an effort to remove some contradictions between the requirements of U.S. GAAP and the SEC’s filing rules. The amendments remove the requirement that public companies disclose the date of their financial statements in both issued and revised financial statements. The Company has evaluated the period subsequent to September 30, 2010 for events that did not exist at the balance sheet date but arose after that date and determined that the subsequent event described below should be disclosed in order to keep the financial statements from being misleading.

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

On October 12, 2010, the Company’s subsidiary, Ultra Resources, Inc., issued $525.0 million of Senior Notes (the “2010B Senior Notes”) pursuant to a Third Supplement to its Master Note Purchase Agreement dated March 6, 2008. The 2010B Senior Notes rank pari passu with Ultra Resources’ bank revolving credit facility and other outstanding Senior Notes. Payment of the 2010B Senior Notes is guaranteed by the Company and its subsidiary, UP Energy Corporation. A portion of the proceeds from the 2010B Senior Notes was used to repay revolving credit facility debt, but did not reduce the borrowings available under the revolving credit facility, and the balance will be used for general corporate purposes. Of the 2010B Senior Notes, $315.0 million are 4.51% senior notes due in 2020, $35.0 million are 4.66% senior notes due in 2022 and $175.0 million are 4.91% senior notes due in 2025.

 

The following discussion of the financial condition and operating results of the Company should be read in conjunction with the consolidated financial statements and related notes of the Company. Except as otherwise indicated, all amounts are expressed in U.S. dollars. We operate in one industry segment, natural gas and oil exploration and development with one geographical segment, the United States.

 

The Company currently generates substantially all of its revenue, earnings and cash flow from the production and sales of natural gas and oil. 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, 2010, the average price realization for the Company’s natural gas was $4.84 per Mcf, including realized gains and losses on commodity derivatives. The Company’s average price realization for natural gas was $4.08 per Mcf, excluding the realized gains and losses on commodity derivatives. (See Note 7).

 

The Company has consistently delivered meaningful reserve and production growth over the past ten 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 21% production growth on an Mcfe basis during the quarter ended September 30, 2010 as compared to the same quarter in 2009.

 

The Company currently conducts operations exclusively in the United States. Substantially all of the 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.

 

Derivative Instruments and Hedging Activities.  Currently, the Company largely relies on derivative instruments to manage its exposure to commodity price risk. The natural gas reference prices of the Company’s 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 fixed price forward gas sales agreements 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 FASB ASC Topic 815, Derivatives and Hedging (“FASB ASC 815”).

 

Effective November 3, 2008, the Company changed its method of accounting for natural gas commodity derivatives to reflect unrealized gains and losses on commodity derivative contracts in the income statement rather than on the balance sheet. The Company previously followed hedge accounting for its natural gas hedges. Under this prior accounting method, the unrealized gain or loss on qualifying cash flow hedges (calculated on a mark to market basis, net of tax) was recorded on the balance sheet in stockholders’ equity as accumulated other comprehensive income (loss). When an unrealized hedging gain or loss was realized upon contract expiration, it was reclassified into earnings through inclusion in natural gas sales revenues. The Company continues to record the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, but records the changes in the fair value of its commodity derivatives in the Consolidated Statements of Operations as an unrealized gain or loss on commodity derivatives.

 

During the first quarter of 2009, the Company converted its physical, fixed price, forward natural gas sales to physical, indexed natural gas sales combined with financial swaps whereby the Company receives the fixed price and pays the variable price. This change provides operational flexibility to curtail gas production in the event of continued declines in natural gas prices. The contracts were converted at no cost to the Company and the conversion of these contracts to derivative instruments was effective upon entering into these transactions in March 2009, with upcoming settlements for production months through December 2010.

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 we aligned the categories below with the Level 1, 2, and 3 fair value measurements as defined by the Fair Value Measurements and Disclosures Topic. The balance of net unrealized gains and losses recognized for the Company’s energy-related derivative instruments at September 30, 2010 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 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, 2010 and 2009 was $9.1 million and $7.6 million, respectively. At September 30, 2010, there was $1.2 million of total unrecognized compensation cost related to non-vested share-based compensation arrangements granted under stock option plans. That cost is expected to be recognized over a weighted average period of 0.51 years. See Note 5 for additional information.

FASB ASC 718 requires companies to estimate the fair value of share-based payment awards on the date of grant using an option-pricing model. The Company utilized a Black-Scholes option pricing model to measure the fair value of stock options granted to employees. The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period in the Company’s Consolidated Statement of Operations. The Company’s determination of fair value of share-based payment awards on the date of grant using an option-pricing model is affected by the Company’s stock price as well as assumptions regarding a number of highly complex and subjective variables. These variables include, but are not limited to, the Company’s expected stock price volatility over the term of the awards and actual and projected employee stock option exercise behaviors.

 

Full Cost Method of Accounting.  The Company uses the full cost method of accounting for oil and gas operations whereby 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, 2010. During the first quarter of 2009, the Company recorded a $1.0 billion ($673.0 million net of tax) non-cash write-down of the carrying value of the Company’s proved oil and gas properties as of March 31, 2009, as a result of the ceiling test limitation, which is reflected as write-down of proved oil and gas properties in the accompanying consolidated statements of operations. The March 31, 2009 ceiling test limitation was calculated prior to the adoption of SEC Release No. 33-8995 and was based on prices in effect on the last day of the reporting period, March 31, 2009, reflecting wellhead prices of $2.47 per Mcf for natural gas and $33.91 per barrel for condensate.

 

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 3).

 

Conversion of barrels of oil to Mcfe of gas.  We convert 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, 2010 VS. QUARTER ENDED SEPTEMBER 30, 2009

 

During the quarter ended September 30, 2010, production increased 21% on a gas equivalent basis to 55.4 Bcfe from 45.9 Bcfe for the same quarter in 2009 attributable to the Company’s successful drilling activities during 2009 and in the first nine months of 2010. Realized natural gas prices, including realized gains and losses on commodity derivatives, decreased 6% to $4.84 per Mcf in the third quarter of 2010 as compared to $5.13 per Mcf for the same quarter of 2009. During the three months ended September 30, 2010, the Company’s average price for natural gas was $4.08 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $3.09 per Mcf for the same period in 2009. The increase in production and the increase in average natural gas prices, excluding commodity derivatives, contributed to a 55% increase in revenues to $240.4 million as compared to $155.2 million in 2009.

 

Lease operating expense (“LOE”) increased to $10.9 million during the third quarter of 2010 compared to $9.7 million during the same period in 2009. On a unit of production basis, LOE costs decreased to $0.20 per Mcfe at September 30, 2010 compared to $0.21 per Mcfe at September 30, 2009 largely as a result of increased production volumes during the quarter ended September 30, 2010.

 

During the three months ended September 30, 2010, production taxes were $23.2 million compared to $15.2 million during the same period in 2009, or $0.42 per Mcfe compared to $0.33 per Mcfe. The increase in per unit taxes is attributable to increased sales revenues as a result of increased natural gas prices, excluding the effects of commodity derivatives, during the quarter ended September 30, 2010 as compared to the same period in 2009. During the three months ended September 30, 2010, the Company’s average price for natural gas was $4.08 per Mcf, excluding realized gains and losses on commodity derivatives, as compared to $3.09 per Mcf for the same period in 2009. Production taxes are calculated based on a percentage of revenue from production and were 9.6% of revenues for the quarter ended September 30, 2010 and 9.8% of revenues for the same period in 2009.

 

Gathering fees increased to $12.6 million for the three months ended September 30, 2010 compared to $11.4 million during the same period in 2009 largely due to increased production volumes. On a per unit basis, gathering fees decreased to $0.23 per Mcfe for the three months ended September 30, 2010 as compared to $0.25 per Mcfe during the same period in 2009 as a result of increased production in Pennsylvania, which is not subject to 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 $16.2 million for the quarter ended September 30, 2010 as compared to $16.3 million for the same period in 2009 in association with Rockies Express Pipeline (“REX”) transportation charges. On a per unit basis, transportation charges decreased to $0.29 per Mcfe (on total company volumes) for the three months ended September 30, 2010 as compared to $0.35 per Mcfe (on total company volumes) for the same period in 2009 due to the increase in production volumes during the quarter ended September 30, 2010.

 

DD&A expenses increased to $59.7 million during the three months ended September 30, 2010 from $46.4 million for the same period in 2009, attributable primarily to increased production volumes. On a unit of production basis, DD&A increased to $1.08 per Mcfe for the quarter ended September 30, 2010 from $1.01 per Mcfe for the quarter ended September 30, 2009.

 

General and administrative expenses increased to $6.0 million for the quarter ended September 30, 2010 compared to $5.1 million for the same period in 2009. 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 were $0.11 per Mcfe for the quarters ended September 30, 2010 and 2009.

 

Interest expense increased to $11.4 million during the quarter ended September 30, 2010 compared to $9.7 million during the same period in 2009 as a result of increased borrowings during the period ended September 30, 2010. At September 30, 2010, the Company had $1.3 billion in borrowings outstanding. In

addition, the Company capitalized $6.5 million in interest expense for the quarter ended September 30, 2010 related to unevaluated oil and gas properties and on work in process relating to gathering systems that are not currently in service (See Note 3). There was no capitalized interest for the same period in 2009.

 

During the quarter ended September 30, 2010, the Company recognized $40.6 million of realized gain on commodity derivatives as compared to $89.6 million of realized gain on commodity derivatives during the quarter ended September 30, 2009. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under these derivative contracts.

 

During the quarter ended September 30, 2010, the Company recognized $109.6 million in unrealized gain on commodity derivatives as compared to $145.0 million in unrealized loss on commodity derivatives during the quarter ended September 30, 2009. The unrealized gain or loss on commodity derivatives represents the change in the fair value of these derivative instruments over the remaining term of the contract.

 

The Company recognized income before income taxes of $250.7 million for the quarter ended September 30, 2010 compared with a loss before income tax benefit of $13.9 million for the same period in 2009. The increase in earnings is primarily a result of increased revenues resulting from increased production during the three months ended September 30, 2010 as compared to the same period in 2009 along with the change in the gain or loss on commodity derivatives during the quarter ended September 30, 2010 as compared to the same period in 2009.

 

The income tax provision recognized for the quarter ended September 30, 2010 was $88.1 million compared with an income tax benefit of $5.6 million for the three months ended September 30, 2009. The increase is largely a result of increased revenues resulting from increased production as well as the change in the gain or loss on commodity derivatives during the quarter ended September 30, 2010 as compared to the same period in 2009. The effective tax rate for the quarter ended September 30, 2010 decreased as compared to the prior period primarily due to certain reconciling items related to the filing of the 2008 U.S. Income Tax return in the third quarter of 2009.

 

For the three months ended September 30, 2010, the Company recognized net income of $162.6 million or $1.05 per diluted share as compared with a net loss of $8.3 million or ($0.06) per diluted share for the same period in 2009. The increase is primarily attributable to increased revenues resulting from increased production during the three months ended September 30, 2010 as compared to the same period in 2009 along with the change in the gain or loss on commodity derivatives during the quarter ended September 30, 2010 as compared to the same period in 2009.

 

NINE MONTHS ENDED SEPTEMBER 30, 2010 VS. NINE MONTHS ENDED SEPTEMBER 30, 2009

 

During the nine months ended September 30, 2010, production increased 18% on a gas equivalent basis to 156.4 Bcfe from 132.5 Bcfe for the same period in 2009 attributable to the Company’s successful drilling activities during 2009 and in the first nine months of 2010. Realized natural gas prices, including realized gains and losses on commodity derivatives, increased 2% to $5.00 per Mcf in the nine months ended 2010 as compared to $4.89 per Mcf for the same period in 2009. During the nine months ended September 30, 2010, the Company’s average price for natural gas was $4.49 per Mcf, excluding realized gains and losses on commodity derivatives as compared to $3.24 per Mcf for the same period in 2009. The increase in average natural gas prices along with the increase in production contributed to a 64% increase in revenues to $741.9 million as compared to $453.5 million in 2009.

 

LOE increased to $32.7 million during the nine months of 2010 compared to $30.1 million during the same period in 2009. On a unit of production basis, LOE costs decreased to $0.21 per Mcfe at September 30, 2010 compared to $0.23 per Mcfe at September 30, 2009 largely as a result of increased production volumes during the nine months ended September 30, 2010.

 

During the nine months ended September 30, 2010, production taxes were $74.1 million compared to $45.3 million during the same period in 2009, or $0.47 per Mcfe compared to $0.34 per Mcfe. The increase in per unit taxes is attributable to increased sales revenues as a result of increased realized gas prices during the nine months ended September 30, 2010 as compared to the same period in 2009. Production taxes are

calculated based on a percentage of revenue from production and were 10.0% of revenues for the nine months ended September 30, 2010 and 2009.

 

Gathering fees increased to $37.1 million for the nine months ended September 30, 2010 compared to $33.8 million during the same period in 2009 largely due to increased production volumes. On a per unit basis, gathering fees decreased to $0.24 per Mcfe for the nine months ended September 30, 2010 as compared to $0.25 per Mcfe during the same period in 2009 as a result of increased production in Pennsylvania, which is not subject to 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 $48.6 million for the nine months ended September 30, 2010 as compared to $42.8 million for the same period in 2009 in association with REX transportation charges. On a per unit basis, transportation charges decreased to $0.31 per Mcfe (on total company volumes) for the nine months ended September 30, 2010 as compared to $0.32 per Mcfe (on total company volumes) for the same period in 2009 due to the increase in production volumes during the period ended September 30, 2010 and partially offset by increased transportation rates as a result of further eastern expansion of REX.

 

DD&A expenses increased to $167.8 million during the nine months ended September 30, 2010 from $152.0 million for the same period in 2009, attributable to increased production volumes and partially offset by a lower depletion rate due mainly to a lower depletable base as a result of the ceiling test write-down during the first quarter of 2009. On a unit of production basis, DD&A decreased to $1.07 per Mcfe for the nine months ended September 30, 2010 from $1.15 per Mcfe for the nine months ended September 30, 2009. The Company recorded a $1.0 billion non-cash write-down of the carrying value of the Company’s proved oil and gas properties at March 31, 2009 as a result of ceiling test limitations. The write-down reduced earnings in the first quarter of 2009 and results in a lower DD&A rate in future periods.

 

General and administrative expenses increased to $18.5 million for the nine months ended September 30, 2010 compared to $15.4 million for the same period in 2009. 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 remained flat at $0.12 per Mcfe for the nine months ended September 30, 2010 and 2009.

 

Interest expense increased to $34.5 million during the nine months ended September 30, 2010 compared to $26.9 million during the same period in 2009 as a result of increased borrowings during the period ended September 30, 2010. At September 30, 2010, the Company had $1.3 billion in borrowings outstanding. In addition, the Company capitalized $13.9 million in interest expense for the nine months ended September 30, 2010 related to unevaluated oil and gas properties and on work in process relating to gathering systems that are not currently in service (See Note 3). There was no capitalized interest for the same period in 2009.

 

During the nine months ended September 30, 2010, the Company recognized $77.6 million of realized gain on commodity derivatives as compared to $209.2 million of realized gain on commodity derivatives during the nine months ended September 30, 2009. The realized gain or loss on commodity derivatives relates to actual amounts received or paid under these derivative contracts.

 

During the nine months ended September 30, 2010, the Company recognized $268.5 million in unrealized gain on commodity derivatives as compared to $118.9 million in unrealized loss on commodity derivatives during the nine months ended September 30, 2009. 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.

 

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

 

Other expense for the nine months ended September 30, 2009 includes rig termination payments of $3.1 million that were not incurred during the same period in 2010.

The Company recognized income before income taxes of $665.0 million for the nine months ended September 30, 2010 compared with a loss before income tax benefit of $842.5 million for the same period in 2009. The increase in earnings is primarily a result of the non-cash write-down of oil and gas properties associated with the ceiling test limitation during the first quarter of 2009 and increased natural gas prices and increased production during the nine months ended September 30, 2010 as compared to the same period in 2009.

 

The income tax provision recognized for the nine months ended September 30, 2010 was $238.5 million compared with an income tax benefit of $296.0 million for the nine months ended September 30, 2009. The increase is largely due to increased income during the nine months ended September 30, 2010 compared with a loss before income tax benefit of $842.5 million primarily as a result of the non-cash write-down of oil and gas properties associated with the ceiling test limitation during the first quarter of 2009. The effective tax rate for the nine months ended September 30, 2010 increased as compared to the prior period primarily due to elevated activity levels in the higher state tax rate jurisdiction of Pennsylvania. A one-time catch-up was required, which caused the effective tax rate for the nine months ended September 30, 2010 to increase to 35.9%.

 

For the nine months ended September 30, 2010, the Company recognized net income of $426.5 million or $2.77 per diluted share as compared with net loss of $546.4 million or ($3.61) per diluted share for the same period in 2009. The increase is primarily attributable to the non-cash write-down of oil and gas properties associated with the ceiling test limitation during the first quarter of 2009 and increased natural gas prices and increased production during the nine months ended September 30, 2010 as compared to the same period in 2009.

 

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. GAAP. In addition, application of generally accepted accounting principles 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, judgments and assumptions will occur as a result of future events, and, accordingly, actual results could differ from amounts estimated.

 

LIQUIDITY AND CAPITAL RESOURCES

 

During the nine month period ended September 30, 2010, the Company relied on cash provided by operations along with borrowings under the senior credit facility and the issuance of the 2010A Senior Notes to finance its capital expenditures. During this period, the Company participated in the drilling of 361 wells in Wyoming and Pennsylvania. For the nine month period ended September 30, 2010, total capital expenditures were $1.3 billion ($401.0 million to acquire additional acreage in the Pennsylvania Marcellus Shale, $831.4 million related to oil and gas exploration and development expenditures and $61.3 million related to gathering system expenditures).

 

At September 30, 2010, the Company reported a cash position of $7.2 million compared to $13.0 million at September 30, 2009. Working capital deficit at September 30, 2010 was $105.5 million compared to deficit of $118.4 million at September 30, 2009. At September 30, 2010, we had $291.0 million in outstanding borrowings and $209.0 million of available borrowing capacity under the credit facility. In addition, the Company had $1.0 billion outstanding under its Senior Notes (See Note 4). Other long-term obligations of $64.0 million at September 30, 2010 is comprised of items payable in more than one year, primarily related to production taxes and asset retirement obligations.

 

The Company’s available cash, existing credit facility and the cash generated from operations, are projected to be sufficient to meet the Company’s obligations and to fund the budgeted capital investment program for 2010, which is currently projected to be $1.1 billion, exclusive of acquisitions. Of the $1.1 billion budget, the Company plans to allocate approximately 60% to Wyoming and 40% to Pennsylvania.

In 2010, the Company closed the purchase of additional acreage in the Pennsylvania Marcellus Shale for $401.0 million. This transaction is incremental to the 2010 budgeted capital investment program discussed above. In addition, the Company traded and consolidated its land position in Pennsylvania during the first quarter of 2010, which resulted in net proceeds of $68.4 million.

 

The Company’s land position in Pennsylvania continues to expand. Including the acquisition of undeveloped acreage in the Marcellus Shale during the first quarter of 2010, as well as additional acreage acquired during the second quarter of 2010 for $60.1 million, partially offset by the consolidation of the Company’s land position for net proceeds of $68.4 million during the first quarter of 2010, the Company’s acreage position in Pennsylvania is approximately 260,000 net acres.

 

Bank indebtedness:  The Company (through its subsidiary) is 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. This agreement provides an initial loan commitment of $500.0 million and may be increased to a maximum aggregate amount of $750.0 million at the request of the Company. Each bank has the right, but not the obligation, to increase the amount of its commitment as requested by the Company. In the event the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to add new financial institutions to the credit facility.

 

Loans under the credit facility are unsecured and bear 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 Company’s consolidated leverage ratio (125.0 basis points per annum as of September 30, 2010).

 

At September 30, 2010, the Company had $291.0 million in outstanding borrowings and $209.0 million of available borrowing capacity under the credit facility.

 

The facility has restrictive covenants that include the maintenance of a ratio of consolidated funded debt to EBITDAX (earnings before interest, taxes, DD&A and exploration expense) not to exceed three and one half times; 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 at least 1.75 to 1.00. At September 30, 2010, the Company was in compliance with all of its debt covenants under the credit facility.

 

Senior Notes:  On January 28, 2010, Ultra Resources, Inc., issued $500.0 million of Senior Notes (“the 2010A Senior Notes”) pursuant to a Second Supplement to the Master Note Purchase Agreement between the Company and the purchasers of the Notes.

 

The Senior Notes rank pari passu with the Company’s bank credit facility. 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, 2010, the Company was in compliance with all of its debt covenants under the Master Note Purchase Agreement (See Note 4).

 

Operating Activities.  During the nine months ended September 30, 2010, net cash provided by operating activities was $604.1 million, a 44% increase from $420.8 million for the same period in 2009. The increase in net cash provided by operating activities is largely attributable to the increase in realized natural gas prices and increased production during the nine months ended September 30, 2010 as compared to the same period in 2009.

 

Investing Activities.  During the nine months ended September 30, 2010, net cash used in investing activities was $1.1 billion as compared to $586.9 million for the same period in 2009. The increase in net cash used in investing activities is largely due to increased capital investments associated with the Pennsylvania Marcellus Shale acquisition in February 2010 and the Company’s drilling activities in 2010 as compared to

2009, partially offset by the proceeds from the sale of undeveloped acreage during the nine months ended September 30, 2010.

 

Financing Activities.  During the nine months ended September 30, 2010, net cash provided by financing activities was $527.0 million as compared to $165.0 million for the same period in 2009. The increase in net cash provided by financing activities is largely due to increased borrowings, primarily attributable to the 2010A Senior Notes offering, during the nine months ended September 30, 2010 as compared to the same period in 2009.

 

OFF BALANCE SHEET ARRANGEMENTS

 

The Company did not have any off-balance sheet arrangements as of September 30, 2010.

 

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. We are also subject to risks associated with the current unprecedented volatility in the financial markets, including the duration of the crisis and effectiveness of government solutions. See the Company’s annual report on Form 10-K for the year ended December 31, 2009 and its Form 10-Q for the quarters ended March 31, 2010 and June 30, 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.

 

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.

 

Commodity Derivative Contracts:  During the first quarter of 2009, the Company converted its physical, fixed price, forward natural gas sales to physical, indexed natural gas sales combined with financial swaps whereby the Company receives the fixed price and pays the variable price. This change provides operational flexibility to curtail gas production in the event of continued declines in natural gas prices. The contracts were

converted at no cost to the Company and the conversion of these contracts to derivative instruments was effective upon entering into these transactions in March 2009, with upcoming settlements for production months through December 2010. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by independent third parties.

 

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.

 

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. The application of hedge accounting was discontinued by the Company for periods beginning on or after November 3, 2008.

 

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 income statement. 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.

 

At September 30, 2010, 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. See Note 8 for the detail of the asset and liability values of the following derivatives.

 

 

The following table summarizes the pre-tax realized and unrealized gains and losses the Company recognized related to its natural gas derivative instruments in the Consolidated Statements of Operations for the nine months and quarters ended September 30, 2010 and 2009 (refer to Note 2 for details of unrealized gains or losses included in accumulated other comprehensive income in the Consolidated Balance Sheets):

 

 

 

 

 

We have 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”). Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our 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, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of September 30, 2010. There were no changes in our internal control over financial reporting during the nine months ended September 30, 2010 that have materially affected or are reasonably likely to affect, our 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, 2009 and on the Company’s Quarterly Report on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010.

 

None.

 

None.

 

None.

 

(a)  Exhibits

 

 

 

 

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, 2010

 

Name:     Marshall D. Smith

 

Date: November 4, 2010