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 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):

 

 

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 31, 2008 was 150,502,296.

 

 

TABLE OF CONTENTS

 

 

 

ULTRA PETROLEUM CORP.

 

CONSOLIDATED STATEMENTS OF INCOME

 

 

See accompanying notes to consolidated financial statements.

ULTRA PETROLEUM CORP.

 

CONDENSEND 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 dollar 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 acquisition, exploration, development, and production of oil and 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.

 

 

The accompanying financial statements, other than the condensed balance sheet data as of December 31, 2007, are unaudited and were prepared from the Company’s records. Condensed balance sheet data as of December 31, 2007 was derived from the Company’s audited financial statements, but does not include all disclosures required by U.S. generally accepted accounting principles. 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.

 

(a) Basis of presentation and principles of consolidation:  The condensed consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries UP Energy Corporation, Ultra Resources, Inc. and Sino-American Energy through the date of the sale of the China operations. The Company presents its financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”). All inter-company transactions and balances have been eliminated upon consolidation.

 

(b) Financial Statement Restatement:  On October 31, 2008, in connection with the preparation of our quarterly report for the third quarter 2008, management of Ultra Petroleum Corp. (the “Company”) and the Audit Committee of the Board of Directors determined that the contemporaneous formal documentation we had prepared in the first quarter of 2008 to support our initial natural gas hedge designations for production sold on the Rockies Express Pipeline (“REX”) did not meet the technical requirements to qualify for hedge accounting treatment in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). In order to cause the hedge contracts to qualify for hedge accounting treatment under SFAS No. 133, the Company was required to predict and document the future relationship between prices at REX sales points and the sales prices at the Northwest Pipeline Rockies (the basis of the contracts) at the time the derivative contracts were entered into. The actual relationship between the sales prices at the two locations was different than that predicted by the Company, which affected our ability to effectively demonstrate ongoing effectiveness between the derivative instrument and the forecasted transaction as outlined in our contemporaneous documentation as set forth under the requirements of SFAS No. 133.

 

The Company has restated the Consolidated Financial Statements for the periods ended March 31, 2008 and June 30, 2008 to reflect the inability to qualify for hedge accounting treatment on the REX designated derivative contracts. The effect of the restatement is to recognize a non-cash, after tax, mark to market unrealized loss on commodity derivatives of $18.0 million in the first quarter of 2008 and a non-cash, after tax, mark to market unrealized gain on commodity derivatives of $1.6 million in the second quarter of 2008.

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Under this accounting treatment, the Company recognized a non-cash, after tax, mark to market unrealized gain on commodity derivatives of $26.6 million in the third quarter of 2008. There is no effect in any period on overall cash flows, total assets, total liabilities or total stockholders’ equity. Because these contracts were entered into and expire in fiscal year 2008, there will be no change in full-year 2008 net income or operating cash flows as a result of the change in accounting treatment of these derivative contracts, as restated. The restatement did not have any impact on any of the financial covenants under the Company’s Senior Credit Facility or Senior Notes due 2015 and 2018.

 

(c) Cash and cash equivalents:  We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

 

(d) 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. Wyoming law requires that these funds be held in a federally insured bank in Wyoming.

 

(e) Capital assets other than oil and gas properties:  Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life.

 

(f) 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”). Separate cost centers are maintained for each country in which the Company incurs costs. 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.

 

Oil and natural gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. The Company excludes these costs until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed, at least quarterly, to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (“DD&A”) pool).

 

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 prices in effect on the last day of the quarter. SEC regulation S-X Rule 4-10 states that if prices in effect at the end of a quarter are the result of a temporary decline and prices improve prior to the issuance of the financial statements, the increased price may be applied in the computation of the ceiling test. 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 result in lower DD&A expense in future periods. A write-down may not be reversed in future periods, even though higher oil and

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

natural gas prices may subsequently increase the ceiling. The effect of implementing SFAS No. 143 had no effect on the ceiling test calculation as the future cash outflows associated with settling asset retirement obligations are excluded from this calculation.

 

(g) Inventories:  Materials and supplies inventories are carried at the lower of current market value or 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, 2008, drilling and completion supplies inventory of $6.0 million primarily includes the cost of pipe and production equipment that will be utilized during the 2008 and 2009 drilling programs.

 

(h) Forward natural gas sales transactions:  The Company primarily relies on fixed price physical delivery contracts, which are considered sales in the normal course of business, to manage its commodity price exposure. The Company, from time to time, also uses derivative instruments as a way to manage its exposure to commodity prices. (See Note 7).

 

(i) 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 of SFAS No. 109.

 

Effective January 1, 2007, we adopted FASB Interpretation No. 48 (“FIN 48”) which requires that 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.

 

(j) Earnings per share:  Basic earnings per share is computed by dividing net earnings attributable to common stock 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.

 

The following table provides a reconciliation of the components of basic and diluted net income per common share:

 

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

(k) Use of estimates:  Preparation of consolidated financial statements in accordance with 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.

 

(l) Accounting for share-based compensation:  The Company applies Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”) 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 under SFAS No. 123R for the nine months ended September 30, 2008 and 2007 was $4.9 million and $3.9 million, respectively. See Note 4 for additional information.

 

(m) Fair Value Accounting.  In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, this statement does not require any new fair value measurements. The changes to current practice resulting from the application of this statement relate to the definition of fair value, the methods used to measure fair value, and the expanded disclosures about fair value measurements. The Company adopted SFAS No. 157 as of January 1, 2008. The implementation of SFAS No. 157 was applied prospectively for our assets and liabilities that are measured at fair value on a recurring basis, primarily our commodity derivatives, with no material impact on consolidated results of operations, financial position or liquidity. For those non-financial assets and liabilities measured or disclosed at fair value on a non-recurring basis, SFAS No. 157 is effective January 1, 2009. Implementation of this portion of the standard is not expected to have a material impact on consolidated results of operations, financial position or liquidity. See Note 9 for additional information.

 

(n) 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

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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.

 

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

 

 

 

 

At September 30, 2008, the Company recorded a current asset of $35.7 million and a non-current asset of $5.5 million associated with the fair value of derivative instruments.

 

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

 

(q) Impact of recently issued accounting pronouncements:  In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). This statement is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to increase transparency about the location and amounts of derivative instruments in an entity’s financial statements; how derivative instruments and related hedged items are accounted for under SFAS No. 133; and how derivative instruments and related hedged items affect financial position, financial performance, and cash flows. SFAS No. 161 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2008. The Company does not anticipate that the implementation of SFAS No. 161 will have a material impact on the consolidated results of operations, financial position or liquidity.

 

 

 

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 our 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 our consolidated leverage ratio (87.5 basis points per annum as of September 30, 2008).

 

At September 30, 2008, we had $148.0 million in outstanding borrowings and $352.0 million of available borrowing capacity under our 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 31/2 times; and as long as our debt rating is below investment grade, the maintenance of an annual ratio of the net present value of our oil and gas properties to total funded debt of at least 1.75 to 1.00. At September 30, 2008, we were in compliance with all of our debt covenants under our credit facility.

 

Senior Notes, due 2015 and 2018:  On March 6, 2008, our wholly-owned subsidiary, Ultra Resources, Inc. issued $300.0 million Senior Notes (“the Notes”) pursuant to a Master Note Purchase Agreement between the Company and the purchasers of the Notes. The Notes rank pari passu with the Company’s bank credit facility. Payment of the Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. Of the Notes, $200.0 million are 5.92% Senior Notes due 2018 and $100.0 million are 5.45% Senior Notes due 2015.

 

Proceeds from the sale of the Notes were used to repay bank debt, but did not reduce the borrowings available to us under the revolving credit facility.

 

The Notes are pre-payable in whole or in part at any time. The Notes are subject to representations, warranties, covenants and events of default customary for a senior note financing. If payment default occurs, any Note holder may accelerate its Notes; if a non-payment default occurs, holders of 51% of the outstanding principal amount of the Notes may accelerate all the Notes. At September 30, 2008, we were in compliance with all of our debt covenants under the Notes.

 

Other long-term obligations:  These costs primarily relate to the long-term portion of production taxes payable, a liability associated with imbalanced production, the long-term portion of costs associated with our compensation programs and our asset retirement obligations.

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

Valuation and Expense Information under SFAS 123R

 

The following table summarizes share-based compensation expense under SFAS No. 123R for the nine months ended September 30, 2008 and 2007, respectively, which was allocated as follows:

 

 

The fair value of each share option award is estimated on the date of grant using a Black-Scholes pricing model based on assumptions noted in the following table. 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 estimate 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.

 

 

Changes in Stock Options and Stock Options Outstanding

 

The following table summarizes the changes in stock options for the nine months ended September 30, 2008:

 

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

PERFORMANCE SHARE PLANS:

 

Long-Term Equity-Based Incentives.  In 2005, we adopted the Long Term Incentive Plan (“LTIP”) in order to further align the interests of key employees with shareholders and give key employees the opportunity to share in the long-term performance of the Company by achieving specific corporate financial and operational goals. Participants are recommended by the CEO and approved by the Compensation Committee. Selected officers, managers and other key employees are eligible to participate in the LTIP which has two components, an LTIP Stock Option Award and an LTIP Common Stock Award.

 

Under the LTIP, each year the Compensation Committee establishes a percentage of base salary for each participant which is multiplied by the participant’s base salary to derive an LTI Value (“Long Term Incentive Value”). With respect to LTIP Stock Option Awards, options are awarded equal to one half of the LTI Value based on the fair value on the date of grant (using Black-Scholes methodology).

 

The other half of the LTI Value is the “target” amount that may be awarded to the participant as an LTIP Common Stock Award at the end of a three year performance period. The Compensation Committee establishes performance measures at the beginning of each three year overlapping performance period. Each participant is also assigned threshold and maximum award levels in the event that performance is below or above target levels.

 

For the performance periods January 2006 — December 2008 (“2006 LTIP Common Stock Award”), January 2007 — December 2009 (“2007 LTIP Common Stock Award”), and January 2008 — 2010 (“2008 LTIP Common Stock Award”), the Compensation Committee established the following performance measures: return on equity, reserve replacement ratio, and production growth.

 

Awards are expressed as dollar targets for the 2006 LTIP and 2007 LTIP Common Stock Awards and become payable in common shares at the end of each performance period based on the Company’s overall performance during such period. During the third quarter of 2008, the Board modified the 2008 LTIP Common Stock Award such that the dollar target is converted to shares on the date the Board approved the modification. A new three year period begins each January. Participants must be employed by the Company when an award is distributed in order to receive an award.

 

For the nine months ended September 30, 2008, the Company recognized $0.5 million, $0.6 million and $0.5 million in pre-tax compensation expense related to the 2006 LTIP, 2007 LTIP and 2008 LTIP Common Stock Awards, respectively. For the nine months ended September 30, 2007, the Company recognized $0.4 million and $0.4 million in pre-tax compensation expense related to the 2006 LTIP and 2007 LTIP Common Stock Awards, respectively. The amounts recognized during the first nine months of 2008 and 2007 assume that maximum performance objectives are attained. If the Company ultimately attains maximum performance objectives, the associated total compensation cost, estimated at September 30, 2008, for the three year performance periods would be approximately $2.7 million, $3.5 million and $3.3 million (before taxes) related to the 2006 LTIP, 2007 LTIP and 2008 LTIP Common Stock Awards, respectively.

 

In 2008, the Company established the 2008 Best in Class program for all employees. The performance period related to the 2005 Best in Class program ended December 31, 2007 with the resulting payout in the second quarter of 2008. The Best in Class program recognizes and financially rewards the collective efforts of all of our 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, all employees received a contingent award of stock units equal to $60,000 worth of our common stock based on the average high and low share price on the date of grant. Employees joining the Company after January 1, 2008 will participate on a pro rata basis based on their length of employment during the performance period. The number of units that will vest and become payable is based on our performance relative to the industry during a three-year performance period beginning January 1, 2008, and ending December 31, 2010, and are set at threshold (50%), target (100%) and maximum (150%) levels. For each

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

vested unit, the participant will receive one share of common stock. The performance measures are all sources finding and development cost and full cycle economics.

 

For the nine months ended September 30, 2008, the Company recognized $0.5 million in pre-tax compensation expense related to the 2008 Best in Class program. For the nine months ended September 30, 2007, the Company recognized $0.5 million in pre-tax compensation expense related to the 2005 Best in Class program. The amount recognized for the nine months ended September 30, 2008 assumes that target performance levels are achieved. If the Company ultimately attains the target performance level, the associated total compensation cost will be approximately $3.4 million before income taxes.

 

5.  SHARE REPURCHASE PROGRAM:

 

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. Pursuant to this authorization, the Company has commenced a program to purchase up to $750.0 million of the Company’s outstanding shares through open market transactions or privately negotiated transactions. The stock repurchase will be funded with cash held in an Ultra Resources bank account or the Company’s senior credit facility.

 

The following tables summarize the Company’s share repurchases in total (open market repurchases plus net share settlements) as of September 30, 2008:

 

 

 

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

The amount of unrecognized tax benefits did not materially change as of September 30, 2008. It is expected that the amount of unrecognized tax benefits may change in the next twelve months; however, the Company does not expect the change to have a significant impact on the results of operations or the financial position of the Company. Interest expense or penalties recognized during the nine months ended September 30, 2008 were immaterial.

 

The following table summarizes the components of Income Tax Expense for the three and nine months ended September 30, 2008 and 2007:

 

 

The income tax provision for continuing operations for the quarter and nine months ended September 30, 2008 differs from the amount that would be computed by applying the combined U.S. federal and state income tax rates of approximately 35.1% to pre-tax income primarily as a result of $1.7 million of foreign tax credits that will not be utilized as a result of the sale of the China properties (see Note 8) along with $4.7 million of withholding taxes related to the share repurchase program.

 

 

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 Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Realized natural gas prices are derived from the financial statements which include the effects of realized hedging gains and losses and natural gas balancing.

 

The Company primarily relies on fixed price forward gas sales to manage its commodity price exposure. These fixed price forward gas sales are considered normal sales. The Company, from time to time, also uses derivative instruments to manage its exposure to commodity prices. The Company has periodically entered into fixed price to index price swap agreements in order to mitigate its commodity price exposure on a portion of its natural gas production. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by such publications as Inside FERC Gas Market Report.

 

Under SFAS No. 133, all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

met. For qualifying cash flow hedges, the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the Condensed Consolidated Balance Sheets, and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Operations.

 

On October 31, 2008, in connection with the preparation of our quarterly report for the third quarter 2008, management of Ultra Petroleum Corp. (the “Company”) and the Audit Committee of the Board of Directors determined that the contemporaneous formal documentation we had prepared in the first quarter of 2008 to support our initial natural gas hedge designations for production sold on REX did not meet the technical requirements to qualify for hedge accounting treatment in accordance with SFAS No. 133. In order to cause the hedge contracts to qualify for hedge accounting treatment under SFAS No. 133, the Company was required to predict and document the future relationship between prices at REX sales points and the sales prices at the Northwest Pipeline Rockies (the basis of the contracts) at the time the hedge contracts were entered into. The actual relationship between the sales prices at the two locations was different than that predicted by the Company, which affected our ability to effectively demonstrate ongoing effectiveness between the derivative instrument and the forecasted transaction as outlined in our contemporaneous documentation as set forth under the requirements of SFAS No. 133. While such derivatives no longer qualify for hedge accounting treatment, the Company believes that these contracts remain a valuable component of our commodity price risk management program.

 

At September 30, 2008, 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 (all prices NWPL Rockies basis).

 

 

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 Income for the three and nine months ended September 30, 2008 and 2007 (refer to Note 1(o) for details of unrealized gains or losses included in accumulated other comprehensive income in the Condensed Consolidated Balance Sheets):

 

 

 

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

The Company also utilizes fixed price forward physical delivery contracts at southwest Wyoming delivery points to mitigate its commodity price exposure. The Company had the following fixed price physical delivery contracts in place on behalf of its interest and those of other parties at September 30, 2008. (In November 2007, the Minerals Management Service commenced a Royalty-in-Kind program which had the effect of increasing the Company’s average net interest in physical gas sales from 80% to approximately 91%.)

 

 

 

During the third quarter of 2007, we made the decision to dispose of Sino-American Energy Corporation, which owned our Bohai Bay assets in China, in order to focus on our legacy asset in the Pinedale Field in southwest Wyoming. The reserve volumes sold represent all of Ultra’s international assets and, previously, were the only results included in our foreign operating segment.

 

On September 26, 2007, our wholly-owned subsidiary, UP Energy Corporation, a Nevada corporation, entered into a definitive share purchase agreement with an effective date of June 30, 2007 and a closing date of October 22, 2007 in order to sell all of the outstanding shares of Sino-American Energy Corporation (“Sino-American”), a Texas corporation, for a total purchase price of US$223.0 million, subject to adjustments. The Company recorded results of operations for the China properties through the close date of October 22, 2007.

 

A summary of financial information related to the Company’s discontinued operations is as follows:

 

 

 

On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurement”. We adopted SFAS No. 157 effective January 1, 2008. SFAS No. 157 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. The statement requires fair value measurements be classified and disclosed in one of the following categories:

 

 

ULTRA PETROLEUM CORP.

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

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 our assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis, as of September 30, 2008:

 

 

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 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.

 

 

Effective November 3, 2008, the Company has 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 has historically followed hedge accounting for its natural gas hedges. Under this 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 will continue to record the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, but will record 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. There will be no resulting effect on overall cash flow, total assets, total liabilities or total stockholders’ equity, and there is no impact on any of the financial covenants under the Company’s Senior Credit Facility or Senior Notes due 2015 and 2018.

 

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. (See Note 8 for a discussion regarding the sale of our Chinese assets).

 

The Company currently generates substantially all of its revenue, earnings and cash from the production and sales of natural gas and oil from its property in southwest Wyoming. The price of natural gas in the southwest Wyoming region is a critical factor to the Company’s business. The price of gas in southwest Wyoming historically has been volatile. The average realizations for the period 2003-2008 have ranged from $2.33 to $8.64 per Mcf. This 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 gas in southwest Wyoming. During the quarter ended September 30, 2008, the average price realization for the Company’s natural gas was $8.21 per Mcf, including realized gain or loss on commodity derivatives. The Company’s average price realization for natural gas was $7.57 per Mcf, excluding the realized gain or loss on commodity derivatives. (See Note 7).

 

The Company has grown its natural gas and oil production significantly over the past three years and management believes it has the ability to continue growing production by drilling already identified locations on its leases in Wyoming. The Company delivered 35% production growth from continuing operations on an Mcfe basis during the quarter ended September 30, 2008 as compared to the same quarter in 2007.

 

Financial Statement Restatement.  On October 31, 2008, in connection with the preparation of our quarterly report for the third quarter 2008, management of Ultra Petroleum Corp. (the “Company”) and the Audit Committee of the Board of Directors determined that the contemporaneous formal documentation we had prepared in the first quarter of 2008 to support our initial natural gas hedge designations for production sold on the Rockies Express Pipeline (“REX”) did not meet the technical requirements to qualify for hedge accounting treatment in accordance with Statement of Financial Accounting Standard No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”). In order to cause the hedge contracts to qualify for hedge accounting treatment under SFAS No. 133, the Company was required to predict and document the future relationship between prices at REX sales points and the sales prices at the Northwest Pipeline Rockies (the basis of the contracts) at the time the derivative contracts were entered into. The actual relationship between the sales prices at the two locations was different than that predicted by the Company, which affected our ability to effectively demonstrate ongoing effectiveness between the derivative instrument and the forecasted transaction as outlined in our contemporaneous documentation as set forth under the requirements of SFAS No. 133.

 

The Company has restated the Consolidated Financial Statements for the periods ended March 31, 2008 and June 30, 2008 to reflect the inability to qualify for hedge accounting treatment on the REX designated derivative contracts. The effect of the restatement is to recognize a non-cash, after tax, mark to market unrealized loss on commodity derivatives of $18.0 million in the first quarter of 2008 and a non-cash, after tax, mark to market unrealized gain on commodity derivatives of $1.6 million in the second quarter of 2008. Under this accounting treatment, the Company recognized a non-cash, after tax, mark to market unrealized gain on commodity derivatives of $26.6 million in the third quarter of 2008. There is no effect in any period on overall cash flows, total assets, total liabilities or total stockholders’ equity. Because these contracts were entered into and expire in fiscal year 2008, there will be no change in full-year 2008 net income or operating cash flows as a result of the accounting treatment of the derivative contracts, as restated. The restatement did not have any impact on any of the financial covenants under the Company’s Senior Credit Facility or Senior Notes due 2015 and 2018.

 

Rockies Express Pipeline.  In December 2005, the Company agreed to become an anchor shipper on the Rockies Express Pipeline (“REX”) securing pipeline infrastructure providing sufficient capacity to transport a portion of its natural gas production away from southwest Wyoming and to provide for reasonable basis

differentials for its natural gas in the future. The Company’s commitment involves capacity of 200,000 MMBtu per day of natural gas for a term of 10 years (beginning in the first quarter of 2008), and the Company is obligated to pay REX certain demand charges related to its rights to hold this firm transportation capacity as an anchor shipper. The pipeline will be completed in two phases: REX-West (Wyoming to Missouri) and REX-East (Missouri to Ohio).

 

During the second quarter of 2008, the REX-West pipeline was extended from the ANR delivery point in Brown County, Kansas to the Panhandle Eastern Pipeline system at Audrain County, Missouri and placed into service. With the completion of this segment, the Company is able to deliver its firm capacity of 200,000 MMBtu per day of natural gas from Wyoming to markets in the Midwest.

 

On May 30, 2008, the FERC issued a Certificate of Public Convenience and Necessity for the REX-East project. During October 2008, Kinder Morgan, the managing member of REX, informed the Company that the progress in constructing REX-East has been reassessed and the projected in-service date for Interim Service on REX-East to a series of new delivery points in Illinois is anticipated to be on or about April 1, 2009. Service to pipeline interconnections near Lebanon, Ohio is projected to commence on or about June 15, 2009. Kinder Morgan has further advised that, when fully completed, (estimated to be on or about November 1, 2009) the REX-East pipeline will provide up to 1.8 Bcf per day of natural gas transportation capacity from the Rockies to Clarington, Ohio.

 

Discontinued Operations.  On September 27, 2007, the Company announced the execution of a stock purchase agreement for the sale of Sino-American Energy Corporation which represents all of Ultra’s interest in Bohai Bay, China for $223 million. The sale closed on October 22, 2007, with an effective date of June 30, 2007.

 

Forward Natural Gas Sales.  Effective November 3, 2008, the Company has 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 has historically followed hedge accounting for its natural gas hedges. Under this 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 will continue to record the fair value of its commodity derivatives as an asset or liability on the Consolidated Balance Sheets, but will record 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. There will be no resulting effect on overall cash flow, total assets, total liabilities or total stockholders’ equity, and there is no impact on any of the financial covenants under the Company’s Senior Credit Facility or Senior Notes due 2015 and 2018.

 

Fair Value Measurements.  The Company adopted SFAS No. 157 as of January 1, 2008. The implementation of SFAS No. 157 was applied prospectively for our assets and liabilities that are measured at fair value on a recurring basis, primarily our commodity derivatives, with no material impact on consolidated results of operations, financial position or liquidity. See Note 9 for additional information.

 

SFAS No. 157 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 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 SFAS No. 157. In addition, we aligned the categories below with the Level 1, 2, and 3 fair value measurements as defined by SFAS No. 157. The balance of net unrealized gains and losses recognized for our energy-related derivative instruments at September 30, 2008 is summarized in the following table based on the inputs used to determine fair value:

 

 

 

 

Share-Based Payment Arrangements.  The Company applies Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123R”) 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 under SFAS No. 123R for the nine months ended September 30, 2008 and 2007 was $4.9 million and $3.9 million, respectively. At September 30, 2008, there was $12.2 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 1.8 years. See Note 4 for additional information.

 

SFAS No. 123R 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 periods 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. 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.

 

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 prices in effect on the last day of the quarter. SEC regulation S-X Rule 4-10 states that if prices in effect at the end of a quarter are the result of a temporary decline and prices improve prior to the issuance of the financial statements, the increased price may be applied in the computation of the ceiling test. 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 result in lower DD&A expense 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.

 

RESULTS OF OPERATIONS

 

QUARTER ENDED SEPTEMBER 30, 2008 VS. QUARTER ENDED SEPTEMBER 30, 2007

 

During the third quarter of 2008, production from continuing operations increased 35% on a gas equivalent basis to 36.3 Bcfe from 26.9 Bcfe for the same quarter in 2007 attributable to the Company’s successful drilling activities during 2007 and in the first nine months of 2008. Realized natural gas prices, including realized gain and loss on commodity derivatives, increased 103% to $8.21 per Mcf in the third quarter of 2008 as compared to $4.04 for the third quarter of 2007. During the three months ended September 30, 2008, the Company’s average price realization for natural gas was $7.57 per Mcf, excluding realized gains and losses on commodity derivatives. The increase in realized average natural gas prices together with the increase in production contributed to a 169% increase in revenues from continuing operations, including realized gain and loss on commodity derivatives, to $314.8 million as compared to $117.2 million in 2007.

 

Lease operating expense (“LOE”) increased to $8.5 million at September 30, 2008 compared to $6.4 million at September 30, 2007 due primarily to increased production volumes. On a unit of production basis, LOE costs remained relatively flat at $0.23 per Mcfe at September 30, 2008 compared to $0.24 per Mcfe at September 30, 2007.

 

During the third quarter of 2008, production taxes were $31.6 million compared to $13.0 million during the third quarter of 2007, or $0.87 per Mcfe, compared to $0.48 per Mcfe. The increase in per unit taxes is attributable to increased sales revenues as a result of increased production and higher realized gas prices received during the quarter ended September 30, 2008 as compared to the same period in 2007. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher prices received increased production taxes on a per unit basis.

 

Gathering fees increased to $8.9 million at September 30, 2008 compared to $6.7 million at September 30, 2007 largely due to increased production volumes. On a per unit basis, gathering fees remained relatively flat at $0.24 per Mcfe for the three months ended September 30, 2008 as compared to $0.25 per Mcfe for the same period in 2007.

 

To secure pipeline infrastructure providing sufficient capacity to transport a portion of the Company’s natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas, the Company incurred transportation demand charges totaling $11.4 million for the quarter ended September 30, 2008 in association with REX Pipeline demand charges. The REX Pipeline became operational beginning in the first quarter of 2008.

 

Depletion, depreciation and amortization (“DD&A”) expenses increased to $45.7 million during the quarter ended September 30, 2008 from $31.9 million for the same period in 2007, attributable to increased production volumes and a higher depletion rate, due mainly to increased development costs. On a unit basis, DD&A increased to $1.26 per Mcfe at September 30, 2008 from $1.18 at September 30, 2007.

 

General and administrative expenses increased to $4.2 million ($0.12 per Mcfe) at September 30, 2008 compared to $3.5 million ($0.13 per Mcfe) for the same period in 2007. The increase in general and administrative expenses during 2008 is primarily attributable to higher compensation costs as a result of increased personnel during the three months ended September 30, 2008.

Interest expense remained relatively flat at $5.2 million during the quarter ended September 30, 2008 compared to $5.6 million during the same period in 2007. At September 30, 2008, the Company had $448.0 million in borrowings outstanding.

 

During the quarter ended September 30, 2008, the Company recognized $17.2 million and $40.9 million related to realized gain on commodity derivatives and unrealized gain on commodity derivatives, respectively. These amounts relate to derivative contracts that the Company entered into during the first quarter of 2008 in order to mitigate commodity price exposure on a portion of the forecasted production (130,000 Mmbtu per day for April through October 2008) which was expected to be sold on REX. Due to limited historical data correlating REX sales points and NWPL — Rockies (the basis of the contracts), the Company was unable to effectively demonstrate correlation between the derivative instrument and the forecasted transaction according to the contemporaneous documentation as set forth under the requirements of SFAS No. 133 causing the derivative contracts to no longer qualify for hedge accounting treatment. The realized gain on commodity derivatives relates to actual amounts received under these derivative contracts while the unrealized gain on commodity derivatives represents the change in the fair value of these derivative instruments.

 

Net income before income taxes increased to $240.3 million for the quarter ended September 30, 2008 from $50.5 million for the same period in 2007 primarily as a result of increased natural gas prices, increased production and unrealized gains on commodity derivatives during the quarter ended September 30, 2008.

 

The income tax provision increased to $91.4 million for the three months ended September 30, 2008 as compared to $17.7 million for the three months ended September 30, 2007 due to higher pre-tax income combined with $4.7 million in withholding tax associated with the Company’s share repurchase program (See Note 6).

 

Income from discontinued operations, net of tax, (which is comprised entirely of results associated with the Chinese assets) decreased to zero for the quarter ended September 30, 2008 from $4.6 million for the same period in 2007. The sale closed on October 22, 2007. See Note 8 for additional information.

 

For the quarter ended September 30, 2008, net income increased to $149.0 million or $0.95 per diluted share as compared with $37.4 million or $0.24 per diluted share for the same period in 2007 primarily attributable to increased gas prices realized in 2008 as well as increased natural gas production and unrealized gains on commodity derivatives.

 

NINE MONTHS ENDED SEPTEMBER 30, 2008 VS. NINE MONTHS ENDED SEPTEMBER 30, 2007

 

During the nine months ended September 30, 2008, production from continuing operations increased 29% on a gas equivalent basis to 104.6 Bcfe from 80.8 Bcfe for the same period in 2007 attributable to the Company’s successful drilling activities during 2007 and in the first nine months of 2008. Realized natural gas prices, including realized gain and loss on commodity derivatives, increased 68% to $7.98 per Mcf for the nine months ended September 30, 2008 as compared to $4.76 for the same period in 2007. During the nine months ended September 30, 2008, the Company’s average price realization for natural gas was $8.00 per Mcf, excluding realized gains and losses on commodity derivatives. The increase in realized average natural gas prices together with the increase in production contributed to a 117% increase in revenues from continuing operations, including realized gain and loss on commodity derivatives, to $880.1 million as compared to $404.7 million in 2007.

 

LOE increased to $27.8 million at September 30, 2008 compared to $16.7 million at September 30, 2007 due primarily to increased production volumes. On a unit of production basis, LOE costs increased to $0.27 per Mcfe at September 30, 2008 compared to $0.21 per Mcfe at September 30, 2007 mainly due to costs related to non-operated properties for water disposal expenses.

 

During the nine months ended September 30, 2008, production taxes were $98.3 million compared to $45.2 million during the same period of 2007, or $0.94 per Mcfe, compared to $0.56 per Mcfe. The increase in per unit taxes is attributable to increased sales revenues as a result of increased production and higher realized gas prices received during the nine months ended September 30, 2008 as compared to the same period

in 2007. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher prices received increased production taxes on a per unit basis.

 

Gathering fees increased to $27.6 million at September 30, 2008 compared to $20.1 million at September 30, 2007 largely due to increased production volumes. On a per unit basis, gathering fees remained relatively flat at $0.26 per Mcfe for the nine months ended September 30, 2008 as compared to $0.25 per Mcfe for the same period in 2007.

 

To secure pipeline infrastructure providing sufficient capacity to transport a portion of the Company’s natural gas production away from southwest Wyoming and to provide for reasonable basis differentials for its natural gas, the Company incurred transportation demand charges totaling $33.1 million for the nine months ended September 30, 2008 in association with the REX Pipeline demand charges. The REX Pipeline became operational beginning in the first quarter of 2008.

 

DD&A expenses increased to $130.7 million during the nine months ended September 30, 2008 from $94.1 million for the same period in 2007, attributable to increased production volumes and a higher depletion rate, due mainly to increased development costs. On a unit basis, DD&A increased to $1.25 per Mcfe at September 30, 2008 from $1.16 at September 30, 2007.

 

General and administrative expenses increased to $13.0 million ($0.12 per Mcfe) at September 30, 2008 compared to $10.1 million ($0.13 per Mcfe) for the same period in 2007. The increase in general and administrative expenses during 2008 is primarily attributable to increased Medicare taxes as a result of increased employee stock option exercises as well as higher compensation costs related to increased personnel for the nine months ended September 30, 2008.

 

Interest expense increased to $15.0 million during the nine months ended September 30, 2008 from $12.5 million during the same period in 2007. The increase is related to higher average outstanding debt balances during the period ended September 30, 2008 as compared to the same period in 2007. At September 30, 2008, the Company had $448.0 million in borrowings outstanding.

 

During the nine months ended September 30, 2008, the Company recognized $3.1 million and $15.8 million related to realized gain on commodity derivatives and unrealized gain on commodity derivatives, respectively. These amounts relate to derivative contracts that the Company entered into during the first quarter of 2008 in order to mitigate commodity price exposure on a portion of the forecasted production (130,000 Mmbtu per day for April through October 2008) which was expected to be sold on REX. Due to limited historical data correlating REX sales points and NWPL — Rockies (the basis of the contracts), the Company was unable to effectively demonstrate correlation between the derivative instrument and the forecasted transaction according to the contemporaneous documentation as set forth under the requirements of SFAS No. 133 causing the derivative contracts to no longer qualify for hedge accounting treatment. The realized gain on commodity derivatives relates to actual amounts received under these derivative contracts while the unrealized gain on commodity derivatives represents the change in the fair value of these derivative instruments.

 

Net income before income taxes increased to $550.6 million for the nine months ended September 30, 2008 from $206.9 million for the same period in 2007 primarily as a result of increased natural gas prices and increased production during the nine months ended September 30, 2008.

 

The income tax provision increased to $201.9 million for the nine months ended September 30, 2008 as compared to $73.7 million for the nine months ended September 30, 2007 due to higher pre-tax income combined with $4.7 million in withholding tax associated with the Company’s share repurchase program (See Note 6).

 

Income from discontinued operations, net of tax, (which is comprised entirely of results associated with the Chinese assets) decreased to $0.4 million for the nine months ended September 30, 2008 from $19.9 million for the same period in 2007. The sale closed on October 22, 2007. See Note 8 for additional information.

For the nine months ended September 30, 2008, net income increased to $349.2 million or $2.22 per diluted share as compared with $153.1 million or $0.96 per diluted share for the same period in 2007 primarily attributable to increased gas prices realized in 2008 as well as increased natural gas production.

 

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, 2008, the Company relied on cash provided by operations along with borrowings under the senior credit facility and the issuance of the Notes to finance its capital expenditures. The Company participated in the drilling of 254 wells in Wyoming. For the nine month period ended September 30, 2008, net capital expenditures were $679.0 million. At September 30, 2008, the Company reported a cash position of $31.0 million compared to $8.7 million at September 30, 2007. Working capital at September 30, 2008 was a deficit of $126.7 million compared to working capital of $26.9 million at September 30, 2007. At September 30, 2008, we had $148.0 million in outstanding borrowings and $352.0 million of available borrowing capacity under our credit facility. In addition, the Company has $300.0 million outstanding under its Senior Notes at September 30, 2008 (See Note 3) and other long-term obligations of $63.4 million at September 30, 2008 is comprised of items payable in more than one year, primarily related to production taxes.

 

The Company’s positive cash provided by operating activities, along with availability under the senior credit facility, are projected to be sufficient to fund the Company’s budgeted capital expenditures for 2008, which are currently projected to be $945.0 million. Of the $945.0 million budget, the Company plans to allocate approximately 97% to Wyoming and 3% to Pennsylvania.

 

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 our 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 our consolidated leverage ratio (87.5 basis points per annum as of September 30, 2008).

 

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 31/2 times; and as long as our debt rating is below investment grade, the maintenance of an annual ratio of the net present value of our oil and gas properties to total funded debt of at least 1.75 to 1.00. At September 30, 2008, we were in compliance with all of our debt covenants under our credit facility.

 

Senior Notes, due 2015 and 2018:  On March 6, 2008, our wholly-owned subsidiary, Ultra Resources, Inc. issued $300.0 million Senior Notes pursuant to a Master Note Purchase Agreement between the Company and the purchasers of the Notes. The Notes rank pari passu with the Company’s bank credit facility. Payment of the Notes is guaranteed by Ultra Petroleum Corp. and UP Energy Corporation. Of the Notes, $200.0 million are 5.92% Senior Notes due 2018 and $100.0 million are 5.45% Senior Notes due 2015.

Proceeds from the sale of the Notes were used to repay bank debt, but did not reduce the borrowing available to us under our revolving credit facility.

 

The Notes are pre-payable in whole or in part at any time. The Notes are subject to representations, warranties, covenants and events of default customary for a senior note financing. If payment default occurs, any Note holder may accelerate its Notes; if a non-payment default occurs, holders of 51% of the outstanding principal amount of the Notes may accelerate all the Notes. At September 30, 2008, we were in compliance with all of our debt covenants under the Notes.

 

Operating Activities.  During the nine months ended September 30, 2008, net cash provided by operating activities was $708.2 million, a 98% increase over the $357.0 million for the same period in 2007. The increase in net cash provided by operating activities was largely attributable to the increase in production and realized natural gas prices during the nine months ended September 30, 2008 as compared to the same period in 2007.

 

Investing Activities.  During the nine months ended September 30, 2008, net cash used in investing activities was $643.4 million as compared to $527.3 million for the same period in 2007. The increase in net cash used in investing activities is largely due to increased capital expenditures associated with the Company’s drilling activities in 2008.

 

Financing Activities.  During the nine months ended September 30, 2008, net cash used in financing activities was $44.4 million as compared to cash provided by financing activities of $164.5 million for the same period in 2007. The decrease in cash provided by net financing activities is primarily attributable to $285. million of share repurchases during the nine months ended September 30, 2008 as compared to $84.5 million in the same period in 2007, partially offset by decreased net borrowings of $158.0 million during the nine months ended September 30, 2008 as compared to $230.0 million during the same period in 2007. Additionally, the Company recognized $65.9 million in excess tax benefit from stock based compensation during the nine months ended September 30, 2008 as compared to $13.6 million for the same period in 2007.

 

Recent Disruption in the Credit Markets.  We are experiencing unprecedented disruption in the U.S. and international credit markets. These disruptions have resulted in greater volatility, less liquidity, widening of credit spreads and more limited availability of financing. While we believe our cash on hand and availability under our credit facility will be sufficient to finance our capital expenditures and operations over then next twelve months, continued, long-term disruption in the credit markets could make financing more expensive or unavailable, which could have a material adverse effect on our operations.

 

OFF BALANCE SHEET ARRANGEMENTS

 

The Company did not have any off-balance sheet arrangements as of September 30, 2008.

 

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 our 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, 2007 for additional risks related to the Company’s business.

 

 

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 Wyoming natural gas production. Historically, prices received for natural gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Realized natural gas prices are derived from the financial statements which include the effects of realized hedging gains and losses and natural gas balancing.

 

The Company primarily relies on fixed price forward gas sales to manage its commodity price exposure. These fixed price forward gas sales are considered normal sales. The Company, from time to time, also uses derivative instruments to manage its exposure to commodity prices. The Company has periodically entered into fixed price to index price swap agreements in order to hedge a portion of its natural gas production. The natural gas reference prices of these commodity derivative contracts are typically referenced to natural gas index prices as published by such publications as Inside FERC Gas Market Report.

 

Under SFAS No. 133, all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the unrealized gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the Condensed Consolidated Balance Sheets, and the associated unrealized gains and losses are recorded as current expense or income in the Consolidated Statements of Operations.

 

On October 31, 2008, in connection with the preparation of our quarterly report for the third quarter 2008, management of Ultra Petroleum Corp. (the “Company”) and the Audit Committee of the Board of Directors determined that the contemporaneous formal documentation we had prepared in the first quarter of 2008 to support our initial natural gas hedge designations for production sold on the Rockies Express Pipeline (“REX”) did not meet the technical requirements to qualify for hedge accounting treatment in accordance with SFAS No. 133. In order to cause the hedge contracts to qualify for hedge accounting treatment under SFAS No. 133, the Company was required to predict and document the future relationship between prices at REX sales points and the sales prices at the Northwest Pipeline Rockies (the basis of the contracts) at the time the hedge contracts were entered into. The actual relationship between the sales prices at the two locations was different than that predicted by the Company, which affected our ability to effectively demonstrate ongoing effectiveness between the derivative instrument and the forecasted transaction as outlined in our contemporaneous documentation as set forth under the requirements of SFAS No. 133. While such derivatives no longer qualify for hedge accounting treatment, the Company believes that these contracts remain a valuable component of our commodity price risk management program.

At September 30, 2008, 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 (all prices NWPL Rockies basis).

 

 

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 Income for the three and nine months ended September 30, 2008 and 2007 (refer to Note 1(o) for details of unrealized gains or losses included in accumulated other comprehensive income in the Condensed Consolidated Balance Sheets):

 

 

 

 

The Company also utilizes fixed price forward physical delivery contracts at southwest Wyoming delivery points to mitigate its commodity price exposure. The Company had the following fixed price physical delivery contracts in place on behalf of its interest and those of other parties at September 30, 2008. (In November 2007, the Minerals Management Service commenced a Royalty-in-Kind program which had the effect of increasing the Company’s average net interest in physical gas sales from 80% to approximately 91%.)

 

 

 

 

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, 2008. There were no changes in our internal control over financial reporting during the nine months ended September 30, 2008 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.

 

 

If the United States experiences a sustained economic downturn or recession, natural gas prices may fall, which may adversely affect our results of operations.

 

We are experiencing unprecedented disruption in the U.S. and international credit markets. Many economists are predicting that the United States will experience an economic downturn or a recession. The reduced economic activity associated with an economic downturn or recession may reduce the demand for, and so the prices we receive for, our natural gas production. A sustained reduction in the prices we receive for our natural gas production will have a material adverse effect on our results of operations. For example, for the quarter ending September 30, 2008, a 10% reduction in the price we received for natural gas would have reduced our revenues by approximately $25 million.

 

There have been no other material changes with respect to the risk factors disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

 

 

On May 17, 2006, the Company announced that its Board of Directors authorized a share repurchase program for up to an aggregate of $1 billion of the Company’s outstanding common stock which has been and will be funded by cash on hand and borrowings under the Company’s senior credit facility. Pursuant to this authorization, the Company has commenced a program to purchase up to $750.0 million of the Company’s outstanding shares through open market transactions or privately negotiated transactions. (See Note 5 for further details).

 

 

None.

 

 

None.

 

 

None.

 

 

 

 

 

 

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

 

Date: November 5, 2008

 

Name:     Marshall D. Smith

 

Date: November 5, 2008