UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

OR

Commission file number 0-29370

ULTRA PETROLEUM CORP.

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act) YES x NO o

The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of October 25, 2004 was 75,137,968.

PART 1 – FINANCIAL INFORMATION

ITEM 1 – FINANCIAL STATEMENTS

(Expressed in U.S. Dollars)

ULTRA PETROLEUM CORP.

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ULTRA PETROLEUM CORP.

(Expressed in U.S. Dollars)

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ULTRA PETROLEUM CORP.

(Expressed in U.S. Dollars)

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ULTRA PETROLEUM CORP.

(All dollar amounts in this Quarterly Report on Form 10-Q are expressed in U.S. dollars 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 was originally incorporated under the laws of British Columbia, Canada. On March 1, 2000, the Company was continued under the laws of the Yukon Territory, Canada. The Company’s principal business activities are in the Green River Basin of southwest Wyoming and Bohai Bay, China.

1. SIGNIFICANT ACCOUNTING POLICIES:

The accompanying financial statements, other than the balance sheet data as of December 31, 2003, are unaudited and were prepared from the Company’s records. Balance sheet data as of December 31, 2003 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 financial statements on a basis consistent with the Company’s annual audited financial 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 related notes included in the Company’s most recent annual report on Form 10-K.

(a) Basis of presentation and principles of consolidation:

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, UP Energy Corporation, Ultra Resources, Inc., and Sino-American Energy Corporation. The Company presents its financial statements in accordance with accounting principles generally accepted in the United States (“US GAAP”). All material inter-company transactions and balances have been eliminated upon consolidation.

(b) Accounting principles:

The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States.

(c) Cash and cash equivalents:

The Company considers 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:

Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life.

(f) Oil and gas properties:

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 to the Company’s cost centers. 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. The Company conducts operations in both the United States and China. Separate cost centers are maintained for each country in which the Company has operations.

The capitalized costs, together with the costs of production equipment, are depleted using the units-of-production method based on the proven reserves as determined by independent petroleum engineers. Oil and gas reserves and production are converted into equivalent units based upon relative energy content.

Costs of acquiring and evaluating unproved properties are initially excluded from the costs subject to depletion. These unproved properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the costs subject to depletion.

The total capitalized cost of oil and gas properties less accumulated depletion is limited to an amount equal to the estimated future net cash flows from proved reserves, discounted at 10%, using year-end prices, plus the cost (net of impairment) of unproved properties as adjusted for related tax effects (the “full cost ceiling test limitation”).

Proceeds from the sale of oil and gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion.

Substantially all of the Company’s exploration, development and production activities are conducted jointly with others and, accordingly, these financial statements reflect only the Company’s proportionate interest in such activities.

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(g) Derivative transactions:

The Company has entered into commodity price risk management transactions to manage its exposure to gas price volatility. These transactions are in the form of price swaps with financial institutions or other credit worthy counter parties. These transactions have been designated by the Company as cash flow hedges. As such, unrealized gains and losses related to the change in fair market value of the derivative contracts are recorded in other comprehensive income in the balance sheet. The Company also enters into forward sales of physical gas volumes to credit worthy purchasers which are not reflected on the balance sheet.

(h) Income taxes:

The Company uses the asset and liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for future tax consequences. Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial statement and tax basis of assets and liabilities, using the enacted tax rates in effect for the year in which the differences are expected to reverse.

(i) 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 stock options. 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:

(j) Use of estimates:

Preparation of consolidated financial statements in accordance with US 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.

(k) Reclassifications:

Certain amounts in the financial statements of the prior years have been reclassified to conform to the current year financial statement presentation.

(l) Accounting for stock-based compensation:

Statement of Financial Accounting Standards No. 123, “Accounting for Stock–Based Compensation” (SFAS No. 123), defines a fair value method of accounting for employee stock options and similar equity instruments. SFAS No. 123 allows for the continued measurement of compensation cost for such plans using the intrinsic value based method prescribed by APB Opinion No. 25, “Accounting for Stock Issued to Employees” (APB No. 25), provided that pro forma results of operations are disclosed for those options granted. The Company accounts for stock options granted to employees and directors of the Company under the intrinsic value method. Had the Company reported compensation costs as determined by the fair value method of accounting for option grants to employees and directors, net income and net income per common share would approximate the following pro forma amounts:

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For purposes of pro forma disclosures, the estimated fair value of options is amortized to expense over the options’ vesting period. The weighted-average fair value of each option granted is estimated on the date of grant using the Black Scholes option pricing model with an assumed expected volatility of 38.35%. All options have expected lives of 6.5 years.

2. OIL AND GAS PROPERTIES:

3. LONG-TERM DEBT:

The Company (through its subsidiary) participates in a long-term credit facility with a group of banks led by Bank One N.A. The agreement specifies a maximum loan amount of $500 million and an aggregate borrowing base of $315 million and a commitment amount of $200 million at June 9, 2004. The commitment amount may be increased up to the lesser of the borrowing base amount or $500 million at any time at the request of the Company. Each bank shall have the right, but not the obligation, to increase the amount of their commitment as requested by the Company. In the event that the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to bring additional banks into the facility. At September 30, 2004, the Company had $102 million outstanding and $98 million unused and available under the current committed amount.

The credit facility matures on May 1, 2008. The note bears interest at either the bank’s prime rate plus a margin of one-quarter of one percent (0.25%) to seven-eighths of one percent (0.875%) based on the percentage of available credit drawn or at LIBOR plus a margin of one and one-quarter percent (1.25%) to one and seven-eighths of one percent (1.875%) based on the percentage of available credit drawn. For the purposes of calculating interest, the available credit is equal to the borrowing base. An average annual commitment fee of 0.30% to 0.50%, depending on the percentage of available credit drawn, is charged quarterly for any unused portion of the commitment amount.

The borrowing base is subject to periodic (at least semi-annual) review and re-determination by the banks and may be decreased or increased depending on a number of factors, including the Company’s proved reserves and the bank’s forecast of future oil and gas prices. If the borrowing base is reduced to an amount less than the balance outstanding, the Company has sixty days from the date of written notice of the reduction in the borrowing base to pay the difference. Additionally, the Company is subject to quarterly reviews of compliance with the covenants under the bank facility including minimum coverage ratios relating to interest, working capital and advances to Sino-American Energy Corporation. In the event of a default under the covenants, the Company may not be able to access funds otherwise available under the facility. As of September 30, 2004, the Company was in compliance with required ratios of the bank facility.

The debt outstanding under the credit facility is secured by a majority of the Company’s proved domestic oil and gas properties.

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4. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES:

In September 2003, the AcSB (Accounting Standards Board) released revised transitional provisions for Stock-Based Compensation and Other Stock-Based Payments, Section 3870, to provide the same alternative methods of transition as is provided in the US for voluntary adoption of the fair value based method of accounting. These provisions permit either retroactive (with or without restatement) or prospective application of the recognition provisions to awards not previously accounted for at fair value. Prospective application is only available to enterprises that elect to apply the fair value based method of accounting to that type of award for fiscal years beginning before January 1, 2004.

The AcSB has also amended Section 3870 to require that all transactions whereby goods and services are received in exchange for stock-based compensation and other payments result in expenses that should be recognized in financial statements, and that this requirement would be applicable for financial periods beginning on or after January 1, 2004. Section 3870 requires that share-based transactions be measured on a fair value basis.

As described in Note 1, had the Company expensed the fair value of options vested during the period, net income would have been reported as $25,213,922 for the quarter ended September 30, 2004 and $61,763,087 for the nine months ended September 30, 2004.

Recorded in other comprehensive loss in the equity section of the Company’s balance sheet is an offset of $6,282,292 to a liability that measures a future effect of the fixed price to index price swap agreements that the Company currently has in place. The Company has recorded this in compliance with FASB No. 133 which addresses accounting impacts of derivative instruments.

The AcSB issued a new Accounting Guideline (“Guideline”), AcG-13, Hedging Relationships, in December 2001 in connection with amendments to CICA Handbook Section 1650, Foreign Currency Translation. The Guideline is applicable to hedging relationships in effect in fiscal years beginning on or after July 1, 2003 (the AcSB changed the original effective date of January 1, 2002 in its December 2001 meeting, and further deferred the effective date in its September 2002 meeting). The Guideline is not applicable to prior periods, but requires the discontinuance of hedge accounting for hedging relationships established in prior periods that do not meet the conditions for hedge accounting at the date it is first applied.

The Guideline supplements some of the requirements on accounting for hedges of foreign currency items in Section 1650, but is equally applicable to accounting for hedges of other types of risk exposure. The Guideline deals with the identification, documentation, designation and effectiveness of hedges and also the discontinuance of hedge accounting, but does not specify hedge accounting methods.

The Guideline is intended to improve the quality and consistency of hedge accounting under Canadian GAAP. The Guideline incorporates certain features of the U.S. hedge accounting standards as requirements. The AcSB has attempted to avoid creating any additional GAAP differences, i.e., requirements that prevent an entity from adopting a U.S. requirement. However, Canadian hedge accounting remains inconsistent with U.S. GAAP in some fundamental ways.

5. SEGMENT INFORMATION

The Company has two reportable operating segments, one domestic and one foreign, which are in the business of natural gas and crude oil exploration and production. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on profit or loss from oil and gas operations before price-risk management and other, general and administrative expenses and interest expense. The Company’s reportable operating segments are managed separately based on their geographic locations. Financial information by operating segment is presented below:

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6. ASSET RETIREMENT OBLIGATIONS:

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Company has recorded a liability of $692,387 to account for future obligations associated with its assets both domestic and in China.

ITEM 2 – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion of the financial condition and operating results of the Company should be read in conjunction with the 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 segment, natural gas and oil exploration and development with two geographical segments; the United States and China.

The Company currently generates the majority of its revenue, earnings and cash from the production and sales of natural gas and oil from its property in southwestern 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 annual realizations for the period 2001-2003 have ranged from $2.33 to $4.16 per Mcf. This volatility could be very detrimental to the Company’s financial performance. The Company seeks to limit the impact of this volatility on its results by entering into derivative and forward sales contracts for gas in southwest Wyoming. The average realization for the Company’s gas during the third quarter of 2004 was $4.91 per Mcf, basis Opal, Wyoming, including the effect of hedges. For the nine-month period ended September 30, 2004, the average realization for the Company’s gas was $4.87 per Mcf, basis Opal, Wyoming, including the effect of hedges.

On July 18, 2004 the Company initiated production at the first two fields of the nine fields discovered on its oil properties offshore Bohai Bay, China. Production from these fields is characterized as a Heavy, Sweet Crude. The Company sold its first cargos of oil in September, 2004. At that time, the price of oil in east Asia became much more relevant to the Company. The Company sold approximately 300,000 barrels of its Chinese oil production at a price based on the Official ICP (Indonesian Crude oil Price) posting for Duri field crude, less a discount for location and quality differences. These cargos were sold to CNOOC, Ltd., the Company’s Chinese partner, at a price of $36.72 USD per barrel. There can and will be differences in timing between the sale of the Company’s crude oil cargos and the Company’s pro-rata share of production. As of October 15, 2004, the Duri price was approximately $40.65 USD per barrel.

The Company expects to sell at least one additional cargo of its Chinese crude oil production prior to the end of 2004. The Company has the right to export and sell its crude at market prices into the international markets, and is evaluating options to do so in the future. Other markets for the Company’s Chinese oil may be potentially developed in South Korea, Japan, Singapore or other countries.

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 and by bringing into production the already discovered oilfields in China. The Company delivered 87% production growth on an Mcfe basis during the quarter ended September 30, 2004 as compared to the same quarter in 2003 and 69% for the nine-month period ended September 30, 2004 compared to the same period in 2003. Management expects to deliver additional production growth during the balance of 2004 to reach an anticipated annual production of 47 Bcfe in 2004, a 63% growth in annual production over 2003 levels. This increase in production is expected to be achieved by drilling and bringing into production additional wells in Wyoming.

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 to the Company’s cost centers. 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. The Company conducts operations in both the United States and China. Separate cost centers are maintained for each country in which the Company has operations. Substantially all of the oil and gas activities are conducted jointly with others and, accordingly, the amounts in these financial statements 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.

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RESULTS OF OPERATIONS

QUARTER ENDED SEPTEMBER 30, 2004 VS. QUARTER ENDED SEPTEMBER 30, 2003

During the quarter ended September 30, 2004, production increased 87% on an equivalent basis to 13 Bcfe from 6.9 Bcfe for the same quarter in 2003 primarily because of the additional wells drilled and completed in Wyoming during 2003 and the first half of 2004 coupled with initial crude oil production beginning this quarter in China. Average realized price for natural gas and condensate increased 21% on an equivalent basis to $5.12 per Mcfe during the quarter ended September 30, 2004 from $4.22 per Mcfe for the same quarter in 2003 resulting in a 127% increase in revenues to $66.4 million.

Production costs increased 104% to $12.6 million primarily due to the 87% increase in production and higher production taxes driven by the 127% increase in revenues. Production taxes are calculated as a percentage of revenue, which percentage increased slightly to 12% from 11% in the same quarter last year, due primarily to the phasing out of certain tax benefits. On a unit of production basis, production costs increased 9% to $0.97 per Mcfe. The increase in production costs was attributable almost wholly to the increase in production taxes arising from higher revenues which were $0.53 per Mcfe.

Net income before income taxes increased 158% to $43.6 million and income tax provision-deferred increased by 140% to $15.7 million at a rate of 35.5%. Net income increased 170% to $27.9 million or $0.35 per diluted share.

NINE-MONTHS ENDED SEPTEMBER 30, 2004 VS. NINE-MONTHS ENDED SEPTEMBER 30, 2003

During the nine-months ended September 30, 2004, production increased 69% on an equivalent basis to 32.3 Bcfe from 19.1 Bcfe for the same nine-months in 2003 primarily because of the additional wells drilled and completed during 2003, the increased drilling and completion during the first nine-months of the year along with initial production in China beginning in July of 2004. Average realized price for natural gas and condensate increased 23% on an equivalent basis to $4.99 per Mcfe during the nine-month period ended September 30, 2004 from $4.04 per Mcfe for the same period in 2003 resulting in a 108% increase in revenues to $161.2 million.

Production costs increased 94% to $31.7 million primarily due to the 69% increase in production and higher production taxes driven by the 108% increase in revenues. The production taxes which are paid on the Company’s Wyoming properties, are calculated as a percentage of revenue, which percentage increased slightly to 12% during the nine-month period ended September 30, 2004 from 11% in the same nine-months last year, due primarily to the phasing out of certain tax benefits. On a unit of production basis, production costs increased 15% to $0.98 per Mcfe. The increase in production costs was attributable almost wholly to the increase in production taxes arising from higher revenues. Production taxes were $0.56 per Mcfe for the nine-month period.

Net income before income taxes increased 142% to $103.0 million and income tax provision-deferred increased by 124% to $36.8 million at a rate of 35.5%. Net income increased 153% to $66.2 million, or $0.83 per diluted share.

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 US 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, 2004, the Company relied on cash provided by operations and borrowings under its senior credit facility to finance its capital expenditures. The Company participated in the drilling of 66 wells in Wyoming and continued to participate in the development process in the China blocks, including the ongoing drilling of development wells. Due to this continued development in China, the Company saw first production from these properties in July of 2004. For the nine-month period ended September 30, 2004 net capital expenditures were $130.4 million. At September 30, 2004, the Company reported a cash position of $12.5 million compared to $2.6 million at September 30, 2003. Working capital deficit at September 30, 2004 was $(21.6) million as compared to $(26.3) million at September 30, 2003. As of September 30, 2004, the Company had incurred bank indebtedness of $102.0 million and other long-term obligations of $12.4 million 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 the availability under the senior credit facility, are projected to be sufficient to fund the Company’s budgeted capital expenditures for 2004, which are currently projected to be $190.0 million. Of the $190.0 million budget, the Company plans to spend approximately $162.0 million of its 2004 budget in Wyoming and approximately $25.0 million in China with the balance allocated to evaluating other areas. To date the Company has spent $130 million of the $190.0 million capital budget, $119.2 million in Wyoming and $10.8 million in China. Of the $162.0 million for Wyoming, the Company plans to drill or participate in an estimated 80 gross wells in 2004, of which approximately 40% will be for exploration wells and the remaining will be for development wells. Of the $25.0 million budgeted for China, approximately 12% will be for exploratory/appraisal activity and the balance will be for development activity. The Company currently has no budget for acquisitions in 2004.

The Company (through its subsidiary) participates in a long-term credit facility with a group of banks led by Bank One N.A. The agreement specifies a maximum loan amount of $500 million and an aggregate borrowing base of $315 million and a commitment amount of $200 million at June 9, 2004. The commitment amount may be increased up to the lesser of the borrowing base amount or $500 million at any time at the request of the Company. Each bank shall have the right, but not the obligation, to increase the amount of their commitment as requested by the Company. In the event that the existing banks increase their commitment to an amount less than the requested commitment amount, then it would be necessary to bring additional banks into the facility. At September 30, 2004, the Company had $102 million outstanding and $98 million unused and available under the current committed amount.

The credit facility matures on May 1, 2008. The note bears interest at either the bank’s prime rate plus a margin of one-quarter of one percent (0.25%) to seven-eighths of one percent (0.875%) based on the percentage of available credit drawn or at LIBOR plus a margin of one and

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one-quarter percent (1.25%) to one and seven-eighths of one percent (1.875%) based on the percentage of available credit drawn. For the purposes of calculating interest, the available credit is equal to the borrowing base. An average annual commitment fee of 0.30% to 0.50%, depending on the percentage of available credit drawn, is charged quarterly for any unused portion of the commitment amount.

The borrowing base is subject to periodic (at least semi-annual) review and re-determination by the bank’s and may be decreased or increased depending on a number of factors, including the Company’s proved reserves and the bank’s forecast of future oil and gas prices. If the borrowing base is reduced to an amount less than the balance outstanding, the Company has sixty days from the date of written notice of the reduction in the borrowing base to pay the difference. Additionally, the Company is subject to quarterly reviews of compliance with the covenants under the bank facility including minimum coverage ratios relating to interest, working capital and advances to Sino-American Energy Corporation. In the event of a default under the covenants, the Company may not be able to access funds otherwise available under the facility. As of September 30, 2004, the Company was in compliance with required ratios of the bank facility.

The debt outstanding under the credit facility is secured by a majority of the Company’s proved domestic oil and gas properties.

During the nine-months ended September 30, 2004, net cash provided by operating activities was $126.0 million as compared to $52.4 million for the nine-months ended September 30, 2003. The increase in cash provided by operating activities was primarily attributable to the increase in earnings.

During the nine-months ended September 30, 2004, cash used in investing activities was $119.7 million as compared to $44.8 million for the nine-months ended September 30, 2003. The change is primarily attributable to increased activity for drilling and completion activity in Wyoming and China. The $119.7 million used in investing activities consists of $130.4 million incurred for drilling and completion activities in 2004, offset by $(11.3) million attributable to capital expenditures incurred but not yet paid.

During the nine-months ended September 30, 2004, cash provided by (used in) financing activities was $4.3 million as compared to $(6.4) million for the nine-months ended September 30, 2003. The change is primarily attributable to drawing down additional debt under the senior credit facility.

OFF-BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of September 30, 2004.

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. See the Company’s annual report on Form 10-K for the year ended December 31, 2003 for additional risks related to the Company’s business.

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company’s major market risk exposure is in the pricing applicable to its gas and oil production. Realized pricing is primarily driven by the prevailing price for crude oil and spot prices applicable to the Company’s U.S. natural gas production, which contributed 89% of the Company’s oil and gas revenue for the nine months ended September 30, 2004. Historically, prices received for gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Gas price realizations averaged $4.87 per Mcf during the nine months ended September 30, 2004. This average price includes the effects of hedging and gas balancing between working interest owners.

The Company periodically enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and natural gas price volatility. The Company primarily utilizes fixed price physical contracts as well as price swaps, which are placed with major financial institutions or with counter-parties of high credit quality that it believes are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices the Company receives. 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 gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. 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 consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statement of operations. The Company currently does not have any derivative contracts in place that do not qualify as a cash flow hedge.

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During the first nine months of 2004, the total impact of the Company’s price swaps was a reduction in gas revenues of $5.2 million. The effect of fixed price physical contracts is not included in this amount. The Company does not currently hedge its oil production.

At September 30, 2004, the Company had the following open 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 southwest Wyoming basis). (The Company’s gas contains approximately 1.06 MMBtu per Mcf upon delivery at the sales point.)

DERIVATIVE CONTRACTS

The Company also utilizes fixed price forward gas sales contracts at southwest Wyoming delivery points to hedge its commodity exposure. In addition to the derivative contracts discussed above, 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, 2004. (The Company’s approximate average net interest in physical gas sales is 80%.)

FIXED PRICE FORWARD SALES CONTRACTS

The above derivative and forward gas sales contracts represent approximately 34% of the Company’s currently forecasted gas production for the balance of 2004, 34% for calendar year 2005 and 9% for calendar year 2006.

ITEM 4 – CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures. The Company’s management, including the Company’s principal executive officer and principal financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934) as of the end of the period covered by this Quarterly Report on Form 10-Q. Based upon that evaluation, the Company’s principal executive officer and principal financial officer have concluded that the disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission as of the end of the period covered by this Quarterly Report on Form 10-Q.

(b) Changes in Internal Controls. There were no changes in the Company’s internal control over financial reporting that occurred during the Company’s last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART 2 – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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

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

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF THE SECURITY HOLDERS

None

ITEM 5. OTHER INFORMATION

None

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ITEM 6. EXHIBITS

Exhibits

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		ULTRA PETROLEUM CORP.
Date October 26, 2004		By:
		Name:		Michael D. Watford
		Title:		Chief Executive Officer
		By:
		Name:		F. Fox Benton III
		Title:		Chief Financial Officer

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Index to Exhibits