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     

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

Table of Contents

PART 1 — FINANCIAL INFORMATION

ITEM 1 — FINANCIAL STATEMENTS

(Expressed in U.S. Dollars)

ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

2

ULTRA PETROLEUM CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

(Expressed in U.S. Dollars)

3

ULTRA PETROLEUM CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)

(Expressed in U.S. Dollars)

4

ULTRA PETROLEUM CORP.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(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 is incorporated 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, 2004, are unaudited and were prepared from the Company’s records. Balance sheet data as of December 31, 2004 was derived from the Company’s audited financial statements, but does not include all disclosures required by U.S. generally accepted accounting principles (“GAAP”). 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 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 U.S. 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: 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: 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 exploration and development activities as defined by the Securities and Exchange Commission (SEC). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. 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. Effective with the adoption of SFAS No. 143 in 2003, the carrying amount of oil and 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 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 gas properties are amortized using the unit-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 on relative energy content. Operating fees received related to the properties in which the Company owns an interest are netted against expenses. Fees received in excess of costs incurred are recorded as a reduction to the full cost pool. Effective with the adoption of SFAS 143 asset retirement obligations are included in the base costs for calculating depletion.

Oil and gas properties include unproved 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 on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. All unproved 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) or a charge is made against earnings for those international operations where a reserve base has not yet been established. For international operations where a reserve base has not yet been established, an impairment requiring a charge to earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or other information.

Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, generally using prices in effect at the end of the period held flat for the life of production excluding the estimated abandonment cost for properties with asset retirement obligations recorded on the balance sheet and including the effect of derivative contracts that qualify as cash flow hedges, discounted at 10%, net of related tax effects, plus the cost of unevaluated properties and major development. The effect of implementing SFAS 143 has 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: Crude oil products and merchandise 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. Selling expenses and general and administrative expenses are reported as period costs and excluded from inventory cost. Inventories of materials

5

and supplies are valued at cost or less. Inventory at March 31, 2005 includes depletion and lease operating expenses of $1,973,367, associated with the Company’s crude oil production in China.

(h) 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 and other credit worthy counterparties. 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 to the extent the hedges are effective.

(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.

(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:

(k) Use of estimates: Preparation of consolidated financial statements in accordance with accounting principles generally accepted in the United States 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) Reclassifications: Certain amounts in the financial statements of the prior year have been reclassified to conform to the current year financial statement presentation.

(m) 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:

6

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 the following assumptions: at March 31, 2005, expected volatility of 38.4% and a risk free rate of 3.570%; and at March 31, 2004, expected volatility of 25.0% and a risk free rate of 4.35%. At March 31, 2005 options have expected lives of 6.5 years, and at March 31, 2004 options had expected lives of ten years.

(n) Revenue Recognition. Natural gas revenues are recorded on the entitlement method. Under the entitlement method, revenue is recorded when title passes based on the Company’s net interest. The Company records its entitled share of revenues based on estimated production volumes. Subsequently, these estimated volumes are adjusted to reflect actual volumes that are supported by third party pipeline statements or cash receipts. Since there is a ready market for natural gas, the Company sells the majority of its products soon 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.

Oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title is transferred.

(o) Impact of recently issued accounting pronouncements: In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement of Financial Accounting Standards No. 123 (FAS 123R), “Share-based Payment.” FAS 123R requires compensation costs related to share-based payments to be recognized in the income statement over the vesting period. The amount of the compensation cost will be measured based on the grant-date fair value of the instrument issued. FAS 123R is effective as of January 1, 2006, for all awards granted or modified after that date and for those awards granted prior to that date that have not vested. Beginning after January 1, 2006 the Company will begin expensing share based compensation. All outstanding awards issued prior to this date will have fully vested.

2. ASSET RETIREMENT OBLIGATIONS:

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”). 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 $1,069,239 ($646,232 U.S. and $423,007 China) to account for future obligations associated with its assets in both the United States and China.

3. OIL AND GAS PROPERTIES:

4. LONG-TERM LIABILITIES:

Bank indebtedness: The Company (through its subsidiary) participates in a revolving credit facility with a group of banks led by JP Morgan Chase Bank. The agreement specifies a maximum loan amount of $500 million and an aggregate borrowing base of $400 million and a commitment amount of $200 million at November 1, 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 March 31, 2005, the Company had $87 million outstanding and $113 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.

7

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, the Company’s U.S. subsidiary in which the China assets are held. In the event of a default under the covenants, the Company may not be able to access funds otherwise available under the facility and may, in certain circumstances including reduction in borrowing base, be required to repay the credit facilities. The notes are collateralized by a majority of the Company’s proved domestic oil and gas properties. At March 31, 2005, the Company had $87.0 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 4%. The Company was in compliance with all loan covenants at March 31, 2005.

Other long-term obligations: These costs relate to the long-term portion of production taxes payable, a liability associated with imbalanced production, the long-term portion of the fair value estimate of our hedging liability and our asset retirement obligations mentioned in Note 2.

5. 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 should be measured on a fair value basis.

As described in Note 1, had the Company expensed the fair value of options granted during the period, net income would have been reported as $35,478,449.

Recorded in other comprehensive income in the equity section of the Company’s balance sheet is an offset of $4,714,540 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.

6. 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:

8

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 business 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 2003-2005 have ranged from $3.84 to $5.58 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 first quarter of 2005 was $5.58 per Mcf, basis Opal, Wyoming, including the effect of hedge transactions. The Company continued producing from the first of the nine fields discovered on its oil properties in offshore Bohai Bay, China. The Company’s average realized crude oil price was $33.66 USD per barrel for the quarter ended March 31, 2005.

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 61% production growth on an Mcfe basis during the quarter ended March 31, 2005 as compared to the same quarter in 2004.

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 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.

RESULTS OF OPERATIONS

QUARTER ENDED MARCH 31, 2005 VS. QUARTER ENDED MARCH 31, 2004

During the current quarter, production increased 61% on an equivalent basis to 15.6 Bcfe from 9.7 Bcfe for the same quarter in 2004 attributable to the Company’s successful drilling activities during 2004 and in the first quarter of 2005 along with continued production in China. Average realized price for natural gas increased 13% to $5.58 per Mcf combined with the production increase, resulted in an 83% increase in revenues to $88.8 million.

In Wyoming, production costs increased to $14.6 million at March 31, 2005 compared to $9.7 million at March 31, 2004 due to increased production. On a unit of production basis, LOE costs increased slightly to $0.14 per Mcfe at March 31, 2005 compared to $0.13 per Mcfe at March 31, 2004. During the first quarter of 2005 production taxes were $9.0 million compared to $5.7 million during the first quarter of 2004, or $0.65 per Mcfe, compared to $0.58 per Mcfe. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher prices received increased the costs on a per unit basis. Gathering fees increased 31% to $3.6 million at March 31, 2005 compared to $2.8 million at March 31, 2004 attributable to higher production volumes.

In Wyoming, depletion, depreciation and amortization (“DD&A”) expenses increased to $9.7 million during the quarter ended March 31, 2005 from $5.5 million for the same period in 2004, attributable to increased production volumes and a higher depletion rate, attributable to forecasted increased future development costs. On a unit basis, DD&A increased to $0.70 per Mcfe at March 31, 2005 from $0.56 at March 31, 2004.

9

In China, production costs were $1.5 million at March 31, 2005 ($0.82 per Mcfe or $4.93 per BOE). DD&A was $1.6 million ($0.89 per Mcfe or $5.34 per BOE).

Net income before income taxes increased 87% to $57.5 million and income tax expense increased 85% to $20.2 million. Net income increased 89% to $37.3 million or $0.46 per diluted share.

General and administrative expenses increased 65% to $2.6 million at March 31, 2005 compared to $1.6 million for the same period in 2004. This increase was primarily attributable to increased audit fees associated with the implementation of an internal audit function implemented by the Company to support its compliance with the Sarbanes-Oxley Act coupled with increased external audit fees.

Total income tax expense for the period was $20.2 million during the first quarter of 2005 compared to $10.9 million during the first quarter of 2004. This increase was attributable to an increase in net income from continuing operations. The Company’s effective tax rate was 35.1% at March 31, 2005 compared to 35.5% at March 31, 2004.

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 three month period ended March 31, 2005, the Company relied on cash provided by operations to finance its capital expenditures. The Company participated in the drilling of 18 wells in Wyoming and continued to participate in the exploration and development processes in the China blocks including the ongoing batch drilling program for the development wells. For the three-month period ended March 31, 2005, net capital expenditures were $54 million. At March 31, 2005, the Company reported a cash position of $17.6 million compared to $1.9 million at March 31, 2004. Working capital deficit at March 31, 2005 was $(4.6) million as compared to $(10.0) million at December 31, 2004. As of March 31, 2005, the Company had incurred bank indebtedness of $87.0 million and other long-term obligations of $10.3 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 2005, which are currently projected to be $290 million. Of the $290 million budget, the Company plans to spend approximately $270 million of its 2005 budget in Wyoming and approximately $20 million in China. Of the $270 million for Wyoming, the Company plans to drill or participate in an estimated 105 gross wells in 2005, of which approximately 18% will be for exploration wells and the remaining will be for development wells. Of the $20 million budgeted for China, approximately $15 million will be for development activity and the balance will be for exploratory/appraisal activity. The Company currently has no budget for acquisitions in 2005.

The Company (through its subsidiary) participates in a revolving credit facility with a group of banks led by JP Morgan Chase Bank. The agreement specifies a maximum loan amount of $500 million and an aggregate borrowing base of $400 million and a commitment amount of $200 million at November 1, 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. 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 increased or decreased depending on a number of factors including the Company’s proved reserves and the bank’s forecast of future oil and gas prices. 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, the Company’s U.S. subsidiary in which the China assets are held. In the event of a default under the covenants, the Company may not be able to access funds otherwise available under the facility and may, in certain circumstances including a reduction in the borrowing base, be required to repay the credit facilities. The notes are collateralized by a majority of the Company’s proved domestic oil and gas properties. At March 31, 2005, the Company had $87.0 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 4%. The Company was in compliance with all loan covenants at March 31, 2005.

During the three-months ended March 31, 2005, net cash provided by operating activities was $92.2 million as compared to $25.7 million for the three-months ended March 31, 2004. The increase in cash provided by operating activities was attributable to the increase in net income.

During the three-months ended March 31, 2005, cash used in investing activities was $82.1 million as compared to $41.0 million for the three-months ended March 31, 2004. The change is primarily attributable to increased activity for drilling and completion activity in Wyoming and China.

During the three-months ended March 31, 2005, cash used in financing activities was $9.4 million as compared to cash provided of $15.4 million for the three-months ended March 31, 2004. The change is primarily attributable to decreased borrowings under the senior credit facility.

OFF BALANCE SHEET ARRANGEMENTS

The Company did not have any off-balance sheet arrangements as of March 31, 2005.

10

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, 2004 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. Historically, prices received for gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Gas price realizations averaged $5.58 per Mcf during the three months ended March 31, 2005. This average price includes the effects of hedging and gas balancing between working interest owners. The average realized price for oil in China was $33.66 per barrel. The Company currently does not hedge any of its oil production.

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 consolidated statement of income. 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 income. The Company currently does not have any derivative contracts in place that do not qualify as a cash flow hedge.

During the first three months of 2005, the total impact of the Company’s price swaps was a reduction in gas revenues of $1 million. The effect of fixed price physical contracts is not included in this amount. The Company does not currently hedge its oil production.

At March 31, 2005, 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.)

* Unrealized losses are not adjusted for income tax effect

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 March 31, 2005. (The Company’s approximate average net interest in physical gas sales is 80%.)

The above derivative and forward gas sales contracts represent approximately 45% of the Company’s currently forecasted gas production for the balance of 2005, and 19% for calendar year 2006.

11

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 the 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

ITEM 6. EXHIBITS

Exhibits

3.1 Articles of Incorporation of Ultra Petroleum Corp. — (incorporated by reference to Exhibit 3.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)

3.2 By-Laws of Ultra Petroleum Corp — (incorporated by reference to Exhibit 3.2 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)

4.1 Specimen Common Share Certificate — (incorporated by reference to Exhibit 4.1 of the Company’s Quarterly Report on Form 10Q for the period ended June 30, 2001.)

31.1 Certification of Chief Executive Officer and Principle Financial Officer pursuant to Rule 13(a) — 14(a)

32.1 Certification of Chief Executive Officer and Principle Financial Officer pursuant to Rule 13(a) — 14(b)

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 April 30, 2005	By:
		Name:	Michael D. Watford
		Title:	Chief Executive Officer (on behalf of the registrant and as the Principal Financial Officer)

12