SECURITIES AND UNITED STATES EXCHANGE COMMISSION

Indicate by check mark whether the registrantregistrant: (1) has filed all reports required to be filed by sectionSection 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.

----- ----- Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act) YES X NO ----- ----- The number of common shares, without par value, of Ultra Petroleum Corp., outstanding as of November 1, 2002May 5, 2003 was 74,779,793.

(Expressed (Expressed in U.S. dollars unless otherwise noted)

Nine Three months ended September 30,March 31, 2003 and 2002 and 2001

BUSINESS Ultra Petroleum Corp. (the “Corporation”"Company") is an independent oil and gas company engaged in the acquisition, exploration, development, and production of oil and gas properties. The Company was incorporated under the laws of British Columbia, Canada. AtOn March 1, 2000, the CorporationCompany was continued under the laws of the Yukon Territory, Canada and is now incorporated under the laws of the Yukon Territory. ItsCanada. The Company's principal business activity is the exploration and development of oil and gas properties locatedactivities are in the United States. The Corporation also has oilGreen River Basin of Southwest Wyoming and gas properties inBohai Bay, China.

The accompanying financial statements, other than the balance sheet data as of December 31, 2001,2002, are unaudited and were prepared from ourthe Company's records. Balance sheet data as of December 31, 20012002 was derived from ourthe Company's audited financial statements, but do not include all disclosures required by U.S. generally accepted accounting principles. OurThe Company's management believes that these financial statements include all adjustments necessary for a fair presentation of ourthe Company's financial position and results of operations. All adjustments are of a normal and recurring nature unless specifically noted. WeThe Company prepared these statements on a basis consistent with ourthe Company's annual audited statements and Regulation S-X. Regulation S-X allows usthe 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 ourthe Company's most recent annual report on Form 10-K.

(a) Basis of presentation:

presentation and principles of consolidation: The consolidated financial statements include the accounts of the CorporationCompany 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 intercompanyinter-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 Canada.

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 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"). 5 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. (g) Hedging transactions:

Beginning April 1, 2002 the Corporation The Company has entered into commodity price risk price management transactions to manage its exposure to gas price volatility. These transactions are in the form of price swaps with a financial institution.institution or other credit worthy counter parties. These transactions have been designated by the CorporationCompany as cash flow hedges.

(d) 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. (h) Income taxes:

The CorporationCompany uses the asset and liability method of accounting for income taxes under which deferred tax assets and liabilities are recognized for the future tax consequences. Accordingly, deferred tax assetsliabilities and liabilitiesassets 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.

(e) (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 CorporationCompany 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 for the three- and nine-month periods ended September 30, 2002 and 2001:

(h)share:

Three Months Ended March 31, 2003 2002 ---------- ----------- Net income $8,221,492 $ 1,711,436 ========== =========== Weighted average common shares outstanding during the period 74,056,840 73,496,196 Effect of dilutive instruments 3,893,828 3,857,731 ---------- ----------- Weighted average common shares outstanding during the period including the effects of dilutive instruments 77,950,668 77,353,927 ========== =========== Basic earnings per share $ 0.11 $ 0.02 ========== =========== Diluted earnings per share $ 0.11 $ 0.02 ========== ===========

(j) Use of estimates:

Preparation of consolidated financial statements in accordance with generally accepted accounting principles in CanadaUS 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.

(i) (k) Reclassifications:

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

The credit facility matures on March 1, 2005. The notes bear interest at either the bank’sbank's prime rate plus a margin of one-half of one percent (0.50%) to one and one-quarter percent (1.25%) based on the percentage of available credit drawn or at LIBOR plus a margin of one and one-half percent (1.5%(1.50%) to two and one-quarter percent (2.25%) based on the percentage of available credit drawn. An average annual commitment fee of three-eighths of one percent (0.375%)0.375% is charged quarterly for any unused portion of the credit line.

The borrowing base is subject to periodic (at least semi-annual) review and re-determination by the bank and may be decreased or increased depending on a number of factors including the Corporation’sCompany's proved reserves and the bank’sbank's forecast of future oil and gas prices. Additionally, the CorporationCompany is subject to quarterly reviews of compliance with the covenants under the bank facility including minimum coverage ratios relating to interest, working capital, general and administrative expenditures and advances to Sino-American Energy Corporation.Company. In the event of a default under the covenants, the CorporationCompany may not be able to access funds otherwise available under the facility orand may be required to make immediate principal repayment. As of September 30, 2002,March 31, 2003, the CorporationCompany was in compliance with the covenants and required ratios.

The Corporation hascredit facility is secured this debt by a majority of its proved domestic oil and gas properties.

The Corporation accounts for stock options granted Other long-term obligations: These costs relate to employees and directorsthe long-term portion of the Corporation under the intrinsic value method. Had the Corporation reported compensation costsproduction taxes payable as determined by the fair value method of accounting for option grants to employees and directors prospectively beginning January 1, 2002,well as net income and net income per common share would approximate the following pro forma amounts:

The consolidated financial statements have been prepared in accordance with Currently under Canadian generally accepted accounting principles in Canada (“("Canadian GAAP”GAAP"), which may differthere is not a provision in certain respects from generally acceptedplace to expense stock-based compensation as with FASB Statement No. 123 Accounting for Stock-Based Compensation; however, there was an exposure draft issued in December 2002 that would essentially harmonize their accounting principlesstandards to US GAAP. The proposed effective date for implementing Stock-Based Compensation and Other Stock-Based Payments, Section 3870, is January 1, 2004. During the quarter ended March 31, 2003, the Company recorded to the full cost pool under capitalized general and administrative expenses a consultant's stock-based compensation expense of $56,052. Under current Canadian GAAP, this amount would have been recognized as a disclosure item, with no impact on the financial statements. Recorded in other comprehensive income in the United States (“US GAAP”).

In April 2002,Equity section of our balance sheet is an offset to a liability that measures a future effect of the Corporation began hedging a portion of its production with a fixed price to index price swap agreement.agreements that the Company currently has in place. We have recorded this in compliance with FASB 133 addressing accounting impacts of derivative instruments. Currently under Canadian GAAP the future effects of derivative instruments are recorded through revenue in the period in which the production is sold. The purposetotal future value of the agreementswap is to provide a measure of stability tonot captured as an asset or liability, and the Corporation’s cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. Under US GAAP, the Corporation recognizes all derivative instruments as assets or liabilities in the balance sheet at fair value. The accounting treatment of the changes in fair value as specified in FAS No. 133term Other Comprehensive Income, is dependent upon whether or not a derivative instrument is designated and qualifies as a hedge. This agreement is accounted for as cash flow hedge. As a result, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings as oil and gas revenue. For all other derivatives, changes in fair value are recognized in earnings as non-operating income or expense. At September 30,Canada. In 2002, the Corporation hadCanadian Accounting Standards Board issued a current derivative liability of $144,800. Under the current agreement, the Corporation receives the difference between a fixed price per unit of production and a price based on an agreed upon third-party index if the index price is lower. If the index price is higher, Ultra pays the difference. By entering into swap agreements the Corporation effectively fixes the price that it will receive in the future for the hedged production. Ultra settles in cash on a monthly basis. As of April 1, 2002, Ultra had the following agreementdraft proposal to put in place basedCanadian standards which would be in harmony with U.S. standards on the Northwest Pipeline Corp., Rocky Mountains; Index as publishedfinancial instruments. Canadian enterprises could then choose to apply accounting policies and practices that are in Inside FERC at the first of each month. The Corporation entered into this agreement for 10,000 MMBTU per day at $2.58 through October 31, 2002. The corporation has entered into two additional agreements,accordance with both at 5,000 MMBTU per day at $3.105US and $3.27, which begin on January 1, 2003 for a term of twelve months. The 2003 agreements are also based on Northwest Pipeline Corp., Rocky Mountains; Index as published in Inside FERC at the first of each month.

In June 2001, the Financial Accounting Standards BoardFASB issued SFAS No. 143, “AccountingAccounting for Asset Retirement Obligations”Obligations ("SFAS No. 143"). SFAS No. 143 requires entitiesthe Company to record the fair value of liabilities foran 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 adopted SFAS No. 143 on January 1, 2003. Based on current estimates, the Company would record asset retirement obligations (using a 10% discount rate) and a cumulative effect of acquired assets.change in accounting principle, related to the depreciation and accretion expense that would have been recorded had the fair value of the asset retirement obligation, and corresponding increase in the carrying amount of the related long-lived asset been determined in prior years. Currently the Company has determined that the impact of adopting SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. Management is currently assessingnot material to its financial position or results of operations. The Company adopted the impact, if any,disclosure provisions of SFAS No. 143 on the Corporation’s consolidated financial statements148, Accounting for future periods.

In July 2002, the Financial Accounting Standards Board also issuedStock-based Compensation-Transition and Disclosure" effective January 1, 2003. SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities”. SFAS No. 146 applies to costs associated with (1) an exit activity that does not involve an entity newly acquired in a business combination or (2) a disposal activity within the scope of148 amended FASB Statement No. 144, “Accounting123, Accounting for Stock-Based Compensation ("Statement No. 123"), to provide alternative methods of transition for a voluntary change to the Impairment or Disposalfair-value based method of Long-Lived Assets”. Those costs include (a) certain termination benefits (so-called one-time termination benefits), (b) costsaccounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement No. 123 to terminate a contract that isrequire prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provision of SFAS No. 148 has no material impact on us, as we do not a capital lease, and (c) other associated costs including costsplan to consolidate facilities or relocate employees. The Statement is effectiveadopt the fair-value method of accounting for exit or disposal activities that are initiated after Decemberstock options at the current time. For the period ended March 31, 2002, however, earlier application is encouraged. Management has not yet assessed2003, the impactpro-forma net income, had the Company adopted the provisions of this statement.

Oil and gas revenues increased 171% to $8,671,032 or 25%$24,671,095 for the quarter ended September 30, 2002March 31, 2003 from $6,937,035$9,106,319 for the same period in 2001.2002. This increase was attributable to increased production and an increase in prices received for that production. During the first quarter, the Corporation’s gasCompany's production increased by 40%60% to 46.0 Bcf of gas, and 50,000 barrels of condensate, up from 2.83.8 Bcf whileof gas and 34,000 barrels of condensate increased by 24% to 36 thousand barrels from 29 thousand barrels for the same period in 2001.2002. During the quarter ended September 30, 2002March 31, 2003, the average product prices for gas and condensate were $1.91$3.84 per Mcf and $30.21$30.90 per barrel, respectively, compared to $2.15$2.24 per Mcf and $29.38$20.58 per barrel for the same period in 2001.

During the quarter ended September 30, 2002March 31, 2003, production expenses and taxes increased 48% to $2,556,096$5,201,744 from $1,722,796$2,488,932 for the quarter ended September 30, 2001.March 31, 2002. Direct lease operating expenses increased 66% to $605,335$945,286 for the quarter ended September 30, 2002March 31, 2003 from $364,902$486,867 for the same period in 2001.2002, attributable primarily to increased production volumes. On a per unit of production basis, these costs increased to $.15 per Mcfe in September 2002,the first quarter 2003, as compared to $.12 per Mcfe in September 2001.the first quarter 2002. Production taxes for the thirdfirst quarter 2002of 2003 were $744,429,$2,663,222, compared to $683,823$935,587 in thirdfirst quarter 2001of 2002 or $.18$.42 per Mcfe in thirdfirst quarter 2002,2003, compared to $.23$.24 per Mcfe in thirdfirst quarter 2001.of 2002. Production taxes are calculated based on a percentage of revenue from production, therefore lowerhigher realized prices contributed to the decrease.increase. Gathering fees for the quarter ended September 30, 2002March 31, 2003 increased 79% to $1,206,332$1,593,236 from $674,071$1,066,478 for the same period in 2001, primarily2002, attributable to increasedhigher production and higher unit charges on certain gathering systems.

Depletion, depreciation and amortization expenses (DD&A) were $2,340,270expense increased to $3,605,846 during the quarter ended September 30, 2002 compared to $1,690,540March 31, 2003 from $2,108,297 for the same period in 2001.2002, primarily due to increased production volumes. On a per unit basis, DD&A remained flat atdepletion, depreciation and amortization increased to $.57 per Mcfe, from $.53 in 2002 primarily as a rateresult of $.56 per Mcfe.

General and administrative expenses increased to $1,095,113$1,237,703 during the quarter ended September 30, 2002March 31, 2003 from $1,021,272$848,311 for the same period in 2001.2002. The increase was attributable to legal, professional and compensation expenses that coincide with the Corporation’sCompany's increased activity in both Wyoming and China.

Interest expense for the period increased 50% to $706,705$653,600 in thirdthe first quarter 2002of 2003 from $471,052$514,061 in thirdthe first quarter 2001.of 2002. This increase was attributable to the increase in borrowings under the senior credit facility.

The CorporationCompany recorded deferred income tax expense of $601,783$5,146,788 at an effective rate of 38.5% for the quarter ended September 30, 2002,March 31, 2003, compared to $198,958 at an effective rate of 10.5%$1,071,387 for the quarter ended September 30, 2001.March 31, 2002. Although the CorporationCompany is not expected to pay cash taxes in 2002,2003, in accordance with FAS No. 109 and specifically, the guidance concerning intraperiod tax allocations, the CorporationCompany is required to recognize tax expense evenly throughout the year. In the prior year, income tax expense, as calculated at the statutory rate including estimated state income tax effect, was offset by recognition of deferred tax assets for which a valuation allowance had previously been provided.

Cash flow used in investing activities was $40,670,611 for the nine months ended September 30, 2002 compared to $36,274,743 for the nine months ended September 30, 2001. During the nine monthsquarter ended September 30, 2002, oil and gas property and capital asset expenditures were $40,030,172 and $640,439, respectively, compared to $36,409,693 and $177,415 duringMarch 31, 2003, the same period in the prior year. Amounts expended during the nine-months ended September 30, 2001 were also offset by $312,365 of cash received from the Pendaries Merger.

NetCompany relied on cash provided by financing activities was $30,706,281 for the nine months ended September 30, 2002 compared to cash used of $4,978,074 for the nine months ended September 30, 2001. Cash received in 2002 represented borrowings of $31,000,000 on the credit facility, proceeds from the exercise of options of $899,931 and the cost to acquire stock related to options of $(1,193,650). In the prior year, cash represented as borrowings under the credit facility was $4,404,060, offset by proceeds from the exercise of options of $574,014.

In the nine-month period ending September 30, 2002 the Corporation relied on its existing cash flow and availability under its credit facilityoperations to finance its capital expenditures. During the first nine-months of 2002, the CorporationThe Company participated in continued activity on the Pinedale Anticline in Wyoming. The Corporation participated in the drilling to total depth of twenty-one new wells. Of these, nine were on production as of the end of the third quarter. The remaining twelve wells that were drilled during the nine-month period were in various stages of completion. Capital expenditures in China were related to the participation in the drilling of five wells in Bohai BayWyoming, and two wells in the preparation of the development plan for CFD 11-1 and CFD 11-2 fields.China blocks. For the nine-monththree-month period ending September 30, 2002ended March 31, 2003 net capital expenditures were $40,030,171 ($33,798,171 in Wyoming and $6,232,000 in Bohai Bay).$9.1 million. At September 30, 2002,March 31, 2003, the CorporationCompany reported a cash position of $766,310$1.8 million compared to $1,379,462$4.0 million at DecemberMarch 31, 2001.2002. Working capital at September 30, 2002March 31, 2003 was $(5,613,023)$(2.4) million as compared to $(6,634,866)$(4.8) million at DecemberMarch 31, 2001.

Based on forecasted gas prices, production2002. As of March 31, 2003, the Company had incurred bank indebtedness of $82.0 million and bank availability, management believesother long-term debt of $4.0 million comprised of items payable in more than one year. The positive cash provided by operating activities that the Corporation’s continued positive cash flow from operations andCompany continues to produce, along with the availability under the senior credit facility, willare projected to be sufficient to fund the Corporation’sCompany's budgeted capital expenditures for 2002,2003, which are estimatedcurrently projected to be $60$110.0 million. However, future cash flowsOf the $110.0 million budget, the Company plans to spend approximately $90.0 million of its 2003 budget in Wyoming and continued availabilityapproximately $20.0 million in China. Of the $90.0 million for Wyoming, the Company plans to drill or participate in an estimated 57 gross wells in 2003, of financing arewhich approximately 40% will be for exploration wells and the remaining will be for development wells. Of the $20.0 million budgeted for China, approximately 50% will be for exploratory/appraisal activity and the balance will be for development activity. The Company currently has no budget for acquisitions in 2003. As of March 3, 2003, the revolving senior credit facility provides for a $150.0 million revolving credit line with a current borrowing base of $120.0 million. The credit facility matures on March 1, 2005. The notes bear interest at either Bank One's prime rate plus a margin of one-half of one percent (0.50%) to one and one-quarter percent (1.25%) based on the percentage of available credit drawn or at LIBOR plus a margin of one and one-half percent (1.50%) to two and one-quarter percent (2.25%) based on the percentage of available credit drawn. An average annual commitment fee of 0.375% is charged quarterly for any unused portion of the credit line. 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 uncertainties beyondfactors including the Corporation’s control such as production rates, the price of gas and oil, continued favorable results of the Corporation’s drilling programCompany's proved reserves and the general conditionbank's forecast of the capital markets forfuture oil and gas companies. There canprices. 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, general and administrative expenditures and advances to Sino-American Energy. In the event of a default under the covenants, the Company may not be no assurances that adequate funding willable to access funds otherwise available under the facility and may, in certain circumstances, be available8 required to executerepay the Corporation’s planned futurecredit facilities. The notes are collateralized by a majority of the Company's proved domestic oil and gas properties. At March 31, 2003, the Company had $82.0 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 3%. The Company was in compliance with all loan covenants at March 31, 2003. During the quarter ended March 31, 2003, net cash provided by operating activities was $13.4 million as compared to $6 million for the quarter ended March 31, 2002. The increase in cash provided by operating activities was attributable to the increase in earnings and the decrease in net changes to non-cash working capital program.

This report contains “forward-looking statements”or incorporates by reference forward-looking statements within the meaning of Section 27A of the federal securities laws. TheseSecurities 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 including the Corporation’s outlook for the remainder of 2002 with regard to plans for funding operations and capital expenditures, are based on a number of risks and uncertainties that are outsidewill prove to be correct nor can the Corporation’s control. For example, future cash flows and continued availability of financing are subject to a number of uncertainties beyond the Corporation’s control. There can be no assurances thatCompany assure adequate funding will be available to execute the Corporation’sCorporation's planned future capital program.

Other risks and uncertainties include, but are not limited to, fluctuations in the price we receivethe 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.

Commodity Risk. The Corporation’sCompany's major market risk exposure is in the pricing applicable to its natural gas and oil production. Realized pricing is primarily driven by the prevailing price for crude oil and spot prices applicable to Ultra’s natural gas production in southwestern Wyoming which may not reflect pricing ofthe Company's United States natural gas in general.production. Historically, prices received for gas production have been volatile and unpredictable. Pricing volatility is expected to continue.

Ultra’s production is generally sold at prevailing market prices. However, Gas price realizations averaged $3.84 per Mcf during the Corporationquarter ended March 31, 2003. This average wellhead price includes the effects of hedging and gas balancing between working interest owners. The Company periodically enters into various hedging transactionsarrangements for its natural gas production. During the first quarter of 2003, the total impact of the Company's hedges to the consolidated statements of income was $(518,350). In the first quarter of 2003, the Company entered into additional swaps covering an additional 10,000 MMBtu or approximately 9 MMcf of gas for the period from April 1, 2003 to October 31, 2003 at a portionprice of its production when market conditions are deemed favorable in order$3.75 per MMBtu or approximately $3.95 per Mcf (pricing referenced to manageOpal), plus an additional 5,000 MMBtu or approximately 4 MMcf of gas per day for the same period at a price fluctuations and achieve a more predictable cash flow.of $4.25 per MMBtu or approximately $4.48 per Mcf (pricing referenced to Opal). The Corporation may use fixed-price physical delivery contracts and derivative instruments to manage exposures to commodity prices. The Corporation does not enter into derivative instruments for trading purposes.

At September 30, 2002,table below summarizes the Corporation had the following swaps in place. (“MMBtu” means million British thermal units.)

The Corporation had one fixed-price physical delivery contracthedges in place at September 30, 2002 coveringas of March 3, 2003:

Type Period Daily Volume MMBTU Price / MMBtu at OPAL WY ---- ------ ------------------ ------------------------ Fixed Price Sale Calendar 2003 5,000 $ 3.06 Swap Calendar 2003 5,000 $3.005 Swap Calendar 2003 5,000 $ 3.27 Swap April-Oct 2003 10,000 $ 3.75 Swap April-Oct 2003 5,000 $ 4.25

These hedges represent approximately 45% of the Company's forecasted production for the period January through Decemberfrom April 1, 2003 to October 31, 2003, and approximately 30% of the Company's forecasted production for 5,000 MMBTU at $3.06 per MMBTU.

(a) Evaluation of Disclosure Controls and Procedures. Based on their evaluation as of a date within 90 days of the filing date of this Quarterly Reportquarterly report on Form 10-Q, the Corporation’sCompany's principal executive officer and principal financial officer have concluded that the Corporation’sCompany's disclosure controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934 (the “Exchange Act”"Exchange Act")) are effective to ensure that information required to be disclosed by the CorporationCompany in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission.

The CorporationCompany 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 CorporationCompany believes that the resolution of all such pending or threatened litigation is not likely to have a material adverse effect on the Corporation’sCompany's financial position, or results of operations.

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(a) Exhibits 3.1 Certificate of Continuance of Ultra Petroleum Corp. (incorporated by reference to Exhibit 99.1—3.1 to the Company's quarterly report on form 10-Q for the period ended June 30, 2001) 3.2 By-Laws of Ultra Petroleum Corp. (incorporated by reference to Exhibit 3.2 to the Company's quarterly report on form 10-Q for the period ended June 30, 2001) 4.1 Specimen common share certificate (incorporated by reference to Exhibit 4.1 to the Company's quarterly report on form 10-Q for the period ended June 30, 2001) 10.1 First Amendment to First Amended and Restated Credit Agreement dated November 4, 2002 among Ultra Resources, Inc., Bank One N.A., Union Bank of California, N.A., Guaranty Bank, FSB, Hibernia National Bank and Compass Bank (incorporated by reference to Exhibit 10.1 to the Company's annual report on Form 10-K for the period ended December 31, 2002) 10.2 First Amended and Restated Credit Agreement dated March 1, 2002 among Bank One N.A., Union Bank of California N. A., Guaranty Bank FSB, Hibernia National Bank, Banc One Capital Markets, Inc. and Ultra Resources, Inc. (incorporated by reference to Exhibit 10.1 to the Company's annual report on Form 10-K for the period ended December 31, 2001) 99.1 Certification of Chief Executive Officer

Exhibit 99.2— 99.2 Certification of Chief Financial Officer

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.