10-K 1 h04186e10vk.txt ULTRA PETROLEUM CORP. - DATED 12/31/2002 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002. [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM __________TO ___________. COMMISSION FILE NUMBER: 0-29370 ULTRA PETROLEUM CORP. (Exact Name of Registrant as Specified in Its Charter) YUKON TERRITORY, CANADA N/A (Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 363 NORTH SAM HOUSTON PARKWAY EAST, SUITE 1200 HOUSTON, TEXAS 77060 (Address of Principal Executive Offices) (Zip Code) 281-876-0120 (Registrant's Telephone Number, Including Area Code) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- ------------------- Common Shares American Stock Exchange without par value Toronto Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE 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 requirement for the past 90 days. YES [X] NO [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). YES [ ] NO [ X ] As of March 3, 2003, the Registrant had 74,087,668 common shares outstanding, and the aggregate market value of the common shares held by non-affiliates was approximately $659,380,245 based upon the closing price of $ 8.90 per share for the common stock on March 3, 2003, as reported on the American Stock Exchange. Documents incorporated by reference: The definitive Proxy Statement for the 2003 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2002, is incorporated by reference in Part III of this Form 10-K. 1 TABLE OF CONTENTS

Page ---- PART I ITEM 1. DESCRIPTION OF BUSINESS ...................................... 3 ITEM 2. DESCRIPTION OF PROPERTY ...................................... 8 ITEM 3. LEGAL PROCEEDINGS ............................................ 12 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS .......... 12 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS .......................................... 12 ITEM 6. SELECTED FINANCIAL DATA ...................................... 13 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS .................................... 14 ITEM 7A QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ... 28 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA .................. 29 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES .................................... 45 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT ............... 45 ITEM 11. EXECUTIVE COMPENSATION ....................................... 45 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 45 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ............... 46 ITEM 14. CONTROLS AND PROCEDURES ...................................... 46 PART IV ITEM 15. EXHIBITS, CONSOLIDATED FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K .......................................... 46 SIGNATURES ................................................... 48

2 PART I ITEM 1. DESCRIPTION OF BUSINESS. ------ ------------------------ Ultra Petroleum Corp. ("Ultra" or the "Company") is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and gas properties. The Company was incorporated on November 14, 1979, under the laws of the Province of British Columbia, Canada. The Company continued into the Yukon Territory, Canada under Section 190 of the Business Corporations Act (Yukon Territory) on March 1, 2000. The Company's operations are focused primarily in the Green River Basin of southwest Wyoming and Bohai Bay, offshore China. From time to time, the Company evaluates other opportunities for the exploration and development of oil and gas properties. Ultra owns interests in approximately 187,773 gross (122,393 net) acres in Wyoming covering approximately 300 square miles. The Company owns working interest in approximately 119 gross producing wells and is operator of 60% of those wells. The Company's current domestic operations are principally focused on developing and expanding a tight gas sand project located in the Green River Basin in Southwest Wyoming. In 2002, the Company's Wyoming production was approximately 99% of the Company's total oil and natural gas production and all of the Company's proved reserves were in Wyoming. In 2002, capital expenditures in Wyoming comprised approximately 83% of the Company's total, and the Company plans to spend approximately 75% of its 2003 capital budget in Wyoming. The Company acquired Pendaries Petroleum Ltd. on January 16, 2001. As a result of this acquisition, the Company became active in oil and gas exploration and development in Bohai Bay, China. The Company now holds an 18.182% working interest in Block 04/36 and a 15% working interest in Block 05/36 (jointly the "Blocks"). In 2002, the Company reported no production or reserves attributable to its China property. The Company spent approximately 17% of its 2002 capital budget and plans on spending approximately 25% of its 2003 budget in China. A wholly-owned subsidiary of Kerr-McGee Corporation is the operator of the Blocks. At the time of the acquisition, three oil discoveries had been made on the Blocks. Since the acquisition of Pendaries, four additional discoveries have been made on the Blocks. The Company's annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, are made available to the public on the Company's website at www.ultrapetroleum.com. BUSINESS STRATEGY Green River Basin, Wyoming The Company plans to continue to identify, develop and explore the gas-rich acreage in the Green River Basin. The Green River Basin drilling program targets the upper Cretaceous Lance and Mesaverde sands in the area of the Pinedale Anticline and Jonah Fields. The Company plans to attempt to continue expanding the identified productive area through the drilling of step-out and exploration wells on its Green River Basin acreage as well as continue drilling deeper wells to test other potentially productive horizons. The Company is utilizing its 3-D seismic to map these deeper potentially productive intervals and to identify further extensions of the productive Lance fairway. Bohai Bay, China The Company plans to drill additional exploration and appraisal wells in 2003 on the Blocks and to continue development planning on the appraised discovery areas. The Company is utilizing its 3-D seismic to map potential productive intervals and to identify further prospects. The Company submitted an Overall Development Plan ("ODP") for the CFD 11-1 and 11-2 fields to the Chinese National Offshore Oil Company ("CNOOC") in December 2002. The ODP was approved by CNOOC and forwarded to the Chinese government with final approval expected in the second quarter of 2003. Construction of the Floating Production Storage Offloading ("FPSO") vessel and offshore platforms has begun and it is anticipated that oil production will commence in the second half of 2004. 3 MARKETING AND PRICING The Company currently derives its revenue principally from the sale of natural gas. As a result, the Company's revenues are determined, to a large degree, by prevailing natural gas prices. The Company currently sells the majority of its natural gas on the open market at prevailing market prices, or pursuant to market price contracts in the Rocky Mountain region, more specifically in southwestern Wyoming. The market price for natural gas is dictated by supply and demand at these sales points, and the Company cannot accurately predict or control the price it receives for its natural gas. Moreover, market prices for natural gas vary significantly by region. For example, natural gas in the Rocky Mountain region, where the Company produces most of its natural gas, historically sells for less than natural gas in the Gulf Coast (Henry Hub), Mid Continent, Midwest and Northeast. Accordingly, the Company's income and cash flows will be affected by changes in natural gas prices and by regional pricing differentials. The Company will experience reduced cash flows and may experience operating losses when natural gas prices are low in the Rocky Mountain region. Under extreme circumstances, the Company's natural gas sales may not generate sufficient revenue to meet the Company's financial obligations and fund planned capital expenditures. Moreover, significant price decreases could negatively affect the Company's reserves by reducing the quantities of reserves that are recoverable on an economic basis, necessitating write-downs to reflect the realizable value of the reserves in the low price environment. During 2002, the Company experienced significant pricing differentials in southwestern Wyoming relative to the rest of the country primarily due to production in the region exceeding interstate pipeline capacity to deliver gas to the consuming west and east. The problem was especially pronounced during the summer months when local demand for natural gas in the Rocky Mountain region is typically extremely low. Without sufficient pipeline capacity to move the gas to markets, gas was `bid down' at the inlet of the interstate pipelines. Because of this large differential, the Company received prices significantly lower than those received by companies with production in other regions of the U.S. Currently, significant capacity expansions are planned or under construction that should relieve this shortage of `export' capacity from southwestern Wyoming. Kern River Pipeline which serves southern California, Nevada, Arizona and northern Mexico is expanding by over 900 MMcf/d or 100% to 1.73 Bcf/d and is scheduled to be in service May 2003. Additionally, Northwest Pipeline, which serves the Pacific Northwest, has announced an expansion of 175 MMcf/d and should be in service by late 2003. These expansions are anticipated to moderate the price differentials between southwestern Wyoming and the rest of the country. However, there can be no assurance that the expansions will eliminate large differentials. The Company uses forward sales and financial derivations to reduce the volatility of the prices it receives. See Item 7A for more details. COMPETITION The Company competes with numerous other companies in virtually all facets of its business. The competitors in development, exploration, acquisitions and production include the major oil companies as well as numerous independents, including many that have significantly greater resources. ENVIRONMENTAL MATTERS In 1998, the U.S. Bureau of Land Management ("BLM") initiated a requirement for an Environmental Impact Statement ("EIS") for the Pinedale Anticline area in the Green River Basin. An EIS evaluates the effects that an industry's activities will have on the environment in which the activity is proposed. This EIS encompasses the area north of the Jonah Field, including the Pinedale Anticline, which is where most of the Company's exploration and development is taking place. This environmental study included an analysis of the geological and reservoir characteristics of the area plus the necessary environmental studies related to wildlife, surface use, socio-economic and air quality issues. On July 27, 2000, the BLM issued its Record of Decision ("ROD") with respect to the final EIS. The ROD/EIS allows for the drilling of 700 producing surface locations within the area covered by the EIS, but does not authorize the drilling of particular wells; rather Ultra must submit applications to the BLM's Pinedale field manager for permits to drill and for other required authorizations, such as rights-of-way for pipelines, for each specific well or pipeline location. Development activities in the Pinedale Anticline area, as on all federal leaseholds, remain subject to regulatory agency approval. In making its determination on whether to approve specific drilling or development activities, the BLM applies the requirements outlined in the ROD/EIS. 4 The ROD/EIS imposes limitations and restrictions on activities in the Pinedale Anticline area, including limits on winter drilling and completion activity, and proposes mitigation guidelines, standard practices for industry activities and best management practices for sensitive areas. The ROD/EIS also provides for annual reviews to compare actual environmental impacts to the environmental impacts projected in the EIS and provides for adjustments to mitigate such impacts, if necessary. The review team is comprised of operators, local residents and other affected persons. The process of reviews is currently undergoing changes to satisfy the Federal Advisory Committee Act. The Company cannot predict if or how these changes may affect permitting, development and compliance under the EIS. The BLM's field manager may also impose additional limitations and mitigation measures as are deemed reasonably necessary to mitigate the impact of drilling and production operations in the area. To date, the Company has expended significant resources in order to satisfy applicable environmental laws and regulations in the Pinedale Anticline area and other areas of operation under the jurisdiction of the BLM, and the Company's costs of complying with these regulations may continue to be substantial. Compliance costs under the ROD/EIS and any revisions to the ROD/EIS could become material. Further, any additional limitations and mitigation measures could further increase production costs, delay exploration, development and production activities and curtail exploration, development and production activities altogether. The Company also co-owns leases on state and privately owned lands in the vicinity of the Pinedale Anticline that do not fall under the jurisdiction of the BLM and are not subject to the EIS requirement. In August 1999, the BLM required an Environmental Assessment ("EA") for the potential increased drilling density in the Jonah Field area. An EA is a more limited environmental study than is conducted under an EIS. The EA was required to address the environmental impacts of developing the field on 40-acre well density rather than the 80-acre density that was approved in the initial EIS in 1998. The EA was completed in June 2000. With the approval of this subsequent EA, the Company was permitted to infill drill on 40-acre well density the 2,160 gross (1,322 net) acres owned in the field. Prior to this approval, the Company had drilled 21 gross (7.7 net) wells in the field. Since the approval of 40-acre spacing, the Company has drilled an additional 22 gross (14.0 net) wells during 2000 and 2001. All 43 of the wells drilled by the Company in Jonah Field have been productive. Another operator in Jonah Field is currently investigating the feasibility of downspacing the field to 20 acres per location. While preliminary results appear encouraging, there are no assurances that the field will ultimately be further downspaced. Downspacing will require further environmental review and may require an additional EA or EIS. In September 2002, the Company received the "Oil & Gas Wildlife Stewardship" award from the Wyoming Game and Fish Department in recognition of its contribution to wildlife management in the Pinedale area. During 2001, the Company received the "Agency/Corporation of the Year" award from the Wyoming Wildlife Federation and the "Regional Administrator's Award for Environmental Achievement" from the U.S. Environmental Protection Agency. REGULATION Oil and Gas Regulation The availability of a ready market for oil and gas production depends upon numerous factors beyond the Company's control. These factors include state and federal regulation of oil and gas production and transportation, as well as regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of oil and gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For example, a productive gas well may be "shut-in" because of a lack of an available gas pipeline in the areas in which the Company may conduct operations. State and federal regulations are generally intended to prevent waste of oil and gas, protect rights to produce oil and gas between owners in a common reservoir, control the amount of oil and gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and gas plants are also subject to the jurisdiction of various federal, state and local agencies. The Company's sales of natural gas are affected by the availability, terms and costs of transportation both in the gathering systems that transport from the wellhead to the interstate pipelines and in the interstate pipelines themselves. The rates, terms and conditions applicable to the interstate transportation of gas by 5 pipelines are regulated by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Acts, as well as under Section 311 of the Natural Gas Policy Act. Since 1985, the FERC has implemented regulations intended to increase competition within the gas industry by making gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. The Company's sales of oil are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil pipelines to fulfill the requirements of Title VIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil pipeline rates. The FERC has announced several important transportation-related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000 concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises the FERC's pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets. In the event the Company conducts operations on federal or state oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the BLM or Minerals Management Service ("MMS") or other appropriate federal or state agencies. The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies "similar or like privileges" to citizens of the United States. Such restrictions on citizens of a "non-reciprocal" country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation's lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns interests in numerous federal onshore oil and gas leases. It is possible that holders of the Company's equity interests may be citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act. See "Risk Factors" for a discussion of the risks to our international operations. Environmental Regulations General. The Company's activities in the United States are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control and its activities in China are subject to the laws and regulations of China. It is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials in the environment or otherwise relating to the protection of the environment will not have a material effect upon the Company's operations, capital expenditures, earnings or competitive position. The Company's activities with respect to exploration, drilling and production from wells, natural gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing oil, natural gas and other products, are subject to stringent environmental regulation by state and federal authorities including the Environmental Protection Agency ("EPA"). Such regulation can increase the cost of planning, designing, installing and operating such facilities. In most instances, the regulatory requirements relate to water and air pollution control measures. Solid and Hazardous Waste. The Company currently owns or leases, and has in the past owned or leased, numerous properties that have been used for the exploration and production of oil and gas for many years. Although the Company utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed of or released on or under the properties that the Company currently owns or leases or properties that the Company has owned or leased or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties over whom the Company had no control as to such entities' treatment of hydrocarbons or other wastes or the manner in which such substances may have been disposed of or released. State and 6 federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. Under new laws, the Company could be required to remediate property, including ground water, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial plugging operations to prevent future, or mitigate existing, contamination. The Company may generate wastes, including hazardous wastes that are subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA and various state agencies have limited the disposal options for certain wastes, including wastes designated as hazardous under RCRA and state analogs ("Hazardous Wastes") and is considering the adoption of stricter disposal standards for nonhazardous wastes. Furthermore, certain wastes generated by the Company's oil and gas operations that are currently exempt from treatment as Hazardous Wastes may in the future be designated as Hazardous Wastes under RCRA or the applicable statutes, and therefore be subject to more rigorous and costly operating and disposal requirements. Superfund. The federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, generally imposes joint and several liability for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances ("Hazardous Substances"). These classes of persons or so-called potentially responsible parties ("PRPs"), include current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of the Hazardous Substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRP the costs of such action. Although CERCLA generally exempts "petroleum" from the definition of Hazardous Substance. In the course of its operations, the Company has generated and will generate wastes that fall within CERCLA's definition of Hazardous Substance. The Company may also be an owner or operator of facilities on which Hazardous Substances have been released. The Company may be responsible under CERCLA for all or part of the costs to clean up facilities at which such substances have been released and for natural resource damages. To its knowledge, the Company has not been named a PRP under CERCLA nor have any prior owners or operators of its properties been named as PRP's related to their ownership or operation of such property. Air Emissions. The Company's operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require the Company to forego construction, modification or operation of certain air emission sources. Clean Water Act. The Clean Water Act ("CWA") imposes restrictions and strict controls regarding the discharge of wastes, including produced waters and other oil and natural gas wastes, into waters of the United States, a term broadly defined. These controls have become more stringent over the years, and it is probable that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into federal waters. The CWA provides for civil, criminal and administrative penalties for unauthorized discharges of pollutants and of oil and hazardous substances. It imposes substantial potential liability for the costs of removal or remediation associated with discharges of oil or hazardous substances. State laws governing discharges to water also provide varying civil, criminal and administrative penalties and impose liabilities in the case of a discharge of petroleum or its derivatives, or other hazardous substances, into state waters. In addition, the EPA has promulgated regulations that may require the Company to obtain permits to discharge storm water runoff, including discharges associated with construction activities. In the event of an unauthorized discharge of wastes, the Company may be liable for penalties and costs. The Company believes that it is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company. 7 EMPLOYEES As of March 3, 2003, the Company had 22 full time employees, including officers. ITEM 2. DESCRIPTION OF PROPERTY. LOCATION AND CHARACTERISTICS The Company is dependent on oil and gas leases in Wyoming and two petroleum contracts in China in order to explore for and produce oil and gas. The leases in Wyoming are primarily federal leases with 10-year lease terms until establishment of production. Production on the lease extends the lease terms until cessation of that production. The China petroleum contracts are for a maximum of 30 years and are divided into 3 periods; exploration, development and production. The exploration period is for approximately 7 years and work is to be performed and expenditures are to be incurred to delineate the extent and amount of hydrocarbons, if any, for each block. The development period occurs when a field is discovered and commences on the date of approval of the Ministry of Energy. There is no limit on the time allowed to develop a field. The production period of any oil and gas field in a block is a period of 15 consecutive years commencing on the date of commencement of commercial production from the field, unless extended. Green River Basin, Wyoming As of December 31, 2002, the Company owned developed oil and gas leases totaling 5,449 gross (2,564 net) acres in the Green River Basin of Sublette County, Wyoming which represents 88% of the Company's total gross acreage. The Company owned undeveloped oil and gas leases totaling 182,324 gross (119,829 net) acres in the Green River Basin of Sublette County, Wyoming which represents 92.5% of the Company's total domestic undeveloped gross acreage. The Company's acreage in the Green River Basin is primarily covering the Pinedale Anticline with several other undeveloped acreage blocks north and west of the Pinedale Anticline as well as acreage in the Jonah Field. Holding costs of leases in Wyoming not held by production were approximately $242,710 for the fiscal year ending December 31, 2002. The primary target on the Company's Wyoming acreage is the tight gas sands of the upper Cretaceous Lance formation. Exploratory Wells. During the year-ended December 31, 2002, the Company drilled or caused to be drilled a total of 10 gross (5.22 net) exploratory wells on the Green River Basin properties. All the wells were completed and are producing. The exploratory wells in which the Company participated during 2002 were field extension wells around the perimeter of the known accumulation of the Pinedale Anticline. Development Wells. The Company drilled 16 gross (5.5 net) successful development wells in the Pinedale Field area. For purposes of classification of development wells, the Company is using the definition of wells identified as proven undeveloped locations by the independent petroleum engineering firm Netherland, Sewell & Associates, Inc. at the previous year-end reserve evaluation. When drilled, these locations will be counted as development wells. Bohai Bay, China Block 04/36: The Production Sharing Contract ("PSC") covering this block became effective October 1, 1994. Negotiations with the Chinese government in 2002 resulted in an extension of the third exploration term to September 2003. As the contract now stands, the exploration period will end at the end of September 2003. Barring an extension, at that time all acreage not under appraisal, development or production must be relinquished. Negotiations are ongoing to extend the exploration period beyond September 2003. The Company holds an 18.182% working interest in this block which is 454,000 gross (82,546 net) acres, or 66% of the Company's total gross international acreage. Block 05/36: The PSC covering this block became effective March 1, 1996. The second exploration term of this PSC ended in February 2002 with another 25% acreage relinquishment submitted. The third (and final) exploration term will continue through the end of February 2004 when, barring an extension, all acreage not under appraisal, development or production must be relinquished. The Company holds a 15% working interest in this block which is 233,300 gross (34,995 net) acres, or 34% of the Company's total gross international acreage. 8 The relinquished areas of the Blocks were selected using geologic and geophysical modeling. The Company believes that the relinquishments were made to minimize the relinquishment of prospective acreage. Exploration / Appraisal Activity In 2002, utilizing 3-D seismic data, the Company participated in drilling 3 gross (0.55 net) exploratory and 2 gross (0.33 net) appraisal wells on the Blocks. The exploratory drilling resulted in 2 new discoveries on the Blocks. The other exploratory well was termed by the Operator as a non-commercial oil discovery and is classified herein as a dry hole. Although currently not economic, at some point in the future, changes in development economics may allow for the commercial exploitation of this discovery. Both appraisal wells were successful. The primary target formations on the Blocks are the Tertiary Minghuazhen, Guantuao and Dongying formations. Development Activity The Company submitted an ODP for the CFD 11-1 and 11-2 fields to CNOOC in December 2002. The ODP was approved by CNOOC and forwarded to the Chinese government with final approval expected in the second quarter of 2003. Letters of Intent (LOI) for contracts have been signed and construction started for offshore production platforms and a Floating Production Storage Offloading (FPSO) vessel, which will be leased from CNOOC under an operating lease for these fields. The final contracts for these facilities will be signed upon Chinese government approval of the ODP. The platform jackets are expected to be installed offshore in summer 2003 with development well drilling scheduled to start in fourth quarter 2003. The FPSO contract calls for the vessel to be on offshore station in the third quarter of 2004 with oil production starting soon thereafter. The Company has signed a LOI for a 15 year contract (extensions up to 25 years provided) to lease its net share of an FPSO. The FPSO contract specifies a 110,000-150,000 dead weight tons (DWT) double-hull FPSO with 900,000-1,100,000 barrels storage capacity, with Single Point Mooring (SPM) and a processing plant capable of processing 60,000 barrels oil/day (expandable to 80,000 barrels oil/day). The FPSO service agreement calls for a day rate lease payment and a sliding scale per barrel payment that decreases based on cumulative barrels processed. Pennsylvania The Company owns 14,741 gross (14,271 net) acres in Pennsylvania, which represents 7.5% of the Company's total domestic undeveloped gross acreage. Texas The Company operates one gross (0.66 net) well and owns working interests in an additional two gross (0.22 net) wells in Texas and owns 720 gross (382 net) developed acres which represents 12% of the Company's total developed gross acreage. In 2002, the Company participated in the drilling of one gross (0.15 net) well, which was not successful. OIL AND GAS RESERVES The following table sets forth the Company's quantities of proved reserves, for the years-ended December 31, 2002, 2001 and 2000 as estimated by independent petroleum engineers Netherland, Sewell & Associates, Inc. All of the Company's proved oil and gas reserves are located in the Green River Basin, Wyoming. The table summarizes the Company's proved reserves, the estimated future net revenues from these reserves and the standardized measure of discounted future net cash flows attributable thereto at December 31, 2002, 2001 and 2000. 9

December 31, ------------------------------------- 2002 2001 2000 ---- ---- ---- Proved Undeveloped Reserves Natural gas (MMcf) .................................... 444,513 273,433 75,249 Oil (MBbl) ............................................ 3,556 2,187 602 Proved Developed Reserves Natural gas (MMcf) .................................... 222,608 150,397 85,141 Oil (MBbl) ............................................ 2,003 1,295 688 Total Proved Reserves (MMcfe) ............................ 700,474 444,727 168,132 Estimated future net cash flows, before income tax ....... $1,308,595 $531,676 $1,052,126 Standardized measure of discounted future net cash flows . 473,528 $182,460 $ 493,243 Standardized measure of discounted future net cash flows, after income tax ...................................... $ 316,965 $119,258 $ 310,001

PRODUCTION VOLUMES, AVERAGE SALES PRICES AND AVERAGE PRODUCTION COSTS The following table sets forth certain information regarding the production volumes and average sales prices received for and average production costs associated with Ultra's sale of oil and natural gas for the periods indicated.

Year Ended December 31, ----------------------- 2002 2001 2000 ---- ---- ---- PRODUCTION Natural gas (Mcf) 16,495,751 11,500,446 5,297,421 Oil (Bbl) 151,215 116,413 50,386 ----------- ----------- ----------- Total (Mcfe) 17,403,041 12,198,924 5,599,737 REVENUES Gas sales $38,502,971 $38,204,298 $19,399,001 Oil sales 3,839,421 2,996,955 1,603,635 ----------- ----------- ----------- Total Revenues 42,342,392 41,201,253 21,002,636 LEASE OPERATING EXPENSES Production costs* 2,356,986 1,439,026 665,999 Severance/production taxes 4,116,012 4,425,345 2,253,793 Gathering 4,937,870 3,158,901 1,321,228 ----------- ----------- ----------- Total Lease Operating Expenses $11,410,868 $ 9,023,271 $ 4,241,020 REALIZED PRICES Natural gas (Mcf) $ 2.33 $ 3.32 $ 3.66 Oil (Bbl) $ 25.39 $ 25.74 $ 31.83 OPERATING COSTS PER MCFE Production costs $ 0.14 $ 0.12 $ 0.12 Severance/production taxes $ 0.24 $ 0.36 $ 0.40 Gathering $ 0.28 $ 0.26 $ 0.24 ----------- ----------- ----------- Total Operating Costs per Mcfe $ 0.66 $ 0.74 $ 0.76

---------- * Average production costs include lifting costs and remedial workover expenses. 10 PRODUCTIVE WELLS As of December 31, 2002, the Company's total gross and net wells were as follows:

Productive Wells* Gross Wells Net Wells ---------------- ----------- --------- Natural Gas and Condensate 122 56.81

---------- *Productive wells are producing wells plus shut-in wells the Company deems capable of production. A gross well is a well in which a working interest is owned. The number of net wells represents the sum of fractional working interests the Company owns in gross wells. OIL AND GAS ACREAGE As of December 31, 2002, the Company had total gross and net developed and undeveloped oil and gas leasehold acres as set forth below. The developed acreage is stated on the basis of spacing units designated by state regulatory authorities. The acreage and other additional information concerning the Company's oil and gas operations are presented in the following tables. United States Acreage:

Developed Acres Undeveloped Acres --------------- ----------------- Gross Net Gross Net ----- --- ----- --- Wyoming 5,449 2,564 182,324 119,829 Pennsylvania 0 0 14,741 14,271 Texas 720 382 0 0 ----- ----- ------- ------- All States 6,169 2,946 197,065 134,100

Bohai Bay Acreage: The table below sets out Ultra's Bohai acreage held as of March 3, 2003:

Developed Acres Undeveloped Acres --------------- ----------------- Gross Net Gross Net ----- --- ----- --- Block 04/36 0 0 454,000 82,546 Block 05/36 0 0 233,300 34,995 ----- ----- ------- ------- Total Bohai Acreage 0 0 687,300 117,541

DRILLING ACTIVITIES For each of the three fiscal years ended December 31, 2002, 2001 and 2000, the number of gross and net wells drilled by the Company was as follows: WYOMING - GREEN RIVER BASIN

2002 2001 2000 ---- ---- ---- Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Development Wells Productive ...... 16.00 5.50 9.00 5.52 14.00 8.92 Dry ............. 0.00 0.00 0.00 0.00 0.00 0.00 ----- ----- ----- ----- ----- ----- Total 16.00 5.50 9.00 5.52 14.00 8.92 Exploratory Wells Productive ...... 10.00 5.22 22.00 8.67 10.00 3.16 Dry ............. 0.00 0.00 1.00 0.42 1.00 0.09 ----- ----- ----- ----- ----- ----- Total 10.00 5.22 23.00 9.09 11.00 3.25

11 TEXAS

2002 2001 2000 ---- ---- ---- Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Exploratory Wells Productive ............... 0.00 0.00 0.00 0.00 0.00 0.00 Dry ...................... 1.00 0.15 0.00 0.00 0.00 0.00 ----- ----- ----- ----- ----- ----- Total ........................ 1.00 0.15 0.00 0.00 0.00 0.00

CHINA - BOHAI BAY

2002 2001 2000 ---- ---- ---- Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Exploratory Wells Productive and Successful Appraisal* 4.00 0.70 14.00 2.35 4.00 0.66 Dry ...................... 1.00 0.18 1.00 0.18 1.00 0.18 ----- ----- ----- ----- ----- ----- Total ........................ 5.00 0.88 15.00 2.53 5.00 0.84

------------ * Successful Appraisal well is a well that drilled into a formation shown to be productive of oil or gas by an earlier well for the purpose of obtaining more information about the reservoir. ITEM 3. 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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. No matters were submitted to a vote of the Company's security holders during the fourth quarter of the fiscal year ended December 31, 2002. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS. The common shares of the Company are listed and posted for trading on the American Stock Exchange ("AMEX") since January 17, 2001 under the symbol "UPL" and the Toronto Stock Exchange ("TSE") since September 30, 1998 under the symbol "UP". The following table sets forth the high and low closing sales prices on the AMEX for 2002 and 2001 and on the TSE for 2002, 2001 and 2000 as reported by such exchanges, respectively.

AMERICAN STOCK EXCHANGE (US$) TORONTO STOCK EXCHANGE (CDN$) 2002 High Low 2002 High Low ---- ---- --- ---- ---- --- First Quarter $ 8.17 $ 5.71 First Quarter $13.10 $ 9.25 Second Quarter $ 9.22 $ 7.50 Second Quarter $14.50 $11.34 Third Quarter $ 8.59 $ 5.94 Third Quarter $13.51 $ 9.35 Fourth Quarter $ 9.99 $ 7.90 Fourth Quarter $15.62 $12.47 2001 High Low 2001 High Low ---- ---- --- ---- ---- --- First Quarter (beginning 1/17/01) $ 5.50 $ 3.00 First Quarter $ 8.70 $ 3.90 Second Quarter $ 7.34 $ 4.34 Second Quarter $10.95 $ 6.76 Third Quarter $ 5.92 $ 3.54 Third Quarter $ 9.00 $ 5.65 Fourth Quarter $ 6.41 $ 4.00 Fourth Quarter $10.05 $ 6.34

12

2000 High Low ---- ---- --- First Quarter $ 1.05 $ 0.78 Second Quarter $ 2.80 $ 0.79 Third Quarter $ 3.90 $ 2.03 Fourth Quarter $ 4.50 $ 3.25

On March 3, 2003, the last reported sale price of the common stock on the AMEX was $8.90 per share. As of March 3, 2003 there were approximately 449 holders of record of the common stock. The Company has not declared or paid and does not anticipate declaring or paying any dividends on its common stock in the near future. The Company intends to retain its cash flow from operations for the future operation and development of its business. In addition, the Company's credit facility restricts payment of dividends on its common stock. ITEM 6. SELECTED FINANCIAL DATA. The selected consolidated financial information presented below for the years ended December 31, 2002, 2001, 2000, the six months ended December 31, 1999 and the years ended June 30, 1999 and 1998 is derived from the Consolidated Financial Statements of the Corporation. Effective with the period ended December 31, 1999, the Company began utilizing a December 31 year-end.

SIX MONTHS ENDED YEARS ENDED DECEMBER 31, DECEMBER 31, YEARS ENDED JUNE 30, ------------------------ ------------ -------------------- 2002 2001 2000 1999 1999 1998 ---- ---- ---- ---- ---- ---- (IN THOUSANDS, EXCEPT PER SHARE DATA) Statement of Operations Data Revenues: Natural gas sales $38,503 $38,204 $19,399 $ 4,352 $ 6,352 $ 3,472 Oil sales 3,839 2,997 1,604 434 670 174 Interest and other 23 393 171 18 287 121 ------- ------- ------- ------- -------- -------- Total revenues 42,365 41,594 21,174 4,804 7,309 3,767 ======= ======= ======= ======= ======== ======== Expenses: Production expenses and taxes 11,411 9,023 4,241 1,329 2,571 953 Depreciation, depletion and amortization 9,712 6,687 3,163 1,186 1,794 1,377 General and administrative 4,199 3,894 2,828 1,668 5,861 3,406 Stock compensation 1,211 337 250 -- -- -- Interest 2,692 1,687 802 344 577 406 Ceiling test write-down -- -- -- -- 3,417 2,081 Loss on abandonment of oil and gas property -- -- -- -- -- 6,116 Bad debt expense (recovery) -- -- -- (35) 2,019 -- Lawsuit settlement -- -- -- 1,876 -- -- ------- ------- ------- ------- -------- -------- Total expenses 29,225 21,628 11,284 6,368 16,239 14,339 Income from continuing operations before income taxes 13,141 19,966 9,890 (1,564) (8,930) (10,572) Income tax provision - deferred 5,059 2,087 -- -- -- -- ------- ------- ------- ------- -------- -------- Net income $ 8,082 $17,879 $ 9,890 $(1,564) $ (8,930) $(10,572) ======= ======= ======= ======= ======== ======== Basic income per common share $ 0.11 $ 0.25 $ 0.17 $ (0.03) $ (0.16) $ (0.26) Diluted income per common share $ 0.10 $ 0.24 $ 0.17 $ (0.03) $ (0.16) $ (0.26)

13

SIX MONTHS ENDED YEARS ENDED DECEMBER 31, DECEMBER 31, YEARS ENDED JUNE 30, ------------------------ ------------ -------------------- 2002 2001 2000 1999 1999 1998 ---- ---- ---- ---- ---- ---- (IN THOUSANDS) Statement of Cash Flows Data Net cash provided by (used in): Operating activities $ 19,202 $ 35,098 $ 9,046 $ 674 $ 1,913 $ (7,915) Investing activities (62,072) (60,824) (24,541) (1,624) (1,017) (30,032) Financing activities 42,908 25,961 16,236 569 (6,010) 39,094

AS OF JUNE 30, 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- Balance Sheet Data Cash and cash equivalents $ 1,418 $ 1,379 $ 1,144 $ 402 $ 5,896 Working capital (deficit) (4,415) (6,635) 241 195 8,107 Oil and gas properties 207,362 155,221 59,729 33,773 37,392 Total assets 221,874 167,583 73,177 38,063 56,137 Total long-term debt 89,859 48,885 24,731 8,767 10,696 Deferred income taxes 10,033 4,974 -- -- -- Total stockholders' equity 104,067 95,320 35,694 25,632 35,372

ITEM 7. 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. 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. Since its entry into the oil and gas industry in 1993, the Company has continued to raise capital for its exploration and development programs, most of which are based in the United States. 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 - YEAR ENDED DECEMBER 31, 2002 COMPARED TO YEAR ENDED DECEMBER 31, 2001 Oil and gas revenues increased to $42.3 million for the year ended December 31, 2002 from $41.2 million for the same period in 2001. This increase was attributable to an increase in the Company's production offsetting a decline in the price received for that production. During this period the Company's production increased to 16.5 Bcf of gas and 151.0 thousand barrels of condensate, up from 11.5 Bcf of gas and 116.4 thousand barrels of condensate for the same period in 2001. This 43% increase on a Mcfe basis was attributable to the Company's successful drilling activities during 2001 and 2002. During the year ended December 31, 2002 the average product prices were $2.33 per Mcf and $25.39 per barrel, compared to $3.32 per Mcf and $25.74 per barrel for the same period in 2001. Production costs increased to $2.4 million in 2002 from $1.4 million in 2001. On a unit of production basis, costs were $0.135 per Mcfe in 2002, as compared to $0.118 per Mcfe in 2001. Production taxes in 2002 were $4.1 million, compared to $4.4 million in 2001, or $0.237 per Mcfe in 2002, compared to $0.363 per Mcfe in 2001. Production taxes are calculated based on a percentage of revenue from production. Therefore, lower prices received reduced the cost on a per unit basis. Gathering fees for the period increased to $4.9 million in 2002 from $3.2 million in 2001, attributable to higher production volumes and slightly higher gathering rates related to capacity constraints. 14 Depletion, depreciation and amortization ("DD&A") expenses increased to $9.7 million during the year ended December 31, 2002 from $6.7 million for the same period in 2001. On a unit basis, DD&A increased slightly to $0.558 per Mcfe in 2002, from $0.548 per Mcfe in 2001 primarily as a result of increases in future development costs relative to increases in the proved reserves used to calculate depletion of the full cost pool. General and administrative expenses increased to $4.2 million during the year ended December 31, 2002 from $3.9 million for the same period in 2001. The increase was primarily attributable to increases in personnel and overhead expenses arising from the increases in activity on the Wyoming properties. Stock compensation expense increased to $1.2 million in 2002 from $0.3 million in 2001. This increase is attributable to the increased number of shares granted and the share price at the time the stock was granted. Interest expense for the period increased to $2.7 million in 2002 from $1.7 million in 2001. This increase was attributable to the increase in borrowing under the senior credit facility. Interest and other income for the period decreased to $0.0 million in 2002 from $0.4 million in 2001. This decrease was primarily attributable to a change in the way income from Company owned well service equipment was accounted for and, secondarily, from lower interest received on balances in interest bearing accounts in 2002. Deferred income taxes for the period increased to $5.1 million in 2002 from $2.1 million in 2001. This increase was attributable to an increase in the tax rate due to the absence of book tax losses available to offset book taxable income as compared to 2001. The Company was not liable for current payment of any material income taxes for the period ending December 31, 2002. RESULTS OF OPERATIONS - YEAR ENDED DECEMBER 31, 2001 COMPARED TO YEAR ENDED DECEMBER 31, 2000 Oil and gas revenues increased to $41.2 million for the year ended December 31, 2001 from $21.0 million for the same period in 2000. This 96% increase was attributable to an increase in the Company's production. During this period the Company's production increased to 11.5 Bcf of gas and 116.4 thousand barrels of condensate, up from 5.3 Bcf of gas and 50.4 thousand barrels of condensate for the same period in 2000. This 118% increase on an Mcfe basis was attributable to the Company's successful drilling activities during 2000 and 2001. During the year ended December 31, 2001 the average product prices were $3.32 per Mcf and $25.74 per barrel, compared to $3.66 per Mcf and $31.83 per barrel for the same period in 2000. Production costs increased 100% to $1.4 million in 2001 from $0.7 million in 2000 and on a unit of production basis were $0.118 per Mcfe in 2001, as compared to $0.119 per Mcfe in 2000. Production taxes in 2001 were $4.4 million, compared to $2.3 million in 2000, or $0.363 per Mcfe in 2001, compared to $0.402 per Mcfe in 2000. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher production and the subsequent increase in revenue contributed to the increases. Gathering fees for the period increased 146% to $3.2 million in 2001 from $1.3 million in 2000, attributable to higher production volumes. DD&A expenses increased to $6.7 million during the year ended December 31, 2001 from $3.2 million for the same period in 2000. On a unit basis, DD&A decreased to $0.548 per Mcfe in 2001, from $0.565 per Mcfe in 2000 primarily as a result of increases in the proved reserves used to calculate depletion of the full cost pool. General and administrative expenses increased to $3.9 million during the year ended December 31, 2001 from $2.8 million for the same period in 2000. The increase was primarily attributable to increases in personnel and overhead expenses arising from the acquisition and operations of the China properties and increases in activity on the Wyoming properties. Interest expense for the period increased to $1.7 million in 2001 from $0.8 million in 2000. This increase was attributable to the increase in borrowings under the senior credit facility. Interest and other income for the period increased to $0.4 million in 2001 from $0.2 million in 2000. This increase was attributable to increased utilization of Company owned well service equipment and higher balances in interest bearing accounts in 2001. 15 Deferred income taxes for the period increased to $2.1 million in 2001 from $0.0 in 2000. This increase was primarily attributable to the increase in pre-tax net income relative to book net operating losses available to offset net income. The Company expects to book deferred taxes at the statutory rate in future periods. The Company was not liable for current payment of any material income taxes for the period ending December 31, 2001. On January 16, 2001, the Company acquired all of the outstanding capital stock of Pendaries Petroleum Ltd., a New Brunswick company, in exchange for 14,994,958 common shares of the Company. LIQUIDITY AND CAPITAL RESOURCES In the year ending December 31, 2002, the Company relied on its existing senior credit facility and cash provided by operations to finance its capital expenditures. The Company participated in the drilling of 26 gross (10.72 net) wells in Wyoming, 5 gross (0.88 net) wells in the China blocks and one gross (0.15 net) well in Texas. For the twelve-month period ending December 31, 2002 net capital expenditures were $62.1 million. At December 31, 2002, the Company reported a cash position of $1.4 million compared to $1.4 million at December 31, 2001. Working capital at December 31, 2002 was $(4.4) million as compared to $(6.6) million at December 31, 2001. As of December 31, 2002, the Company had incurred bank indebtedness of $86.0 million and other long-term debt of $3.9 million which was comprised of items payable in more than one year. The positive cash provided by operating activities that the Company continues to produce, along with the availability under the senior credit facility, are projected to be sufficient to fund the Company's budgeted capital expenditures for 2003, which are currently projected to be $80.0 million. Of the $80.0 million budget, the Company plans to spend approximately $60.0 million of its 2003 budget in Wyoming and approximately $20.0 million in China. Of the $60.0 million for Wyoming, the Company plans to drill or participate in an estimated 30 gross wells in 2003, of which approximately 50% 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 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, G&A expenditures and advances to Sino-American Energy. 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, 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 December 31, 2002 the Company had $86.0 million of outstanding borrowings under this credit facility, with a current average interest rate of approximately 3.3%. The Company was in compliance with all loan covenants at December 31, 2002. During the year ended December 31, 2002, net cash provided by operating activities was $19.2 million as compared to $35.1 million for the year ended December 31, 2001 and $9.0 million for the year ended December 31, 2000. Cash flow from operations before changes in non-cash working capital was $24.1 million for the year ended December 31, 2002 as compared to $27.0 million for the year ended December 31, 2001 and $13.0 million for the year ended December 31, 2000. The decrease in cash provided by operating activities was attributable to the decrease in earnings and the decrease in net changes to non-cash working capital items. During the year ended December 31, 2002, cash used in investing activities was $62.1 million as compared to $60.8 million for the year ended December 31, 2001 and $24.5 million for the year ended December 31, 2000. The change is primarily attributable to increased drilling and completion activity in Wyoming. 16 During the year ended December 31, 2002, cash provided by financing activities was $42.9 million as compared to $26.0 million for the year ended December 31, 2001 and $16.2 million for the year ended December 31, 2000. The change is primarily attributable to increased borrowing under the senior credit facility. CONTRACTUAL OBLIGATIONS The following table summarizes our contractual obligations as of December 31, 2002:

2003 2004-2005 2006-2007 After 2007 Total ---- --------- --------- ---------- ----- Long-term debt $ -- $86,000,000 $ -- $ -- $86,000,000 Operating Leases 291,015 198,030 132,020 -- 621,065 ----------- -------- ---- ----------- Total contractual obligations $291,015 $86,198,030 $132,020 $-- $86,621,065 ======== =========== ======== ==== ===========

The Company's senior credit facility with its group of banks matures on March 1, 2005. Unless the facility is extended or a new facility put into place, the full amount drawn under the facility would become due and payable at that time. The Company believes that it will be able to extend or renew the facility or one substantially similar to the existing facility prior to March 1, 2005. The Company has signed a LOI for its 8.92% share of a 15 year contract (extensions up to 25 years provided) to lease a FPSO. The LOI provides for the lease to be signed and come into force when and if the government of China approves the ODP, which is expected during the first half of 2003. The FPSO service agreement calls for a day rate lease payment and a sliding scale per barrel processing fee that decreases based on cumulative barrels processed. Lease cancellation on the part of the Company prior to the FPSO starting offshore operations would commit the Company to its 8.92% share of up to $50 million in cancellation fees. The lease cancellation fee, after commencement of offshore operations, would be based on a sliding time-scale (cancellation fee decreases with time) with 8.92% of $50 million the maximum cancellation fee. The Company considers it very unlikely that a lease cancellation situation will occur. Due to these terms of the lease, the Company cannot estimate with any degree of accuracy the costs it may incur during the life of the lease. Additionally, in maintaining its acreage base that is not held by production, the Company incurs certain expenses including delay rental costs. From year to year, the Company's acreage base varies, sometimes dramatically, rendering it impossible to forecast with any accuracy what the amount of these holding expenses will be. In 2002, total holding costs for all of the Company's leases not held by production were $313,122. Although the Company projects that the positive cash provided by operating activities and the availability under the senior credit facility will be sufficient to fund the Company's budgeted capital expenditures for 2003, future cash provided by operating activities and continued availability of financing are subject to a number of uncertainties beyond the Company's control such as the price of gas and oil, production rates, continued results of the Company's drilling program and the general condition of the capital markets for oil and gas companies. There can be no assurances that adequate funding will be available to execute the Company's planned future capital program. CRITICAL ACCOUNTING POLICIES 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. Use of Estimates. The more significant areas requiring the use of assumptions, judgments and estimates relate to volumes of oil and gas reserves used in calculating depletion, depreciation and amortization, the amount of future net revenues used in computing the ceiling test limitations and the amount of abandonment obligations used in such calculations. Assumptions, judgments and estimates are also required in determining impairments of undeveloped properties and the valuation of deferred tax assets. 17 The Company emphasizes that the volumes of reserves are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data as well as production performance data. These estimates, made by the Company's engineers, or by independent petroleum engineers, are reviewed and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in assumptions based on, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in prices, for example, may cause a reduction in some proved reserves due to uneconomic conditions. Due to the volatility of commodity prices, the oil and gas prices on the last day of the quarter significantly impact the calculation of the PV 10. The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company's proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Full Cost Method of Accounting. The Company uses the "full cost method" of accounting for its oil and gas operations. Separate cost centers are maintained for each country in which the Company incurs costs. All costs incurred in the acquisition, exploration and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals, dry holes and overhead related to exploration and development activities) are capitalized. Capitalized costs applicable to each full cost center are depleted using the units of production method based on conversion to common units of measure using one barrel of oil as an equivalent to six thousand cubic feet of natural gas. A reserve is also provided for estimated future development costs related to proved reserves and for estimated future costs of site restoration, dismantlement and abandonment as a component of depletion expense. The present value of oil and gas properties represents the estimated future net cash flows from proved oil and gas reserves, discounted using a prescribed 10% discount rate ("PV 10"). Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGLs that geological and engineering data demonstrate with reasonable certainty can be recovered in future years from known reservoirs under existing economic and operating conditions. Reserves are considered "proved" if they can be produced economically as demonstrated by either actual production or conclusive formation tests. "Proved developed" oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent costs of investments in unproved properties, pending the determination of the existence of proved reserves 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 costs excluded are reviewed quarterly to determine if impairment has occurred. Any impairment is transferred to the costs to be amortized. Costs excluded for oil and gas properties are generally classified and evaluated as significant or individually insignificant properties. Unproved properties whose costs are individually significant are assessed individually by considering the primary lease terms of the properties, the holding period of the properties, and geographic and geologic data obtained relating to the properties. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, such properties are grouped for purposes of assessing impairment. Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test is performed on a country-by- country basis. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves. This ceiling is compared to the net book value of the oil and gas properties reduced by any related deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, an impairment or non-cash write down is required. A ceiling test impairment can give the Company a significant loss for a particular period; however, future depletion, depreciation and amoritization expense would be reduced. The following is a summary of major issues related to the Company's ceiling test calculation. The Company did not have any writedowns related to the full cost ceiling limitation in 2002, 2001 or 2000. As of December 31, 2002, the ceiling limitation exceeded the carrying value of the Company's oil and gas properties by approximately $200 million in the U.S. The Company's China properties have not yet been subject 18 to a ceiling test, as there have not been any proved reserves booked to date. Estimates of discounted future net cash flows at December 31, 2002 were based on average natural gas prices of approximately $2.94 per MCF in the U.S. and on average liquids prices of approximately $30.55 per barrel in the U.S. A reduction in oil and gas prices and/or estimated quantities of oil and gas reserves would reduce the ceiling limitation in the U.S. and could result in a ceiling test writedown. In China, the existence of proved reserves has not yet been determined, therefore, leasehold costs, seismic costs and other costs incurred during the exploration phase remain capitalized as unproved property costs until proved reserves have been established or until exploration activities cease. If exploration activities result in the establishment of proved reserves, amounts are reclassified as proved properties and become subject to depreciation, depletion and amortization and the application of the ceiling test. If exploration efforts are unsuccessful in establishing proved reserves and exploration activities cease, the amounts accumulated as unproved costs are charged against earnings as impairments. As of December 31, 2002, costs related to these international projects of approximately $65.0 million dollars were not being depleted pending determination of the existence of proved reserves. Changes in estimates of reserves, future development costs or future abandonment costs are accounted for prospectively in the depletion calculations. Entitlements Method of Accounting for Oil and Gas Sales. The Company accounts for oil and gas sales using the "entitlements method." Under the entitlements method, revenue is recorded based upon its ownership share of volumes sold, regardless of whether it has taken its ownership share of such volumes. The Company records a receivable or a liability to the extent it receives less or more than its share of the volumes and related revenue. Under the alternative "sales method" of accounting for oil and gas sales, revenue is recorded based on volumes taken by the Company or allocated to it by third parties, regardless of whether such volumes are more or less than its ownership share of volumes produced. Reserve estimates are adjusted to reflect any over-produced or under-produced positions. Receivables or payables are recognized on a company's balance sheet only to the extent that remaining reserves are not sufficient to satisfy volumes over- or under-produced. Make-up provisions and ultimate settlements of volume imbalances are generally governed by agreements between the Company and its partners with respect to specific properties or, in the absence of such agreements, through negotiation. The value of volumes over- or under-produced can change based on changes in commodity prices. The Company prefers the entitlements method of accounting for oil and gas sales because it allows for recognition of revenue based on its actual share of jointly owned production, results in better matching of revenue with related operating expenses, and provides balance sheet recognition of the estimated value of product imbalances. At December 31, 2002, the Company had taken approximately 1,000 MMcf more than its entitled share of production. The estimated value of this imbalance of approximately $2 million was recorded as a long-term liability. Valuation of Deferred Tax Assets. The Company uses the asset and liability method of accounting for income taxes. Under this method, future income tax assets and liabilities are determined based on differences between the financial statement carrying values and their respective income tax bases (temporary differences). Future income tax assets and liabilities are measured using the tax rates expected to be in effect when the temporary differences are likely to reverse. The effect on future income tax assets and liabilities of a change in tax rates is included in operations in the period in which the change is enacted. The amount of future income tax assets recognized is limited to the amount of the benefit that is more likely than not to be realized. To assess the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. In order to fully realize its U.S. net deferred tax asset at December 31, 2002, the Company will need to generate future taxable income prior to the expiration of the net operating loss carry-forwards in 2003 to 2022. Based upon the level of historical taxable income and projections for future taxable income over the periods, which the deferred tax assets are deductible, management believes it is more likely than not the Company will realize the benefits of these 19 deductible differences, net of the existing valuation allowances at December 31, 2002. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carry-forward periods are reduced. Commodity Derivative Instruments and Hedging Activities. 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 price swaps, which are generally 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. RECENTLY ISSUED ACCOUNTING STANDARDS 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. Based on current estimates, the Company would record asset retirement obligations (using a 10% discount rate) and a cumulative effect of change in accounting principle on prior years, related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligation, and corresponding increase in the carrying amount of the related long-lived asset. Currently the Company's assessment has been deemed not material. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"). SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This Statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. SFAS No. 144 also broadens the definition of discontinued operations to include all distinguishable components of an entity that will be eliminated from ongoing operations. The Company has adopted SFAS No. 144 as of January 1, 2002. Because the Company has elected the full-cost method of accounting for oil and gas exploration and development activities, the impairment provisions of SFAS No. 144 do not apply to the Company's oil and gas assets, which are subject to ceiling limitations. For the Company's non-oil and gas assets, the method of impairment assessment is unchanged from SFAS No. 121. The adoption of SFAS No. 144 had no impact on the Company's consolidated financial statements. Statement 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections ("SFAS No. 145") was issued in April 2002. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of income taxes. As a result, the criteria in APB 30 will now be used to classify those gains and losses. Any gain or loss on the extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB 30 for classification as an extraordinary item shall be reclassified. The provisions of this Statement are effective for fiscal years beginning after January 1, 2003. The Company expects adoption of this 20 statement to result in the reclassification of losses on extinguishment of debt for all periods from extraordinary to other income and expense. Statement 146, Accounting for Exit or Disposal Activities ("SFAS No. 146"), was issued in June 2002. SFAS No. 146 addresses significant issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance set forth in EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." SFAS No. 146 will be effective for the Company in January 2003. The Company expects the adoption of SFAS No. 146 to have no impact on its financial statements. In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-based Compensation-Transition and Disclosure ("SFAS No. 148"). SFAS No. 148 amended FASB Statement No. 123, Accounting for Stock-Based Compensation ("Statement 123") to provide alternative methods of transition for a voluntary change to the fair-value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require 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 provisions of SFAS No.148 have no material impact on the Company, as it does not plan to adopt the fair-value method of accounting for stock options at the current time. The Company has included the required disclosures in Note 1 to the Consolidated Financial Statements. In November 2002, the FASB issued Financial Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57 and 107 and rescission of FASB Interpretation No. 34 ("FIN 45"). FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor's fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. As of March 3, 2003, the Company had no guarantees, other than to wholly owned subsidiaries that are consolidated in place. In January 2003, the FASB issued Financial Interpretation No. 46, Consolidation of Variable Interest Entities - an interpretation of ARB No. 51 ("FIN 46" or "Interpretation"). FIN 46 is an interpretation of Accounting Research Bulletin 51, Consolidated Financial Statements, and addresses consolidation by business enterprises of variable interest entities ("VIE"). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. At this time, the Company does not have any VIEs. RISK FACTORS AND CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS 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 Item 7, 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 21 can give no assurances that the assumptions upon which such forward-looking statements are based will prove to be correct. Important factors that could cause actual results to differ materially from the Company's expectations are included throughout this document. The Cautionary Statements expressly qualify all subsequent written and oral forward-looking statements attributable to the Company or persons acting on the Company's behalf. Competition. The Company competes with numerous other companies in virtually all facets of its business. The competitors in development, exploration, acquisitions and production include the major oil companies as well as numerous independents, including many that have significantly greater resources. Therefore, competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources of the Company permit. The ability of the Company to increase reserves in the future will be dependent on its ability to select and acquire suitable prospects for future exploration and development. The availability of a market for oil and natural gas production depends upon numerous factors beyond the control of the Company, including but not limited to the availability of other domestic or imported production, the locations and capacity of pipelines, and the effect of federal and state regulations on production. Historically, the Company's projects have been financed through debt and internally generated cash flow. There is competition for capital to finance oil and gas drilling. The ability of the Company to obtain such financing is uncertain and can be affected by numerous factors beyond its control. The inability of the Company to raise capital in the future could have an adverse effect on certain areas of the business. Marketing of Oil and Natural Gas. The ability to market oil and natural gas depends on numerous factors beyond the Company's control. These factors include: - the extent of domestic production and imports of oil and natural gas; - the availability of pipeline capacity; - the effects of inclement weather; - the demand for oil and natural gas by utilities and other end users; - the availability of alternative fuel sources; - the proximity of natural gas production to natural gas pipelines; - state and federal regulations of oil and natural gas marketing; and - federal regulation of natural gas sold or transported in interstate commerce. Because of these factors, The Company may be unable to market all of the oil and natural gas that it produces, including oil and natural gas that may be produced from the Bohai Bay properties. In addition, it may be unable to obtain favorable prices for the oil and natural gas it produces. Volatility of Oil and Gas Prices. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the Company's control. These factors include but are not limited to weather conditions in the United States, the condition of the United States economy, the actions of the Organization of Petroleum Exporting Countries ("OPEC'), governmental regulation, political stability in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign oil and gas imports and the availability of alternate fuel sources and transportation interruption. Any substantial and extended decline in the price of oil or gas would have an adverse effect on the carrying value of the Company's proved reserves, borrowing capacity, the Company's ability to obtain additional capital, and the Company's revenues, profitability and cash flows from operations. Volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and divestiture and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploitation projects. Price of Wyoming Production. The Company produces natural gas in Wyoming. The market price for this natural gas differs from the market indices for natural gas in the Gulf Coast region of the United States due potentially to insufficient pipeline capacity and/or low demand in the summer months for natural gas in the Rocky Mountain region of the United States. Therefore, the effect of a price decrease may more adversely effect the price received for the Company's Wyoming production than production in the other U.S. regions. 22 Government Regulations. The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may: - require that the Company acquire permits before commencing drilling; - restrict the substances that can be released into the environment in connection with drilling and production activities; - limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas; - require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and - require governmental approval of the overall development plan prior to start of development of fields in China. Under these laws and regulations, the Company could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. The Company maintains limited insurance coverage for sudden and accidental environmental damages, but does not maintain insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages. Accordingly, the Company may be subject to liability or may be required to cease production from properties in the event of environmental damages. A significant percentage of the Company's United States operations are conducted on federal lands. These operations are subject to a variety of on-site security regulations as well as other permits and authorizations issued by the BLM, the Wyoming Department of Environmental Quality and other agencies. A portion of the Company's acreage is affected by winter lease stipulations that prohibit exploration, drilling and completing activities generally from November 15 to May 15, but allow production activities all year round. To drill wells in Wyoming, the Company is required to file an Application for Permit to Drill with the Wyoming Oil and Gas Conservation Commission. Drilling on acreage controlled by the federal government requires the filing of a similar application with the BLM. These permitting requirements may adversely affect the Company's ability to complete its drilling program at the cost and in the time period currently anticipated. On large-scale projects, lessees may be required to perform environmental impact statements to assess the environmental impact of potential development, which can delay project implementation and/or result in the imposition of the environmental restrictions that could have a material impact on cost or scope. Limited Financial Resources. The Company's ability to continue exploration and development of its properties and to replace reserves may be dependent upon its ability to continue to raise significant additional financing, including debt financing that may be significant, or obtain some other arrangements with industry partners in lieu of raising financing. Any arrangements that may be entered into could be expensive to the Company. There can be no assurance that the Company will be able to raise additional capital in light of factors such as the market demand for its securities, the state of financial markets for independent oil companies (including the markets for debt), oil and gas prices and general market conditions. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" for a discussion of the Company's capital budget. The Company expects to continue using its bank credit facility to borrow funds to supplement its available cash flow. The amount the Company may borrow under the credit facility may not exceed a borrowing base determined by the lenders based on their projections of the Company's future production, future production costs and taxes, commodity prices and other factors. The Company cannot control the assumptions the lenders use to calculate the borrowing base. The lenders may, without the Company's consent, adjust the borrowing base at any time. If the Company's borrowings under the credit facility exceed the borrowing base, the lenders may require that the Company repay the excess. If this were to occur, the Company may have to sell assets or seek financing from other sources. The Company can make no assurances that it would be successful in selling assets or arranging substitute financing. For a description of the bank credit facility and its principal terms and conditions, see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." Interruptions from Severe Weather. The Company's operations are conducted principally in the Rocky Mountain region. The weather in this area can be extreme and can cause interruption in the Company's exploration and production operations. Moreover, especially severe weather can result in damage to facilities entailing longer operational interruptions and significant capital investment. Likewise, the Company's Rocky 23 Mountain operations are subject to disruption from winter storms and severe cold, which can limit operations involving fluids and impair access to the Company's facilities. A portion of the Company's acreage is affected by winter lease stipulations that restrict the period of time during which operations may be conducted on the leases. The Company's leases that are affected by the winter stipulations prohibit drilling and completing activities from mid-November to mid-May, but allow production activities all year round. The Company Invests Heavily in Exploration. The Company has historically invested a significant portion of its capital budget in drilling exploratory wells in search of unproved oil and gas reserves. The Company cannot be certain that the exploratory wells it drills will be productive or that it will recover all or any portion of its investments. In order to increase the chances for exploratory success, the Company often invests in seismic or other geoscience data to assist it in identifying potential drilling objectives. Additionally, the cost of drilling, completing and testing exploratory wells is often uncertain at the time of the Company's initial investment. Depending on complications encountered while drilling, the final cost of the well may significantly exceed that which the Company originally estimated. The Company capitalizes all direct costs of drilling an unsuccessful exploratory well in the period in which the well is determined not to be producible in commercial quantities. Under the full-cost method of accounting these costs are then depleted using the units of production method based on the Company's proven reserves. Replacement of Reserves. The Company's future success may depend on its ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. Without successful exploration, development or acquisition activities, the Company's reserves and production will decline. The Company can give no assurance that it will be able to find, develop or acquire additional reserves at acceptable costs. Operating Hazards and Uninsured Risks. The oil and gas business involves a variety of operating risks, including fire, explosion, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as oil spills, gas leaks, and discharges of toxic gases. The occurrence of any of these events with respect to any property operated or owned (in whole or in part) by the Company could have a material adverse impact on the Company. The Company and the operators of its properties maintain insurance in accordance with customary industry practices and in amounts that management believes to be reasonable. However, insurance coverage is not always economically feasible and is not obtained to cover all types of operational risks. The occurrence of a significant event that is not fully insured could have a material adverse effect on the Company's financial condition. Drilling and Operating Risks. The Company's oil and gas operations are subject to all of the risks and hazards typically associated with drilling for, and production and transportation of, oil and gas. These risks include the necessity of spending large amounts of money for identification and acquisition of properties and for drilling and completion of wells. In the drilling of exploratory or development wells, failures and losses may occur before any deposits of oil or gas are found. The presence of unanticipated pressure or irregularities in formations, blow-outs or accidents may cause such activity to be unsuccessful, resulting in a loss of the Company's investment in such activity. If oil or gas is encountered, there can be no assurance that it can be produced in quantities sufficient to justify the cost of continuing such operations or that it can be marketed satisfactorily. Drilling Plans Subject to Change. This report includes certain descriptions of the Company's future drilling plans with respect to its prospects. A prospect is an area which the Company's geoscientists have identified what they believe, based on available seismic and geological information, to be indications of hydrocarbons. The Company's prospects are in various stages of review. Whether or not the Company ultimately drills a prospect may depend on the following factors: receipt of additional seismic data or reprocessing of existing data; material changes in oil or gas prices; the costs and availability of drilling equipment; success or failure of wells drilled in similar formations or which would use the same production facilities; availability and cost of capital; changes in the estimates of costs to drill or complete wells; the approval of partners to participate in the drilling or, in the case of CNOOC, approval of expenditures for budget purposes; the Company's ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; decisions of the Company's joint working interest owners; and the BLM's interpretation of the EIS and the results of the permitting process. The Company will continue to gather data about its prospects, and it is possible that additional information may cause the Company to alter its drilling schedule or determine that a prospect should not be pursued at all. 24 Financial Reporting Impact of Full Cost Method of Accounting. The Company follows the full cost method of accounting for its oil and gas properties. A separate cost center is maintained for expenditures applicable to each country in which the Company conducts exploration and/or production activities. Under such method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated "ceiling." The ceiling is the estimated after tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and gas prices in effect at the time of the calculation are held constant, except for changes which are fixed and determinable by existing contracts. The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an expense. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings. Risks Arising From Being Non-Operator in Bohai Bay. Because the Company is not the operator and holds a minority interest it cannot control the pace of exploration or development in the Bohai Bay properties or major decisions affecting drilling of wells or the plan for development and production, although contract provisions give the Company certain consent rights in some matters. Kerr-McGee's influence over these matters can affect the pace at which the Company spends money on this project. If Kerr-McGee were to shift its focus from this project, the pace of development of the Blocks could slow down or stop altogether. The Company currently does not believe it has sufficient funds to purchase Kerr-McGee's interests in these Blocks if they were offered. On the other hand, if Kerr-McGee were to decide to accelerate development of this project, the Company could be required to fund its share of costs at a faster pace than anticipated, which might exceed its ability to raise funds. If, because of this, the Company were unable to pay its share of costs, it could lose or be forced to sell its interest in the Bohai Bay properties or be forced to not participate in the exploration or development of specific prospects or fields on the Blocks, potentially diminishing the value of its Bohai Bay assets. Political, Economic or International Factors Affecting China. Ownership of property interests and production operations in areas outside the United States are subject to various risks inherent in foreign operations. These risks may include: - loss of revenue, property and equipment as a result of expropriation, nationalization, war or insurrections; - increases in taxes and governmental royalties; - renegotiation of contracts with governmental entities and quasi-governmental agencies; - change in laws and policies governing operations of foreign based companies; - labor problems; - other uncertainties arising out of foreign government sovereignty over its international operations; and - currency restrictions and exchange rate fluctuations. Tensions between China and its neighbors or various Western countries, regional political or military disruption, changes in internal Chinese leadership, social or political disruptions within China, a downturn in the Chinese economy, or a change in Chinese laws or attitudes toward foreign investment could make China an unfavorable environment in which to invest. Although all the foreign interest owners in the Bohai Bay properties have the right to sell production in the world market, the regulation of the concession by China, and the likely participation by CNOOC as a large working interest owner, make Chinese internal and external affairs important to the investment in the Bohai Bay. If any of these negative events were to occur, it could lead to a decision that there is an intolerable level of risk in continuing with the investment, or the Company may be unable to attract equity investors or lenders, or satisfy any then-existing lenders. In the event of a dispute arising from foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts in the United States or a potentially more favorable country. In addition, the Company's China PSCs terminate after 15 years of production, unless extended as provided for, which may be prior to the end of the productive life of the fields. Operating Risks in China. Offshore operations, such as the Company's Bohai Bay properties, are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and/or loss 25 from storms or other adverse weather conditions. These conditions can cause substantial damage to facilities and interrupt production. As a result, the Company could incur substantial liabilities that could result in financial losses or failures. China has many regulations similar to those addressed in Item I, Environmental Regulation that may expose the Company to liability. Offshore projects, like the China field developments, are typically large, complex construction projects that are potentially subject to delays which may cause delays in achieving production and profitability. CERTAIN DEFINITIONS TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS - Bbl -- One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons. - Bcf -- One billion cubic feet of natural gas. - Bcfe -- One billion cubic feet of natural gas equivalent. - BOE -- One barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to 1 Bbl of oil. - BTU -- British Thermal Unit. - MBbl -- One thousand barrels. - Mcf -- One thousand cubic feet of natural gas. - Mcfe -- One thousand cubic feet of natural gas equivalent. - MMBbl -- One million barrels of oil or other liquid hydrocarbons. - MMcf -- One million cubic feet of natural gas. - MBOE -- One thousand BOE. - MMBOE -- One million BOE. - MMBTU -- One million British Thermal Unit. TERMS USED TO DESCRIBE THE COMPANY'S INTERESTS IN WELLS AND ACREAGE - Gross oil and gas wells or acres -- The Company's gross wells or gross acres represent the total number of wells or acres in which the Company owns a working interest. - Net oil and gas wells or acres -- Determined by multiplying "gross" oil and natural gas wells or acres by the working interest that the Company owns in such wells or acres represented by the underlying properties. TERMS USED TO ASSIGN A PRESENT VALUE TO THE COMPANY'S RESERVES - Standardized measure of discounted future net cash flows, after income taxes -- The present value, discounted at 10%, of the pre-tax future net cash flows attributable to estimated net proved reserves. The Company calculates this amount by assuming that it will sell the oil and gas production attributable to the proved reserves estimated in its independent engineer's reserve report for the prices it received for the production on the date of the report, unless it had a contract to sell the production for a different price. The Company also assumes that the cost to produce the reserves will remain constant at the costs prevailing on the date of the report. The assumed costs are subtracted from the assumed revenues resulting in a stream of future net cash flows. Estimated future income taxes using rates in effect on the date of the report are deducted from the net cash flow stream. The after-tax cash flows are discounted at 10% to result in the standardized measure of the Company's proved reserves. 26 - Standardized measure of discounted future net cash flows -- The discounted present value of proved reserves is identical to the standardized measure, except that estimated future income taxes are not deducted in calculating future net cash flows. The Company discloses the discounted present value without deducting estimated income taxes to provide what it believes is a better basis for comparison of its reserves to the producers who may have different tax rates. TERMS USED TO CLASSIFY THE COMPANY'S RESERVE QUANTITIES The SEC definition of proved oil and gas reserves, per Article 4-10(a)(2) of Regulation S-X, is as follows: Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (a) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (2) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (b) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (c) Estimates of proved reserves do not include the following: (1) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (2) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (3) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (4) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. - Proved developed reserves -- Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. - Proved undeveloped reserves -- Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF THE COMPANY'S OIL AND GAS PROPERTIES - Working interest -- A real property interest entitling the owner to receive a specified percentage of the proceeds of the sale of oil and natural gas production or a percentage of the production, but requiring the owner of the working interest to bear the cost to explore for, develop and produce such oil and natural gas. A working interest owner who owns a portion of the working interest may participate either as operator or by voting his percentage interest to approve or disapprove the appointment of an operator and drilling and other major activities in connection with the development and operation of a property. TERMS USED TO DESCRIBE SEISMIC OPERATIONS - Seismic data -- Oil and gas companies use seismic data as their principal source of information to locate oil and gas deposits, both to aid in exploration for new deposits and to manage or enhance production from known reservoirs. To gather seismic data, an energy source is used to send sound waves into the subsurface strata. These waves are reflected back to the surface by underground formations, where they are detected by geophones which digitize and record the reflected waves. Computers are then used to process the raw data to develop an image of underground formations. 27 - 2-D seismic data -- 2-D seismic survey data has been the standard acquisition technique used to image geologic formations over a broad area. 2-D seismic data is collected by a single line of energy sources which reflect seismic waves to a single line of geophones. When processed, 2-D seismic data produces an image of a single vertical plane of sub-surface data. - 3-D seismic data -- 3-D seismic data is collected using a grid of energy sources, which are generally spread over several miles. A 3-D survey produces a three dimensional image of the subsurface geology by collecting seismic data along parallel lines and creating a cube of information that can be divided into various planes, thus improving visualization. Consequently, 3-D seismic data is a more reliable indicator of potential oil and natural gas reservoirs in the area evaluated. ITEM 7A. 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 Ultra's United States natural gas production. Historically, prices received for gas production have been volatile and unpredictable. Pricing volatility is expected to continue. Gas price realizations ranged from a monthly low of $1.85 per Mcf to a monthly high of $3.23 per Mcf during 2002. Realized wellhead prices are from the financial statements, and include the effects of hedging, receipt of deferred revenues from Jonah Gas Gathering, and gas balancing between working interest owners. The Company periodically enters into various hedging arrangements for its natural gas production. During 2002, the Company received payments from counterparties totaling $1,835,800 as its net proceeds from hedging activities. This total includes $312,000 for the second quarter of 2002, $1,130,100 for the third quarter of 2002, and $393,700 for the fourth quarter of 2002. At year-end 2002, the Company had hedges in place covering approximately 15,000 MMBtu or approximately 13 MMcf of gas per day for calendar 2003 at an average price of $3.11 per MMBtu or approximately $3.35 per Mcf. Of these hedges 10,000 MMBtu are in the form of swaps and 5,000 MMBtu are fixed price forward sales at Opal, Wyoming. The swaps are priced relative to the index price at the first of each month at Opal, Wyoming, where the Company delivers most of its gas to the purchasers. 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 price of $3.75 per MMBtu or approximately $3.95 per Mcf (pricing referenced to Opal), plus an additional 5,000 MMBtu or approximately 4 MMcf of gas per day for the same period at a price of $4.25 per MMBtu or approximately $4.48 per Mcf (pricing referenced to Opal). The table below summarizes the hedges in place as of March 3, 2003:

Type Period Volume Price / MMBtu ---- ------ ------ ------------- 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 50% of the Company's forecasted production for the period from April 1, 2003 to October 31, 2003, and approximately 35% of the Company's forecasted production for calendar 2003. 28 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. MANAGEMENT'S REPORT The consolidated financial statements and all other information in the annual report are the responsibility of management. The consolidated financial statements and the financial information appearing in the annual report have been prepared in accordance with accounting principles generally accepted in the United States. Management has designed and maintains a system of internal accounting controls, policies and procedures in order to provide for the safeguarding of assets and preparation of relevant, reliable and timely financial information. External auditors, appointed by the shareholders, have examined the consolidated financial statements. The Board of Directors has reviewed the consolidated financial statements with management and the auditors, and has approved the statements. /s/ Michael D. Watford /s/ F. Fox Benton III Michael D. Watford F. Fox Benton III Chief Executive Officer Chief Financial Officer March 25, 2003 AUDITORS' REPORT To the Shareholders of Ultra Petroleum Corp. We have audited the consolidated balance sheets of Ultra Petroleum Corp. and subsidiaries as of December 31, 2002 and 2001, and the consolidated statements of operations, shareholders' equity and comprehensive income and cash flows for each of the years in the three- year period ended December 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in accordance with accounting principles generally accepted in the United States. /s/ KPMG, LLP KPMG, LLP Denver, Colorado February 28, 2003 29 ULTRA PETROLEUM CORP. CONSOLIDATED BALANCE SHEETS (Expressed in U.S. Dollars)

December 31, ASSETS 2002 2001 ------ ---- ---- Current Assets Cash and cash equivalents $ 1,417,711 $ 1,379,462 Restricted cash 209,306 207,179 Accounts receivable 11,398,483 7,358,742 Prepaid drilling costs and other current assets 474,279 2,823,613 ------------- ------------ 13,499,779 11,768,996 Oil and gas properties, using the full cost method of accounting (Note 3) 207,362,408 155,221,187 Capital assets (Note 4) 1,011,699 592,605 ------------- ------------ TOTAL ASSETS $ 221,873,886 $167,582,788 ============= ============ LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities Accounts payable and accrued liabilities $ 17,914,860 $ 18,403,862 Long-term debt (Note 5) 86,000,000 43,000,000 Deferred income taxes 10,033,174 4,974,008 Notes payable 3,858,810 5,885,414 Shareholders' equity: Common stock (Note 6) 95,098,690 92,585,148 Treasury stock (1,193,650) -- Other comprehensive loss (653,875) -- Accumulated retained earnings 10,815,877 2,734,356 ------------- ------------ Commitments and contingencies (Note 11) 104,067,042 95,319,504 ------------- ------------ TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 221,873,886 $167,582,788 ============= ============

See accompanying notes to consolidated financial statements. Approved on behalf of the Board: /s/ Michael Watford, Director /s/ James E. Nielson, Director 30 ULTRA PETROLEUM CORP. CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT

(Expressed in U.S. Dollars) Year Ended December 31, ----------------------- 2002 2001 2000 ---- ---- ---- REVENUES: Natural gas sales $ 38,502,971 $ 38,204,298 $ 19,399,001 Oil sales 3,839,421 2,996,955 1,603,635 ------------ ------------ ------------ 42,342,392 41,201,253 21,002,636 ------------ ------------ ------------ EXPENSES: Production expenses and taxes 11,410,868 9,023,271 4,241,020 Depletion and depreciation 9,712,111 6,687,433 3,162,568 General and administrative 4,199,104 3,894,185 2,828,156 Stock compensation 1,211,165 337,029 250,000 ------------ ------------ ------------ 26,533,248 19,941,918 10,481,744 OPERATING INCOME (LOSS) 15,809,144 21,259,335 10,520,892 OTHER INCOME (EXPENSE): Interest income 23,151 173,411 87,879 Interest expense (2,691,608) (1,687,172) (802,364) Other -- 220,016 83,519 ------------ ------------ ------------ (2,668,457) (1,293,745) (630,966) ------------ ------------ ------------ NET INCOME BEFORE INCOME TAXES 13,140,687 19,965,590 9,889,926 Income tax provision - deferred 5,059,166 2,086,762 -- NET INCOME 8,081,521 17,878,828 9,889,926 RETAINED EARNINGS (DEFICIT), beginning of period 2,734,356 (15,144,472) (25,034,398) ------------ ------------ ------------ RETAINED EARNINGS (DEFICIT), end of period $ 10,815,877 $ 2,734,356 $(15,144,472) ============ ============ ============ NET INCOME PER COMMON SHARE - BASIC $ 0.11 $ 0.25 $ 0.17 ============ ============ ============ NET INCOME PER COMMON SHARE - DILUTED $ 0.10 $ 0.24 $ 0.17 ============ ============ ============ Weighted average common shares outstanding - basic 73,770,841 72,371,839 56,821,748 ============ ============ ============ Weighted average common shares outstanding - diluted 77,605,018 75,931,529 58,438,783 ============ ============ ============

31 ULTRA PETROLEUM CORP. CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE LOSS Common stock

Authorized 10,000,000 preferred shares 100,000,000 common shares Year Ended Year Ended Year Ended December 31, 2002 December 31, 2001 December 31, 2000 ----------------- ----------------- ----------------- Issued Number Amount Number Amount Number Amount ------ ------ ------ ------ ------ ------ ------ Common Shares Balance, beginning of year 73,318,418 $ 92,585,148 56,939,762 $50,838,663 56,751,125 $50,666,631 Employee stock option plan 617,750 1,101,674 701,500 611,387 5,000 4,032 Employee stock plan 183,000 1,299,765 682,198 1,098,448 119,403 80,000 Fair value non-employee stock options -- 112,103 -- -- -- -- Acreage option purchase -- -- -- -- 64,234 88,000 Merger with Pendaries Petroleum Ltd. -- -- 14,994,958 40,036,650 -- -- ----------- ------------ ---------- ----------- ---------- ----------- Balance, end of period 74,119,168 $ 95,098,690 73,318,418 $92,585,148 56,939,762 $50,838,663 =========== ============ ========== =========== ========== =========== Treasury stock (132,500) (1,193,650) -- -- -- -- =========== ============ ========== =========== ========== =========== Other comprehensive loss -- (653,875) -- -- -- -- =========== ============ ========== =========== ========== ===========

32 ULTRA PETROLEUM CORP. CONSOLIDATED STATEMENTS OF CASH FLOW

Year Ended December 31, ----------------------- 2002 2001 2000 ---- ---- ---- Cash flows from operating activities: Income for the year $ 8,081,521 $ 17,878,828 $ 9,889,926 Adjustments to reconcile income to net cash provided by operating activities: Depletion and depreciation 9,712,111 6,687,433 3,162,568 Deferred income taxes 5,059,166 2,086,762 -- Stock compensation 1,211,165 337,030 250,000 Net changes in non-cash working capital: Restricted cash (2,127) (7,053) 390,145 Accounts receivable (4,039,741) 919,796 (5,740,728) Prepaid expenses and other current assets 1,695,459 (1,983,721) (511,023) Note receivable -- (683,137) -- Accounts payable and accrued liabilities (2,415,606) 9,962,508 1,705,546 Deferred revenue (100,000) (100,000) (100,000) ------------ ------------ ------------ Net cash provided by operating activities 19,201,948 35,098,446 9,046,434 ------------ ------------ ------------ Cash flows from investing activities: Oil and gas property expenditures (61,257,518) (60,818,735) (22,157,020) Note receivable -- -- (2,530,976) Purchase of capital assets (814,205) (317,592) (212,300) Proceeds from sale of oil and gas properties -- 312,365 359,764 ------------ ------------ ------------ Net cash used in investing activities (62,071,723) (60,823,962) (24,540,532) ------------ ------------ ------------ Cash flows from financing activities: Borrowings on long-term debt, net 43,000,000 25,350,000 16,063,966 Proceeds from issuance of common stock 1,101,674 611,387 172,032 Repurchase of common stock (1,193,650) -- -- ------------ ------------ ------------ Net cash provided by financing activities 42,908,024 25,961,387 16,235,998 ------------ ------------ ------------ Net increase in cash and cash equivalents 38,249 235,871 741,900 Cash and cash equivalents, beginning of year 1,379,462 1,143,591 401,691 ------------ ------------ ------------ Cash and cash equivalents, end of year $ 1,417,711 $ 1,379,462 $ 1,143,591 ============ ============ ============ SUPPLEMENTAL INFORMATION Cash paid for: Interest $ 2,691,608 $ 1,687,172 $ 802,364 Income taxes $ -- $ 10,000 $ 25,000 Supplemental schedule of non-cash investing activities Acquisitions Fair value of assets acquired $ -- $ 43,950,263 $ -- Less: liabilities assumed -- (4,225,978) -- Cash acquired -- 312,365 -- ------------ ------------ ------------ Fair value of stock issued $ -- $ 40,036,650 $ -- ============ ============ ============

See accompanying notes to consolidated financial statements 33 ULTRA PETROLEUM CORP. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Expressed in U.S. dollars unless otherwise noted) Years ended December 31, 2002, 2001 and 2000. 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 incorporated under the laws of British Columbia, Canada. At 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: (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 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. 34 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: 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 a financial institution and 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. (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 the 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 (loss) per share: Basic earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted earnings (loss) 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 for the years ended December 31, 2002, 2001 and 2000:

December 31, 2002 2001 2000 ---- ---- ---- Net income (loss) $ 8,081,521 $17,878,828 $ 9,889,926 =========== =========== =========== Weighted average common shares outstanding during the period 73,770,841 72,371,839 56,821,748 Effect of dilutive instruments 3,834,177 3,559,690 1,617,035 ----------- ----------- ----------- Weighted average common shares outstanding during the period including the effects of dilutive instruments 77,605,018 75,931,529 58,438,783 Basic earnings (loss) per share $ 0.11 $ 0.25 $ 0.17 =========== =========== =========== Diluted earnings (loss) per share $ 0.10 $ 0.24 $ 0.17 =========== =========== =========== Number of shares not included in dilutive earnings (loss) per share that would have been antidilutive because the exercise price was greater than the average market price of the common shares 130,570 373,942 -- =========== =========== ===========

(j) 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. (k) Reclassifications: Certain amounts in the financial statements of the prior years have been reclassified to conform to the current year financial statement presentation. 35 (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 (loss) and net income (loss) per common share would approximate the following pro forma amounts:

For the Years Ended December 31, -------------------------------- 2002 2001 2000 ---- ---- ---- (In thousands, except per share amounts) Net income: As reported $8,081,521 $17,878,828 $9,889,926 Pro forma $5,167,990 $14,924,923 $9,056,297 Net income per common share: Basic: As reported $0.11 $0.25 $0.17 Pro forma $0.07 $0.21 $0.16 Diluted: As reported $0.10 $0.24 $0.17 Pro forma $0.07 $0.20 $0.16

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 December 31, 2000, expected volatility of approximately 45%, at December 31, 2001, expected volatility of approximately 30%, at December 31, 2002, expected volatility of 30%. All options have expected lives of ten years. (m) Impact of recently issued accounting pronouncements: 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. Based on current estimates, the Company would record asset retirement obligations (using a 10% discount rate) and a cumulative effect of change in accounting principle on prior years, related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligation, and corresponding increase in the carrying amount of the related long-lived asset. Currently the Company's assessment has been deemed not material. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets ("SFAS No. 144"). SFAS No. 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This Statement requires that long-lived assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. SFAS No. 144 also broadens the definition of discontinued operations to include all distinguishable components of an entity that will be eliminated from ongoing operations. The Company has adopted SFAS No. 144 as of January 1, 2002. Because the Company has elected the full-cost method of accounting for oil and gas exploration and development activities, the impairment provisions of SFAS No. 144 do not apply to the Company's oil and gas assets, which are subject to ceiling limitations. For the Company's non-oil and gas assets, the method of impairment assessment is unchanged from SFAS No. 121. The adoption of SFAS No. 144 had no impact on the Company's consolidated financial statements. 36 Statement 145, Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections ("SFAS No. 145") was issued in April 2002. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of income taxes. As a result, the criteria in APB 30 will now be used to classify those gains and losses. Any gain or loss on the extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB 30 for classification as an extraordinary item shall be reclassified. The provisions of this Statement are effective for fiscal years beginning after January 1, 2003. We expect adoption of this statement to result in the reclassification of losses on extinguishment of debt for all periods from extraordinary to other income and expense. Statement 146, Accounting for Exit or Disposal Activities ("SFAS No. 146"), was issued in June 2002. SFAS No. 146 addresses significant issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that are currently accounted for pursuant to the guidance set forth in EITF Issue No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity ("Issue No. 94-3"). SFAS No. 146 will be effective for the Company in January 2003. We expect the adoption of SFAS No. 146 to have no impact on our financial statements. In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-based Compensation-Transition and Disclosure ("SFAS No. 148"). SFAS No. 148 amended FASB Statement No. 123, Accounting for Stock-Based Compensation ("Statement No. 123"), to provide alternative methods of transition for a voluntary change to the fair-value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement No. 123 to require 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 plan to adopt the fair-value method of accounting for stock options at the current time. We have included the required disclosures in Note 1 to the Consolidated Financial Statements. In November 2002, the FASB issued Financial Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others - an interpretation of FASB Statements No. 5, 57, and 107 and rescission of FASB Interpretation No. 34 ("FIN 45"). FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. The initial recognition and initial measurement provisions of FIN 45 are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the guarantor's fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The Company currently does not have any guarantees other than to wholly owned subsidiaries that are consolidated in place. In January 2003, the FASB issued Financial Interpretation No. 46, Consolidation of Variable Interest Entities - an interpretation of ARB No. 51 ("FIN 46" or "Interpretation"). FIN 46 is an interpretation of Accounting Research Bulletin 51, Consolidated Financial Statements, and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. The Interpretation requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to variable interest entities created after January 31, 2003, and to variable interest entities in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after June 15, 2003, to variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. At this time, the Company does not have any VIEs. 2. ACQUISITION OF PENDARIES PETROLEUM LTD: Effective January 16, 2001, the Company completed the previously announced agreement to acquire 100% of the outstanding shares of Pendaries Petroleum Ltd. ("Pendaries") and its wholly owned subsidiary Sino-American Energy Corporation in exchange for 14,994,958 shares of Ultra Petroleum Corp. common stock valued 37 at $2.67. The value of the shares was based on the average price of the shares a few days prior to and a few days subsequent to the date the transaction was closed. The transaction was accounted for using the purchase method of accounting and was valued at $40 million. The impact of the acquisition increased the undeveloped portion of the Company's full cost pool by $43 million and also carried to the balance sheet a net deferred tax liability of $962,081. This deferred tax liability was created as a result of a difference between the book and tax basis in Sino-American Energy Corporation's oil and gas properties. Accordingly, Pendaries' results of operations have been included in the consolidated financial statements of income from the effective date of acquisition. The consolidated balance sheet dated December 31, 2001, includes the assets and liabilities, as well as the adjustments required to record the acquisition in accordance with purchase accounting. 3. OIL AND GAS PROPERTIES:

December 31, December 31, 2002 2001 ---- ---- Developed Properties: Acquisition, equipment, exploration, development drilling and environmental costs $ 150,986,843 $ 100,574,404 Less accumulated depletion, depreciation and amortization (22,816,605) (13,499,605) ------------- ------------- 128,170,238 87,074,799 Unproved properties - China 64,873,186 55,894,246 Unproved properties - Wyoming 14,318,984 12,252,142 ------------- ------------- $ 207,362,408 $ 155,221,187 ============= =============

4. CAPITAL ASSETS:

December 31, December 31, December 31, December 31, 2002 2002 Accumulated 2002 Net 2001 Net Cost Depreciation Book Value Book Value ---- ------------ ---------- ---------- Computer equipment $ 617,439 $ 418,137 $ 199,302 $254,206 Office equipment 228,880 138,479 90,401 106,829 Field equipment 183,775 139,584 44,191 64,841 Other 1,007,917 330,112 677,805 166,729 ---------- ---------- ---------- -------- $2,038,011 $1,026,312 $1,011,699 $592,605 ========== ========== ========== ========

5. LONG-TERM DEBT:

December 31, December 31, 2002 2001 ---- ---- Bank indebtedness $86,000,000 $43,000,000 Other long-term obligations 3,858,810 2,892,486 Short-term obligations to be refinanced -- 3,092,928 ----------- ----------- $89,858,810 $48,985,414 =========== ===========

Bank indebtedness: 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 $150 million and an aggregate borrowing base of $120 million at November 4, 2002. At December 31, 2002, the Company had $86 million outstanding and $34 million unused and available on the credit facility. The credit facility matures on March 1, 2005. The notes bear interest at either the bank'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. 38 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 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, general and administrative expenditures and advances to Sino-American Energy Company. 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 be required to make immediate principal repayment. As of December 31, 2002, the Company was in compliance with the covenants and required ratios. Other long-term obligations: These costs relate to the long-term portion of production taxes payable. Short-term obligations to be refinanced: These items consist of drilling obligations which will be funded on a long-term basis through the use of the available borrowing base of bank indebtedness. 6. COMMON STOCK: (a) Stock options: The following table summarizes the changes in stock options for the three-year period ending December 31, 2002:

Number of Weighted Average Options Exercise Price (US$) ------- -------------------- Balance, December 31, 1999 4,519,860 $0.64 to $4.22 Granted 1,255,000 $0.51 to $2.65 Exercised (5,000) $0.76 Cancelled (1,244,860) $0.76 to $4.22 ---------- -------------- Balance, December 31, 2000 4,525,000 $0.51 to $2.65 Granted 1,630,000 $2.99 to $5.23 Exercised (701,500) $0.64 to $3.12 Cancelled (22,500) $1.14 to $5.23 ---------- -------------- Balance, December 31, 2001 5,431,000 $0.51 to $5.23 Granted 748,500 $7.82 to $8.86 Exercised (617,750) $0.64 to $5.23 ---------- -------------- Balance, December 31, 2002 5,561,750 $0.51 to $8.86

No compensation resulted from the granting of these options as all were granted at or above the market value of the common shares at the date of grant. Stock options granted to consultants have been assessed at fair value and capitalized to the full cost pool. The following table summarizes information about the stock options outstanding at December 31, 2002:

Options Outstanding Options Exercisable ------------------- ------------------- Weighted Weighted Weighted Average Average Average Range of Exercise Number Remaining Exercise Number Exercise Prices (Cdn$) Outstanding Contractual Life Price (US$) Exercisable Price (US$) ------------- ----------- ---------------- ----------- ----------- ----------- $0.51-$1.14 3,350,500 6.7 Years $0.89 3,350,500 $0.89 $4.15-$8.20 2,211,250 8.6 Years $3.26 1,830,750 $2.12

(b) Share purchase warrants: The following table summarizes the changes in the share purchase warrants for the three-year period ending December 31, 2002: 39

Number of Price Range Special Warrant (US$) =============== ===== Balance, December 31, 1999 1,404,000 $2.56 to $3.31 Expired (1,404,000) $2.56 to $3.31 ------------- Balance, December 31, 2000 -- =============

7. FINANCIAL INSTRUMENTS: In April 2002, the Company began hedging a portion of its production with a fixed price to index price swap agreement. The purpose of the hedges is to provide a measure of stability to the Company's cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. The Company 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. 133 is dependent upon whether or not a derivative instrument is designated as a hedge. For derivatives designated as cash flow hedges, 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 December 31, 2002 the Company had a current derivative liability of $653,875, which is included in other current assets in our balance sheet. During 2002, the Company received payments from counter-parties totaling $1,835,800 as its net proceeds from hedging activities. This total includes $312,000 for the second quarter of 2002, $1,130,100 for the third quarter of 2002, and the $393,700 for the fourth quarter of 2002. At year-end 2002, the Company had hedges in place covering approximately 15,000 MMBtu or approximately 13 MMcf of gas per day for calendar 2003 at an average price of $3.11 per MMBtu or approximately $3.35 per Mcf. Of these hedges, 10,000 MMBtu are in the form of swaps and 5,000 MMBtu are fixed price forward sales at Opal, Wyoming. The swaps are priced relative to the index price at the first of each month at Opal, Wyoming, where the Company delivers most of its gas to the purchasers. 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 price of $3.75 per MMBtu or approximately $3.95 per Mcf (pricing referenced to Opal), plus an additional 5,000 MMBtu or approximately 4 MMcf of gas per day for the same period at a price of $4.25 per MMBtu or approximately $4.48 per Mcf (pricing referenced to Opal). The table below summarizes the hedges in place as of March 3, 2003:

TYPE PERIOD VOLUME PRICE / MMBTU ---- ------ ------ ------------- 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 50% of the Company's forecasted production for the period from April 1, 2003 to October 31, 2003, and approximately 35% of the Company's forecasted production for calendar 2003. 8. INCOME TAXES: The (recovery of) provision for income taxes for the years ended December 31, 2002 and 2001 vary from the amounts that would be computed by applying the U.S. Federal income tax rate of 35% to pretax income as a result of the following: 40

December 31, 2002 December 31, 2001 ----------------- ----------------- Federal tax expense at statutory rate $ 4,599,240 $ 6,987,957 State income tax expense 456,497 468,024 Adjustment for foreign losses 94,087 146,036 Adjustment to estimated acquired net operating losses and partnership income -- 169,417 Percentage depletion (185,016) (523,929) Other 94,358 34,870 Decrease in valuation allowance -- (5,195,612) ----------- ----------- Actual income tax expense $ 5,059,166 $ 2,086,763 ----------- -----------

The tax effects of temporary differences that give rise to significant portions of the future tax assets and liabilities are as follows:

December 31, 2002 December 31, 2001 ----------------- ----------------- Future tax assets: Net operating loss carry-forward $ 9,878,862 $ 9,998,935 Other 797,440 560,111 ------------ ------------ 10,676,302 10,559,045 Less valuation allowance -- -- ------------ ------------ Total future assets 10,676,302 10,559,046 ------------ ------------ Future tax liabilities Property and equipment (20,709,476) (15,533,055) ------------ ------------ Net future tax assets (liabilities) $(10,033,174) $ (4,974,009) ------------ ------------

At December 31, 2002, the Company has available non-capital loss carry-forwards as follows:

Losses for Financial Timing Losses for Statements Differences Tax Purposes Expiry Dates ---------- ----------- ------------ ------------ Canada (Cdn dollars) $9,506,844 $ 421,910 $ 9,928,754 2002-2008 United States (US dollars) $ -- $25,827,299 $25,827,299 2008-2021

During 2001, the Company fully utilized available net operating loss carry-forwards attributable to continuing operations for financial statement purposes. The benefit of the Canadian loss carry-forwards could only be utilized if the Company were to generate taxable income in Canada. The Company currently has no operations in Canada; any potential benefit from these losses has been excluded from the calculation of deferred taxes. 9. EMPLOYEE BENEFITS: The Company sponsors a qualified tax-deferred savings plan in accordance with provisions of Section 401(k) of the Internal Revenue Code for its U.S. employees. Employees may defer up to 15% of their compensation, subject to certain limitations. The Company matches the employee contributions up to 5% of employee compensation along with a profit sharing contribution of 8% which began in February 2000. The plan operates on a calendar year basis and began in February 1998. The expense associated with the Company's contribution was $236,765, $187,255 and $130,341 for the years ended 2002, 2001 and 2000, respectively. 10. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES: Currently under Canadian GAAP, there is not a provision in place 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 standards to U.S. GAAP. The proposed effective date for implementing Stock-Based Compensation and Other Stock-Based Payments, Section 3870, is January 1, 2004. In the year ending December 31, 2002, the Company recorded to the full cost pool under capitalized general and administrative expenses a consultant stock-based compensation expense of $112,103. Under current Canadian GAAP, this amount would have been recognized as a disclosure item, with no impact on the financial statements. 41 Recorded in other comprehensive income in the Equity section of our balance sheet is an offset to a liability that measures a future effect of the fixed price to index price swap agreements that the Company currently has in place (Note 7). We have recorded this in compliance with FAS 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 total future value of the swap is not captured as an asset or liability, and the term Other Comprehensive Income, is not recognized in Canada. In 2002, the Canadian Accounting Standards Board issued a draft proposal to put in place Canadian standards harmonizing with U.S. standards on financial instruments. Canadian enterprises would then have the choice to apply accounting policies and practices that are in accordance with both U.S. and Canadian GAAP. 11. COMMITMENTS AND CONTINGENCIES: The Company is committed to payment under an operating lease for office space in Denver of $192,000 in 2003; however, this amount may change because the current office lease expires June 2003 and the Company will be negotiating a new lease. Approximately 50% of this payment is offset by a sublease with the same term as the primary lease. In December 2002, the Company signed a sublease for office space in Houston, which it has committed to through April 2007. The Company's total liability of this sublease is $429,065. The Company is currently involved in various other routine disputes and allegations incidental to its business operations. While it is not possible to determine the ultimate disposition of these matters, management, after consultation with legal counsel, is of the opinion that the final resolution of all such currently pending or threatened litigation is not likely to have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Company. 12. FAIR VALUE OF FINANCIAL INSTRUMENTS: For certain of the Company's financial instruments including accounts receivable, notes receivable, accounts payable and accrued liabilities, the carrying amounts approximate fair value due to the immediate or short-term maturity of these financial instruments. The carrying value for notes payable approximates fair market value because the interest rates are similar to the current rates presently available to the Company for loans with similar terms and maturity. It is not practicable to estimate the fair values of amounts due to and from related parties due to the related party nature of the amounts and the absence of a ready market for such instruments. 13. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):

Revenues from Net Income Basic Diluted Continuing Before Income Income Tax Net Earnings Earnings Per Operations Expenses Tax Provision Provision Income Per Share Share ---------- -------- ------------- --------- ------ --------- ----- (in thousands, except for per share data) 2002 First Quarter $ 9,106 $ 6,323 $ 2,783 $ 1,071 $ 1,712 $ 0.02 $ 0.02 Second Quarter $ 8,143 $ 6,161 $ 1,982 $ 676 $ 1,306 $ 0.02 $ 0.02 Third Quarter $ 8,671 $ 7,108 $ 1,563 $ 602 $ 961 $ 0.01 $ 0.01 Fourth Quarter $16,422 $ 9,610 $ 6,812 $ 2,710 $ 4,102 $ 0.06 $ 0.05 ------- ------- ------- ------- ------- $42,342 $29,202 $13,140 $ 5,059 $ 8,081 ======= ======= ======= ======= ======= 2001 First Quarter $16,747 $ 5,717 $11,031 $ 1,146 $ 9,885 $ 0.14 $ 0.13 Second Quarter $10,048 $ 5,274 $ 4,774 $ 500 $ 4,274 $ 0.06 $ 0.05 Third Quarter $ 6,937 $ 5,091 $ 1,846 $ 199 $ 1,647 $ 0.02 $ 0.02 Fourth Quarter $ 7,469 $ 5,155 $ 2,315 $ 242 $ 2,073 $ 0.03 $ 0.03 ------- ------- ------- ------- ------- $41,201 $21,237 $19,966 $ 2,087 $17,879 ======= ======= ======= ======= =======

42 14. DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED): The following information about the Company's oil and gas producing activities is presented in accordance with Financial Accounting Standards Board Statement No. 69, Disclosure About Oil and Gas Producing Activities: A. OIL AND GAS RESERVES: The determination of oil and gas reserves is complex and highly interpretive. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs. The following unaudited tables as of December 31, 2002, 2001 and 2000 are based upon estimates prepared by Netherland, Sewell & Associates, Inc. dated January 21, 2003, February 21, 2002 and February 12, 2001, respectively. These are estimated quantities of proved oil and gas reserves for the Company and the changes in total proved reserves as of December 31, 2002, 2001 and 2000. All such reserves are located in the Green River Basin, Wyoming. B. ANALYSES OF CHANGES IN PROVEN RESERVES:

OIL (BBLS) GAS (MCF) ---------- --------- Reserves, January 1, 2000 575,000 71,231,000 ---------- ------------ Extensions, discoveries and additions 741,800 91,369,000 Production (50,400) (5,297,400) Revisions 23,900 3,087,400 Acquisition of reserves in place -- -- Sale of reserves in place -- -- ---------- ------------ Reserves, January 1, 2001 1,290,300 160,390,000 ---------- ------------ Extensions, discoveries and additions 2,222,900 278,057,000 Production (116,400) (11,500,000) Revisions 86,000 (3,117,400) Acquisition of reserves in place -- -- Sale of reserves in place -- -- ---------- ------------ Reserves, January 1, 2002 3,482,800 423,829,600 ---------- ------------ Extensions, discoveries and additions 1,101,500 139,044,000 Production (151,200) (16,496,000) Revisions 1,125,900 120,743,400 Acquisition of reserves in place -- -- Sale of reserves in place -- -- ---------- ------------ Reserves, January 1, 2003 5,559,000 667,121,000 ========== ============ Proved developed reserves: January 1, 2000 297,000 36,480,000 ========== ============ January 1, 2001 688,000 85,141,000 ========== ============ January 1, 2002 1,295,000 150,397,000 ========== ============ January 1, 2003 2,003,000 222,608,000 ========== ============

C. STANDARDIZED MEASURE: The standardized measure of discounted future net cash flows related to proven oil and gas reserves are as follows (US$000): 43

December 31, December 31, December 31, 2002 2001 2000 ---- ---- ---- Future cash inflows $ 2,132,521 $ 939,441 $ 1,301,456 Future production costs (569,034) (257,960) (205,935) Future development costs (254,892) (149,806) (43,395) Future income taxes (432,663) (184,164) (390,868) ----------- --------- ----------- Future net cash flows 875,932 347,511 661,258 Discounted at 10% (558,967) (228,253) (351,257) ----------- --------- ----------- Standardized measure of discounted future net cash flows $ 316,965 $ 119,259 $ 310,001 =========== ========= =========== Pre-tax standardized measure SEC PV-10 $ 473,528 $ 182,460 $ 493,243 =========== ========= ===========

The estimate of future income taxes is based on the future net cash flows from proved reserves adjusted for the tax basis of the oil and gas properties but without consideration of general and administrative and interest expenses. D. SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (US$000)

December 31, December 31, December 31, 2002 2001 2000 ---- ---- ---- Standardized measure, beginning $ 119,259 $ 310,001 $ 33,822 Net revisions 119,995 (1,820) (371) Extensions, discoveries and other changes 136,194 177,819 279,389 Sales of reserves in place -- -- -- Changes in future development costs (40,825) (31,066) (9,622) Sales of oil and gas, net of production costs (39,985) (39,762) (18,083) Net change in prices and production costs 91,501 (407,434) 160,675 Development costs incurred during the period that reduce future development costs 1,573 -- 1,385 Accretion of discount 18,246 49,324 4,127 Net change in income taxes (88,992) 62,196 (141,321) --------- --------- --------- Standardized measure, ending $ 316,965 $ 119,259 $ 310,001 ========= ========= =========

There are numerous uncertainties inherent in estimating quantities of proved reserves and projected future rates of production and timing of development expenditures, including many factors beyond the control of the Company. The reserve data and standardized measures set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and costs that may not prove correct over time. Predictions of future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Historically, oil and gas prices have fluctuated widely. 44 E. COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES (US$000): UNITED STATES

Years Ended December 31, December 31, December 31, 2002 2001 2000 ---- ---- ---- Acquisition costs - unproved properties $ 937 $ 310 $ -- Exploration 22,722 33,845 11,175 Development 28,620 11,950 18,115 -------- -------- -------- Total $ 52,279 $ 46,105 $ 29,290 ======== ======== ========

CHINA

Years Ended December 31, December 31, December 31, 2002 2001 2000 ---- ---- ---- Acquisition costs - unproved properties $ 8,979 $ 11,944 $ -- Exploration -- -- -- Development -- -- -- -------- -------- -------- Total $ 8,979 $ 11,944 $ -- ======== ======== ========

F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (US$000):

Years Ended December 31, December 31, December 31, 2002 2001 2000 ---- ---- ---- Oil and gas revenue $ 43,342 $ 41,201 $ 21,003 Production expenses and taxes (11,411) (9,023) (4,241) Depletion and depreciation (9,712) (6,687) (3,163) -------- -------- -------- Total $ 22,219 $ 25,491 $ 13,599 ======== ======== ========

ITEM 9. CHANGE IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES. None PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. The information required by this item will be included in the Company's definitive proxy statement, which will be filed not later than 120 days after December 31, 2002 and is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION. The information required by this item will be included in the Company's definitive proxy statement, which will be filed not later than 120 days after December 31, 2002 and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. The information required by Item 403 of Regulation S-K will be included in the Company's definitive proxy statement, which will be filed not later than 120 days after December 31, 2002, and is incorporated herein by reference. 45

NUMBER OF SECURITIES REMAINING AVAILABLE FOR FUTURE ISSUANCE UNDER NUMBER OF SECURITIES TO WEIGHTED-AVERAGE EQUITY COMPENSATION PLANS BE ISSUED UPON EXERCISE EXERCISE PRICE OF (EXCLUDING SECURITIES OF OUTSTANDING OPTIONS, OUTSTANDING OPTIONS, REFLECTED IN THE FIRST PLAN CATEGORY WARRANTS AND RIGHTS WARRANTS AND RIGHTS COLUMN) ------------- ------------------- ------------------- ------- Equity compensation plans approved by security holders at 12/31/2002 5,561,750 $2.79 5,651,500 Equity compensation plans not approved by security holders n/a n/a n/a --------- ----- --------- Total 5,561,750 $2.79 5,651,500

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. The information required by this item will be included in the Company's definitive proxy statement, which will be filed not later than 120 days after December 31, 2002 and is incorporated herein by reference. ITEM 14. CONTROLS AND PROCEDURES (a) Evaluation of Disclosure Controls and Procedures. Based on their evaluation as of a date within 90 days of the filing date of this Annual Report on Form 10-K, the Company's principal executive officer and principal financial officer have concluded that the Company'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")) are effective to ensure that information required to be disclosed by the Company 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. (b) Changes in Internal Controls. There were no significant changes in the Company's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) The following documents are filed as part of this report: 1. Financial Statements: See Index to Consolidated Financial Statements in Item 8. 2. Financial Statement Schedules: None 3. Exhibits. The following Exhibits are filed herewith pursuant to Rule 601 of the Regulation S-K or are incorporated by reference to previous filings. Exhibits designated with a "+" constitute a management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 14(c) of Form 10-K. Exhibit Number Description -------------- ----------- 3.1 Articles of Incorporation of Ultra Petroleum Corp. - (incorporated by reference to Exhibit 3.1 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001) 46 3.2 By-Laws of Ultra Petroleum Corp. - (incorporated by reference to Exhibit 3.2 of 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 of 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., Hibernia National Bank, Guaranty Bank, FSB and Compass Bank 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, Ultra Resources, Inc. and Banc One Capital Markets, 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) 10.3 First Amendment to Credit Agreement dated July 19, 2001 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 2001) 10.4 Credit Agreement dated March 22, 2000 (incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001) 10.5 Ratification of and Amendment to Mortgage dated February 15, 2001 (incorporated by reference to Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001) 10.6 Articles of Merger dated July 16, 2001 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 2001) 10.7 Plan of Merger and Reorganization dated July 16, 2001 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 2001) 21.1 Subsidiaries of the Company (incorporated by reference to Exhibit 21.1 to the Company's Annual Report on Form 10-K for the period ended December 31, 2001) 23.1 Consent of Netherland, Sewell & Associates, Inc. 99.1 Certification of Chief Executive Officer 99.2 Certification of Chief Financial Officer (b) Reports on Form 8-K None 47 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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: March 25, 2003 By: /s/ Michael D. Watford Name: Michael D. Watford Title: Chairman of the Board, Chief Executive Officer and President Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

SIGNATURE TITLE DATE /s/ Michael D. Watford Chairman of the Board, ---------------------- Chief Executive Officer and President March 25, 2003 Michael D. Watford /s/ W. Charles Helton ---------------------- W. Charles Helton Director March 25, 2003 /s/ James E. Nielson ---------------------- James E. Nielson Director March 25, 2003 /s/ Robert E. Rigney ---------------------- Robert E. Rigney Director March 25, 2003 /s/ James C. Roe ---------------------- James C. Roe Director March 25, 2003 /s/ F. Fox Benton III ---------------------- F. Fox Benton III Chief Financial Officer March 25, 2003

48 EXHIBIT INDEX Exhibit Number Description -------------- ----------- 3.1 Articles of Incorporation of Ultra Petroleum Corp. - (incorporated by reference to Exhibit 3.1 of 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 of 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 of 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., Hibernia National Bank, Guaranty Bank, FSB and Compass Bank 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, Ultra Resources, Inc. and Banc One Capital Markets, 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) 10.3 First Amendment to Credit Agreement dated July 19, 2001 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 2001) 10.4 Credit Agreement dated March 22, 2000 (incorporated by reference to Exhibit 10.1 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001) 10.5 Ratification of and Amendment to Mortgage dated February 15, 2001 (incorporated by reference to Exhibit 10.2 of the Company's Quarterly Report on Form 10-Q for the period ended June 30, 2001) 10.6 Articles of Merger dated July 16, 2001 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 2001) 10.7 Plan of Merger and Reorganization dated July 16, 2001 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the period ended September 30, 2001) 21.1 Subsidiaries of the Company (incorporated by reference to Exhibit 21.1 to the Company's Annual Report on Form 10-K for the period ended December 31, 2001) 23.1 Consent of Netherland, Sewell & Associates, Inc. 99.1 Certification of Chief Executive Officer 99.2 Certification of Chief Financial Officer