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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

Commission File Number: 0-29370

ULTRA PETROLEUM CORP.

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:

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. [ X ]

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $959,970,404 as of June 30, 2003 (based on the last reported sales price of $12.91 of such stock on the American Stock Exchange on such date).

Documents incorporated by reference: The definitive Proxy Statement for the 2004 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2003, is incorporated by reference in Part III of this Form 10-K.

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TABLE OF CONTENTS

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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.

     As of December 31, 2003 Ultra owns interests in approximately 175,345 gross (97,990 net) acres in Wyoming covering approximately 300 square miles. The Company owns working interest in approximately 156 gross productive wells in this area and is operator of 51% 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 2003, 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 2003, capital expenditures in Wyoming comprised approximately 85% of the Company’s total capital expenditures.

     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 2003, the Company reported no production or reserves attributable to its China property. The Company spent approximately 15% of its 2003 capital 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, six additional discoveries have been made on the Blocks, two of which were discoveries added in 2003.

     The Company owns interests in approximately 15,841 gross (11,384 net) acres and interest in three productive wells in Texas. The Company also owns interest in 14,741 gross (14,087 net) acres in Pennsylvania.

     The Company’s annual report on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to such reports and all other filings we make pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge to the public on the Company’s website at www.ultrapetroleum.com. To access the Company’s SEC filings, select Financials under the Investor Relations tab on the Company’s website. The Company’s SEC filings are available on its website as soon as they are posted to the EDGAR database on the SEC’s website.

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 2004 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 2004 on the Blocks and to continue development planning on the appraised discovery areas. The Company has discovered 9 oil fields on its two Bohai Bay Blocks. Of these 9 fields, 2 fields are under development with first production expected in the fourth quarter of 2004. Five of the fields are in various stages of development planning with tentative plans calling for all 5 fields to have an Overall Development Plan (ODP) submitted to the Chinese by year end 2004. If

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current development schedules are followed for these 5 fields, the Company should have a total of 7 fields on production by the end of 2006. Two of the 9 fields are still under appraisal.

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 the first half of 2003, the Company experienced significant pricing differentials in southwestern Wyoming relative to the Henry Hub (Louisiana) pricing reference point primarily due to production in the region exceeding interstate pipeline capacity to deliver gas to the consuming west and east. Without sufficient pipeline capacity to move the gas to markets, gas prices were ‘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.

     In May of 2003, Kern River Pipeline which serves markets in California, Nevada and Utah expanded its system by over 900 MMcf/d or 100% to 1.73 Bcf/d. Additionally, Northwest Pipeline, which serves the Pacific Northwest, expanded its system by 175 MMcf/d in late 2003. These expansions moderated the price differentials between southwestern Wyoming and the Henry Hub (Louisiana) pricing reference point. However, there can be no assurance that the expansions will eliminate large differentials in the future or that future expansions will be made to accommodate the projected growth in production from the region.

     The Company expects to begin production from the first two fields (“CFD 11-1/11-2”) on Block 04/36 Bohai Bay, China in the fourth quarter of 2004. At that time, the price of crude oil, in particular oil prices in East Asia, will become important to the Company’s revenues. As of February 27, 2004, the Company was still negotiating a Memorandum of Understanding (“MOU”) relating to the valuation of marketing of crude oil from the CFD 11-1/11-2 fields. It is anticipated that the oil from the CFD 11-1/11-2 fields will be priced based on (Indonesian) Duri crude postings with adjustments for quality and location. The quality of crude blend from CFD 11-1/11-2 is currently not known with any degree of certainty because of variations in crude quality from the multiple productive reservoirs. The Company believes it will be successful in reaching agreement on the MOU. The Company will review opportunities to utilize forward sales and financial derivations, if any, to reduce the volatility of the prices it will receive for its CFD 11-1/11-2 crude oil.

     The Company uses forward sales and financial derivations to reduce the volatility of the prices it receives for the sale of its natural gas production. 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 major integrated oil and gas 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

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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. 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.

     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.

     As of year end, the Company had approximately 85 permits to drill wells on Company operated federal leases in the Pinedale Anticline 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. The Company’s future costs of complying with these regulations may continue to be substantial. 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 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. Other operators in the Jonah Field have obtained approval for down-spacing portions of the Jonah Field to 20-acre and 10-acre spacing to test the feasibility of developing the field at tighter spacing than the currently approved 40-acre spacing. The BLM is currently conducting a new EIS covering the Jonah Field in anticipation of down-spacing the entire field at some point in the near future. The Company cannot predict when this EIS will be finalized.

     During 2003 Ultra and other operators on the Pinedale Anticline received approval from the Wyoming Oil & Gas Conservation Commission to drill increased density pilots in several areas of the Pinedale Anticline Field to test the feasibility of developing the field at higher well density than the currently allowed 16 wells per section (40-acre spacing).

     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.

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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 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 and royalty and related valuation requirements. In addition, 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

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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 and 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 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 the 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 the RCRA or other 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.

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     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.

     Endangered Species Act. The Endangered Species Act (“ESA”) was established to provide a means to conserve the ecosystems upon which endangered and threatened species depend, to provide a program for conservation of these endangered and threatened species, and to take the appropriate steps that are necessary to bring any endangered or threatened species to the point where measures provided for in the Act are no longer necessary. The Company conducts operations on federal oil and gas leases that have species, such as sage grouse or other sensitive species, that potentially could be listed as threatened or endangered under the ESA. If a species is listed as threatened or endangered, the U.S. Fish and Wildlife Service must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and gas development. If the Company were to have a portion of its leases designated as critical or suitable habitat, it may adversely impact the value of the affected leases.

     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.

Employees

     As of February 27, 2004, the Company had 31 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. There are approximately 65,528 gross (36,494 net) acres currently held by 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, 2003, the Company owned developed oil and gas leases totaling 7,290 gross (3,157 net) acres in the Green River Basin of Sublette County, Wyoming which represents 91% of the Company’s total domestic developed gross acreage. The Company owned undeveloped oil and gas leases totaling 168,055 gross (94,833 net) acres in the Green River Basin of Sublette County, Wyoming which represents 85% 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 $130,000 for the fiscal year ended December 31, 2003. The primary target on the Company’s Wyoming acreage is the tight gas sands of the upper Cretaceous Lance formation.

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     Exploratory Wells. During the year-ended December 31, 2003, the Company participated in the drilling of a total of 25 gross (10.18 net) exploratory wells on the Green River Basin properties. Of these, only 1 gross (.32 net) was a dry hole. This one well had to be junked and abandoned due to mechanical problems. At year end there were 9 gross (4.66 net) additional exploratory wells that were either still drilling or had drilling operations suspended for winter.

     Development Wells. The Company participated in the drilling of 24 gross (6.88 net) successful development wells in the Pinedale Field area. At year end there were 5 gross (1.95 net) additional development wells that were either still drilling or had drilling operations suspended for winter. 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 2003 resulted in an extension of the third exploration term to September 2005. As the contract now stands, the exploration period will end at the end of September 2005. Barring an extension, at that time all acreage not under appraisal, development or production must be relinquished. 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. Negotiations with the Chinese government in 2003 resulted in an extension of the third exploration term to the end of February 2005. The third (and final) exploration term will now continue through the end of February 2005 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.

     Exploration / Appraisal Activity. In 2003, utilizing 3-D seismic data, the Company participated in drilling 4.0 gross (0.66 net) exploratory wells and 6.0 gross (1.03 net) appraisal wells on the Blocks. The exploratory drilling resulted in 2 new discoveries on the Blocks. Four appraisal wells were successful. The primary target formations on the Blocks are the Tertiary Minghuazhen, Guantuao and Dongying formations.

     Development Activity. An ODP for two of the fields on Block 04/36 (CFD 11-1/11-2) was approved by CNOOC in September 2002 and CNOOC has elected to participate for its 51% working interest in the development of these fields. The Chinese government gave its approval in June 2003. A MOU for marketing and valuation of the CFD 11-1/11-2 crude oil, a Lifting Agreement for the CFD 11-1/11-2 oil fields and a Field Terminal Information and Regulation Agreement are expected to be signed in March 2004 thus clearing the way for full commerciality of the two fields. Construction started on the offshore production platforms and a Floating Production Storage and Offloading (“FPSO”) vessel, which will be leased from CNOOC under an operating lease for these fields. The platform jackets were installed offshore in June 2003 and development well drilling started in the fourth quarter 2003. The FPSO contract calls for the vessel to be on location ready to receive oil in the third quarter of 2004 with oil production starting soon thereafter.

     On October 16, 2003 a 15 year contract which provides for extensions for up to an additional 10 years was signed by the Operator to lease an FPSO. The Company ratified the contract for its net share which is 8.92%. The FPSO contract specifies a 110,000-150,000 dead weight tons (“DWT”) double-hull FPSO with a 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 (14,087 net) acres in Pennsylvania, which represents 7% of the Company’s total domestic undeveloped gross acreage.

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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 9% of the Company’s total developed gross acreage. In 2003, the Company leased 15,121 gross (11,002 net) acres in Texas which represents 8% of the Company’s total domestic undeveloped gross acreage.

Oil and Gas Reserves

     The following table sets forth the Company’s quantities of proved reserves, for the years-ended December 31, 2003, 2002 and 2001 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, 2003, 2002 and 2001. In accordance with Ultra’s three-year planning and budgeting cycle, proved undeveloped reserves included in this table include only economic locations that are forecast to be on production before January 1, 2007. Proved undeveloped reserves represent 64.9% of total proved reserves.

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.

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Productive Wells

     As of December 31, 2003, the Company’s total gross and net wells were as follows:

Oil and Gas Acreage

     As of December 31, 2003, the Company had total gross and net developed and undeveloped oil and gas leasehold acres in the United States 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:

     As of December 31, 2003, the Company had total gross and net developed and undeveloped oil and gas leasehold acres in the Bohai Bay China as set forth below.

Bohai Bay Acreage:

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Drilling Activities

     For each of the three fiscal years ended December 31, 2003, 2002 and 2001, the number of gross and net wells drilled by the Company was as follows:

Wyoming – Green River Basin

     At year end there were 5 gross (1.95 net) additional development wells that were either drilling or had drilling operations suspended over the winter.

     At year end there were 9 gross (4.66 net) additional exploratory wells that were either drilling or had drilling operations suspended over the winter.

Texas

China – Bohai Bay

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, 2003.

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PART II

Item 5. Market for Registrant’s Common Stock and Related Stockholder Matters.

     The common shares of the Company have been 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 and TSE for 2003, 2002 and 2001 as reported by each exchange, respectively.

     On February 27, 2004, the last reported sale price of the common stock on the AMEX was $29.16 per share. As of February 27, 2004 there were approximately 457 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 current credit facility prohibits 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, 2003, 2002, 2001, 2000, the six months ended December 31, 1999 and the year ended June 30, 1999 is derived from the Consolidated Financial Statements of the Company. Effective with the period ended December 31, 1999, the Company began utilizing a December 31 year-end.

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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, 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.

     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

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performance data. These estimates are currently made annually by independent petroleum engineers and reviewed by the Company’s engineers. The reserves are periodically reviewed and revised, either upward or downward, if 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 the production of such resources becoming uneconomic.

     Due to the volatility of commodity prices, the oil and gas prices on the last day of the period 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 a common unit 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 2003, 2002 or 2001. As of December 31, 2003, the ceiling limitation exceeded the carrying value of the Company’s oil and gas properties by approximately $900 million in the U.S. The Company’s China properties have not yet been subject to a ceiling test, as there have not been any proved reserves identified to date. Estimates of discounted future net cash flows at December 31, 2003 were based on average natural gas prices of approximately $5.59 per MCF in the U.S. and on average liquids prices of approximately $31.01 per barrel in the U.S. A reduction in oil

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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 confirmed, 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 as the Company expects, amounts are reclassified as proved properties and become subject to depreciation, depletion and amortization and the application of the ceiling test. If exploration and appraisal 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, 2003, costs related to these international projects of approximately $81.0 million were not being depleted pending confirmation 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 the Company’s 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 would be 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 would be adjusted to reflect any over-produced or under-produced positions. Receivables or payables would be 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, 2003, the Company had taken approximately 264 MMcf more than its entitled share of production. The estimated value of this imbalance of approximately $1.3 million was recorded as a long-term liability under the Notes Payable category on the Balance Sheet.

     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, 2003, the Company will need to generate future taxable income prior to the expiration of the net operating loss carryforwards in 2004 to 2023. 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 deductible differences, net of the existing valuation allowances at December 31, 2003. 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 carryforward periods are reduced.

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     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.

     Legal, Environmental and Other Contingencies. A provision for legal, environmental and other contingencies is charged to expense when the loss is probably and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amounts for accrual is a complex estimation process that includes the subjective judgment of management. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. The Company’s management closely monitors known and potential legal, environmental and other contingencies and periodically determines when the Company should record losses for these items based on information available to the Company.

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. We operate in one segment, natural gas and oil exploration and development with two geographical segments, the United States and China.

     The Company currently generates its revenue, earnings and cash from the production and sales of natural gas and oil from its property in southwestern Wyoming. The price of natural gas in the southwest Wyoming region is a critical factor to the Company’s business. The price of gas in southwest Wyoming historically has been volatile. The average annual realizations for the period 2001-2003 have ranged from $2.33 to $4.16 per Mcf. This volatility could be very detrimental to the Company’s financial performance. The Company seeks to limit the impact of this volatility on its results by entering into derivative and forward sales contracts for gas in southwest Wyoming (see Item 7A). The Company also has oil properties offshore Bohai Bay, China which are expected to begin production in late 2004. At that time, the price of oil in east Asia would become critical to the Company.

     The Company has grown its natural gas and oil production significantly over the past three years and management believes it has the ability to continue growing production by drilling already identified locations on its leases in Wyoming and by bringing into production the already discovered oilfields in China. The Company has experienced significant production growth over the last three years and expects this growth to continue in 2004:

The anticipated 2004 production growth of 40 Bcfe is expected to be achieved by drilling wells in Wyoming. The Company also expects to maintain its cost structure in Wyoming on a unit of production basis during 2004 as follows:

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