10-K 1 d10k.txt FORM 10-K 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, 2001. [ ] 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 (I.R.S. Employer or organization) Identification No.) 16801 GREENSPOINT PARK DRIVE, SUITE 370 Houston, Texas 77060 (Address of principal executive offices) (Zip Code) 281-876-0120 (Registrant's telephone number, including area code) SECURITIES REGISTERED OR TO BE REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE SECURITIES REGISTERED OR TO BE 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 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. [ ] As of March 1, 2002, the Registrant had 73,383,418 common shares outstanding, and the aggregate market value of the common shares held by non-affiliates was approximately $496,805,739.90 based upon the closing price of $6.77 per share for the common stock on March 1, 2002, as reported on the American Stock Exchange. Documents incorporated by reference: The definitive Proxy Statement for the 2002 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2001, is incorporated by reference in Part III of this Form 10-K. 1 TABLE OF CONTENTS

Page ---- PART I Item 1. Business........................................................................ 3 Item 2. Property........................................................................ 13 Item 3. Legal Proceedings............................................................... 17 Item 4. Submission of matters to a vote of security holders............................. 17 PART II Item 5. Market for registrant's common equity and related stockholder matters............ 17 Item 6. Selected Financial Data.......................................................... 18 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................................................................. 19 Item 7A Quantitative and Qualitative Disclosures About Market Risk....................... 33 Item 8. Financial Statements and Supplementary Data...................................... 33 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosures................................................................. 33 PART III Item 10. Directors and Executive Officers of Registrant................................... 33 Item 11. Executive Compensation........................................................... 34 Item 12. Security Ownership of Certain Beneficial Owners and Management.................. 34 Item 13. Certain Relationships and Related Transactions................................... 34 PART IV Item 14. Exhibits, Consolidated Financial Statement Schedules and Reports on Form 8-K.................................................................... 34 Signatures....................................................................... 36

2 PART I ITEM 1. DESCRIPTION OF BUSINESS. Ultra Petroleum Corp. ("Ultra" or 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. Ultra is an independent oil and gas company engaged in the development, production, operation, exploration and acquisition of oil and gas properties. The Company's operations are focused primarily in the Green River Basin of southwest Wyoming and Bohai Bay, offshore China. On January 16, 2001, the Company completed the acquisition through a Plan of Arrangement of all of the outstanding shares of Pendaries Petroleum Ltd., a Houston based independent oil and gas exploration company with its primary focus in the Bohai Bay, China. In exchange, the Company issued 14,994,958 shares of its common stock. The transaction was valued at approximately $40 million based on share price of Ultra and is recorded using the purchase method of accounting. In July 2001 Ultra implemented a restructuring of the Company's subsidiaries; Ultra Resources, Inc., Ultra Petroleum (USA) Inc., Pendaries Petroleum Ltd. and Sino-American Energy Corporation. This restructuring allowed the Company to maximize the tax benefits from the net operating losses (NOL) in the various entities and simplify the overall corporate structure and administration of the Company. To accomplish this goal, the Company formed on July 11, 2001 UP Energy Corporation, a Nevada corporation, so as to transfer all of the stock of Ultra Resources, Inc. and Sino-American Energy Corporation in exchange for UP Energy Corporation stock. On July 13, 2001 Pendaries Petroleum Ltd was dissolved in New Brunswick, Canada, its place of incorporation. Ultra Petroleum (USA) Inc. was merged into Ultra Resources, Inc. on July 16, 2001. Thus after the restructuring, UP Energy Corporation is the wholly-owned subsidiary of Ultra Petroleum Corp., the parent, and Ultra Resources, Inc. and Sino-American Energy Corporation are wholly owned subsidiaries of UP Energy Corporation and now form a consolidated group for federal income taxes. GREEN RIVER BASIN - WYOMING Ultra holds interests in approximately 265,395 gross (163,547 net) acres in Wyoming covering approximately 410 square miles. 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. The Green River Basin drilling program targets the upper Cretaceous Lance and Mesaverde sands. These together, form a thick sequence of tight, over- pressured, gas charged sands which were deposited some 65 million years ago in the developing basin which is bounded on the east by the Wind River Mountains and to the west by the Western Overthrust and LaBarge Platform. The thickest accumulations of these potential play sands underlie the Pinedale Anticline which trends northwest to southeast just west of the Wind River Mountains. The Lance and Mesaverde reservoirs are characterized as, Basin Center Tight Gas Sand reservoirs. As such there are several characteristics of these reservoirs that set them apart from normal hydrocarbon accumulations. These types of reservoirs are generally formed in the deep portions of sedimentary basins. The sands have porosity and permeability levels lower than normally associated with productive zones. Pressures within the reservoir are abnormal, in the case of this accumulation they are greater than normal due to the gas migrating into the reservoir rock from a rich hydrocarbon source bed at rates exceeding those at which the gas can escape. 3 The Lance and Mesaverde consist of a thick sequence of inter-bedded sand and shale which were deposited over the broad depositional basin by a major braided river system which drained across this area from the highlands in the Idaho area to the Cretaceous Seaway which was located in south central Wyoming at the time. Due to the nature of the depositional environment there exists an abundance of stacked sand bodies all of which are relatively small in size and extent but when taken together form a major accumulation of interconnected reservoir bodies that contribute to the high production potential from these zones. The Lance can be over 5000 feet thick with 1000 feet or more being potential reservoir. The underlying Mesaverde section can be up to an additional 1000 feet thick with 300 or more feet of pay sand. The Mesaverde sections differs from the overlying Lance in that, during deposition the area was more stable and closer to the coast thus the sands are somewhat better developed, coal beds are present in parts of the area and the reservoir pressures are somewhat higher than the Lance. Exploratory Wells. During the year-ended December 31, 2001, the Company drilled or caused to be drilled a total of 23 gross exploratory (9.09 net) wells. Of these, 22 gross (8.67 net) wells were considered productive and the one non-productive location was abandoned by the operator due to mechanical reasons. From January 1, 2002 through March 1, 2002, the Company drilled one gross (.425 net) well which is undergoing completion at this time and which appears to be productive. During the second half of 2001, the Company drilled four field extension wells on the flanks of the then identified productive fairway of the Pinedale Anticline based on 3-D seismic. All four (3.23 net) wells were commercially productive. Initial production rates for these wells ranged from 8.8 Mmcf to 12.5 Mmcf per day. Because of the rapid decline normally experienced in the first six months of a well's production life, the Company typically only places two production units on a well site, which can constrain initial production to 12-12.5 Mmcf per day. The success of these wells confirmed the Company's geologic interpretation in these areas of the Anticline and proved that the currently defined fairway can be expanded. Additionally during the second half of 2001, the Company participated in the drilling of 2 (0.74 net) wells that penetrated the Mesaverde, a productive horizon underlying the Lance formation, the primary productive interval in the Company's producing wells. These wells have been successfully completed in the Mesaverde and are currently producing from that horizon. One of these wells was drilled in northern and the other was drilled in the southern portion of the Pinedale Anticline. During the first quarter of 2002 another one gross (0.43 net) well in the southern portion of the Pinedale Anticline was drilled into the Mesaverde formation and appears to be productive in that horizon. However, the Company does not anticipate that the Mesaverde will be productive across the entire Pinedale Anticline. Development Wells. In addition to the 23 gross (9.10 net) exploratory wells, the Company drilled 8 gross (5.1 net) successful development wells in the Jonah Field area as well as one gross (.425 net) development well in the Warbonnet area of the Pinedale Anticline which was successful. During 2001, the Company acquired a new 100 square mile 3-D seismic survey on the west flank of the Pinedale Anticline. The Company has received the first of several data sets to be received from this survey. The Company expects to receive the remaining data sets by the end of the first quarter of 2002. The Company anticipates that the data sets will provide a clear picture of the structural and stratigraphic attributes of the acreage just to the west of the Anticline where it is thought that additional productive structures may be located. This survey, which overlaps the existing 3-D surveys owned by the Company, provides the Company with 330 total square miles of modern (1999-2001), high quality 3-D seismic data over most of the Company's Pinedale Anticline area acreage. The Company believes that this data and the proprietary processing and interpretation techniques utilized by the Company provide the clearest view of the objective formations and structures in this area. The Company believes that these techniques 4 have greatly contributed to the high success rate for both development and exploratory drilling that the Company has achieved over the last two years. Ultra plans to drill and or participate in up to 25 gross (11.4 net) wells in 2002. The Company plans to drill the majority of these wells in and around the current activity areas on the Pinedale Anticline. Additionally, the Company expects to drill at least one wildcat well to test one or more areas identified by the 3-D seismic outside the current fairway. The drilling plans are a combination of development, step-out and exploratory locations selected with the objective of expanding the proved acreage of the Anticline and extended areas while maintaining a good balance of production, risk management, reserves bookings and economic prudence in the current operating market. The Company had estimated net proved reserves as of December 31, 2001 of 444,727 Mmcfe, 36% of which were proved developed, with a PV-10 of approximately $182,460,000. The Company's net daily gas sales at December 31, 2001 were approximately 41.6 Mmcf per day from a total of 72 producing wells. Total sales of hydrocarbons were approximately 43.3 Mmcfe per day. The Company plans to continue to identify, develop and explore the gas-rich acreage in the Green River Basin. At year-end 2001, the Company had 133 commercial Lance locations classified as proved undeveloped on the Pinedale Anticline and another 174 classified as probable under its SEC pricing case. There can be no assurance that the Company will drill these locations or that those drilled will prove to be commercially productive. 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 drilling to intercept deeper potentially productive horizons. The Company is utilizing its 3-D seismic to map these deeper potential productive intervals and to identify further extensions of the productive Lance fairway. BOHAI BAY - CHINA Bohai Bay History With the acquisition of Pendaries Petroleum Ltd. on January 16, 2001, the Company became active in oil and gas exploration and development in Bohai Bay, China. The acquisition brought to Ultra an 18.182% working interest in Block 04/36 (454,000 gross acres), a 15.0% working interest in Block 05/36 (311,000 gross acres) (jointly the "Blocks") and a 10.0% working interest in the (76,107 gross acres) Getuo block. A wholly-owned subsidiary of Kerr-McGee Corporation is the operator of all three blocks. At the time of the acquisition, three oil discoveries had been made on the Blocks. The CFD 2-1 and CFD 11-1 discoveries are located in the 04/36 block and the CFD 12-1 discovery is located in the 05/36 block. The discoveries were in various stages of appraisal and a 1,100 square kilometer 3-D seismic survey had recently been acquired covering the discoveries and a large number of high potential exploration targets on the two blocks. Petroleum Sharing Contracts Contracts covering offshore exploration blocks are Petroleum Sharing Contracts (PSCs) entered into by and between China National Offshore Oil Company ("CNOOC") and foreign oil and gas companies ("Contractor"). CNOOC has the exclusive rights to offshore hydrocarbon leases granted in law from the Chinese government and has the right to enter into PSCs with foreign oil and gas companies. These PSCs have a maximum term of 30 years and are divided into three periods: exploration, development and production. The Contractor pays 100% of the exploration costs required for exploration operations and has the right to act as operator until any 5 development has repaid all of the exploration and development costs. CNOOC has the right to acquire a 51% working interest in any commercial development and will pay their proportionate 51% share of all development costs. The Contractor receives up to a 71% share of the oil and gas produced until it has recovered the exploration costs. After recovery of exploration expenses, the Contractor's share of production is approximately 40-45%. Contractors have the right to take their share of production in kind and sell it on the international market. The Contract is divided into three (3) periods not to exceed 30 years in total. Extensions to any of the three periods of the contract can be negotiated with CNOOC. A brief description of the 3 periods of the contracts is presented below. The exploration period is a 7-year period consisting of an initial term of 3 years, followed by two terms of 2 years each. A relinquishment of 25% of the then contracted acreage is made at the beginning of the second and third terms. All acreage not under appraisal, development or production is relinquished at the end of the seven-year period. The development period for any oil or gas field discovered within the contract area during the exploration period begins upon approval of the Overall Development Plan (ODP) by the Chinese government. The contract does not impose a time limit on the development period of individual fields. The production period for any oil and gas field within the contract area is for 15 years following commencement of commercial production. The contract calls for negotiated extensions to the production period due to circumstances warranting longer field production. Status of Petroleum Sharing Contracts Block 04/36: The PSC covering this block became effective October 1, 1994. Negotiations with the Chinese government in 1997 resulted in the contractor not having to make the mandatory 25% acreage relinquishment at the beginning of the second exploration term. In September 1999 a 25% relinquishment was made to fulfill the required relinquishment schedule at the beginning of the third exploration term. Negotiations at this time resulted in the addition of 31,876 acres to the south side of the block to completely include certain prospects within the block boundary. These negotiations also included a one-year extension of the third exploration term to September 30, 2002. As the contract now stands, the exploration period will end at the end of September 2002. 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. Block 05/36: The PSC covering this block became effective March 1, 1996. At the end of the first exploration term in February 1999, a 25% relinquishment was made. At the same time, a one-year extension to the second exploration term was negotiated, extending the total exploration period to 8 years. The second exploration term ended in February 2002 with another 25% acreage relinquishment submitted. The third (and final) exploration term will continue until the end of February 2004 when, barring an extension, all acreage not under appraisal, development or production must be relinquished. 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. Drilling Activity In 2001, utilizing the newly received 3-D seismic data, the Company participated in drilling 4 (0.61 net) exploratory and 12 (2.02 net) appraisal wells on the Blocks. The exploratory drilling 6 resulted in 2 new discoveries on the Blocks and the appraisal drilling brought the CFD 11-1 and CFD 11-2 fields to commercial status and partially appraised the CFD 12-1 and CFD 12-1S field discoveries. One of the exploratory wells was a dry hole and resulted in the relinquishment of the Getuo Block. Individual block activity is listed below: Block 04/36 (18.2% W.I.): The Company participated in drilling a total of 9 (1.64 net) wells in the 04/36 block in 2001. This included 2 (0.36 net) exploratory wells in the block. One exploratory well discovered the CFD 11-2 field and the other was a dry hole at the CFD 10-1 prospect resulting in a 50% success rate. Ultra drilled 7 (1.27 net) successful appraisal wells on the block in 2001. Five of these appraisal wells were drilled on the CFD 11-1 field thus completing the appraisal process on that field. Two of the appraisal wells were drilled on the CFD 11-2 field (discovered in June 2001) to bring commercial status to that accumulation. Block 05/36 (15.0% W.I.): During 2001, Ultra drilled 6 (0.90 net) wells in the 05/36 block. This included one (0.15 net) exploratory well that was the new field discovery CFD 12-1S-1 that tested in excess of 6,000 BOPD from multiple zones. This resulted in the 05/36 block having a 100% success rate for exploratory drilling. A total of 5 (0.75 net) successful appraisal wells were drilled on the CFD 12-1 (4 wells, 0.60 net) and CFD 12-1S (1 well, 0.15 net) discovery areas. Getuo block (10.0% W.I.): At the time of the Pendaries acquisition, the Getuo block was burdened by a drilling commitment of one well to be drilled by June of 2001. Due to the lack of prospectivity, the partners attempted unsuccessfully to fulfill this commitment through a cash payment to the Chinese. The commitment well was drilled to the required depth and abandoned. With the commitment fulfilled, the Getuo block was relinquished as planned. Thus during 2001, Ultra participated in drilling one (0.10 net) well in the Getuo block. Ultra had placed negative value in the amount of the net commitment on the block in the acquisition of Pendaries. The Company expects to submit a finalized development plan for the CFD 11-1 and CFD 11-2 fields to the Chinese government by mid-year 2002 with first production scheduled in 2004. The Company plans to drill additional exploration wells in 2002 on the two blocks and to continue appraisal activity on the CFD 12-1, CFD 12-1S and CFD 2-1 discovery areas. PENNSYLVANIA During the past year Ultra entered into a joint venture in Pennsylvania covering 10,801 gross (5,401 net) acres of undeveloped leasehold acreage and is continuing to acquire additional acreage. Texas The Company operates one (0.66 net) well and owns working interests in two (0.22 net) other wells in Pecos and Winkler Counties, Texas. The Company believes these interests are not material to the Company. The Company does not generate any revenues in Canada. MARKETING AND PRICING The Company 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 sells the majority of its natural gas on the open market at prevailing market prices, or pursuant to market price contracts. The market price for natural gas is dictated by supply and demand, and the Company cannot 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 7 the Rocky Mountain region, where the Company produces most of its natural gas, historically sells for less than natural gas in the Midwest and Northeast. Accordingly, the Company's income and cash flows will be greatly 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. 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. 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 proximity of natural gas production to natural gas pipelines; . the availability of pipeline capacity; . the demand for oil and natural gas by utilities and other end users; . the availability of alternative fuel sources; . the effects of inclement weather; . 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 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 of the oil and natural gas it produces. 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 period, development period and production period. 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 required 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. 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 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 8 activity is proposed. This EIS encompasses approximately 200,000 gross acres under lease by the Company north of the Jonah Field 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. This has been an important step in giving the Company the ability to develop its natural gas resources in the region. 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-ways 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 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 BLM's field manager may also impose additional limitations and mitigation measures as is deemed reasonably necessary to mitigate the impacts of drilling and production operations in the area. To date, the Company has been required to expend 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 it is expected that the Company's costs of complying with these regulations will continue to be substantial. Compliance costs under the ROD/EIS and any revisions to the ROD/EIS could become material. In addition, any additional limitations and mitigation measures could increase production costs further, delay exploration, development and production activities and curtail exploration, development and production activities altogether. The Company co-owns leases on a significant area of 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 of 2000. With the approval of this subsequent EA, the Company was permitted to infill drill on 40-acre well density the 2,160 gross 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. Eight gross (5.1 net) of these were drilled during 2001. All 43 of the wells drilled by the Company in Jonah Field have been productive. During 2001, the Company received the "Corporation of the Year" Award from the Wyoming Wildlife Federation primarily for its support of the Pinedale area wildlife studies. Also during 2001, the Company received the "Regional Administrator's Award for Environmental Achievement" from the U.S. Environmental Protection Agency for its work in protecting the air quality in Wyoming's Class I wilderness area through the participation in installation of advanced 9 burner technology at the coal burning Naughton power plant which is upwind of the Pinedale area. The technology installed reduced nitrogen dioxide emissions by 1,000-2,000 tons per year. 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 an over-supply of gas or 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. 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, state or Indian 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 Bureau of Land Management ("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 10 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. Environmental Regulation General. The Company's activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. 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. Ultra'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 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. Waste Disposal. Ultra currently owns or leases, and has in the past owned or leased, numerous properties that have been used for 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 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. 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 become stricter. Under these 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 has limited the disposal options for certain wastes that are designated as hazardous under RCRA ("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, 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, 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 potentially responsible parties ("PRP") include the current and certain past owners and operators of a facility where there is or has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the 11 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. In the course of its operations, the Company may have generated and may generate wastes that fall within CERCLA's definition of Hazardous Substances. The Company may also be an owner of facilities on which Hazardous Substances have been released by previous owners or operators. Ultra 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. The Company has not been named a PRP under CERCLA nor does the Company know of any prior owners or operators of its properties that are 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 of air pollution. Local air quality districts do much of the air quality regulation of sources in California. California requires 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 permitting requirements, including additional permits. Because of the severity of the ozone (smog) problems in portions of California, the state has the most severe restrictions on the emissions of volatile organic compounds (VOC) and nitrogen oxides (Nox) of any state. Producing wells, gas plants and electric generating facilities, all of which are owned by us generate VOC and Nox. Some of the Company's producing wells are in counties that are designated as nonattainment for ozone and are therefore potentially subject to restrictive emission limitations and permitting requirements. If the ozone problems in the state are not resolved by the deadlines imposed by the federal Clean Air Act (2005 - 2010), even more restrictive requirements may be imposed including financial penalties based upon the quantity of ozone producing emissions. California also operates a stringent program to control hazardous (toxic) air pollutants, which 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 require the Company to forego construction, modification or operation of certain air emission sources, although the Company believes that in the latter cases the Company would have enough permitted or permittable capacity to continue its operations without a material adverse effect on any particular producing field. 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 us 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. 12 EMPLOYEES As of March 1, 2002, the Company had 20 full time employees, including officers. ITEM 2. DESCRIPTION OF PROPERTY. As of December 31, 2001, the Company owned developed oil and gas leases totaling 4,680 gross (2,169 net) acres of which 85% are located in the Green River Basin of Sublette County, Wyoming and the remaining 15% are located in Texas. The Company also owned production equipment associated with certain developed leases. The Company owned undeveloped oil and gas leases totaling 272,236 gross (167,160 net) acres of which 97% are located in the Green River Basin of Sublette County, Wyoming. Pennsylvania acreage totals 10,801 gross (5,401 net) which is 3% of the Company's total acreage. The Company's acreage in the Green River Basin is primarily covering the Pinedale Anticline and a large undeveloped block northwest of the Anticline. The Company also owns 2,160 gross (1,322 net) acres in the Jonah Field. Holding costs of leases not held by production were approximately $183,127 for the fiscal year ending December 31, 2001. OIL AND GAS RESERVES The table below sets forth the Company's quantities of proved reserves, for the year-ended December 31, 2001, 2000 and 1999 as estimated by independent petroleum engineers Netherland Sewell & Associates, Inc. All of the Company's oil and gas reserves are located in the United States. The table summarizes Ultra'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, 2001, 2000 and 1999.

December 31, ------------------------------------- 2001 2000 1999 ------- --------- ------ Proved Undeveloped Reserves Natural gas (MMcf)......................................... 273,433 75,249 34,751 Oil (MBbl)................................................. 2,187 602 278 Proved Developed reserves Natural gas (MMcf)......................................... 150,397 85,141 36,480 Oil (MBbl)................................................. 1,295 688 297 Total Proved Reserves (Mcfe)................................. 444,727 168,130 74,681 Estimated future net cash flows, before income tax........... 531,676 1,052,126 92,938 Standardized measure of discounted future net cash flows, before income tax............................. 182,460 493,243 41,275

Uncertainty of Estimates of Reserves and Future Revenues. The financial statements included in this report contain estimates of the Company's oil and gas reserves and the discounted future net revenues from those reserves, as prepared by independent petroleum engineers and/or the Company. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the control of the Company. Those estimates are based on several assumptions that the United States Securities and Exchange Commission (the "SEC") requires oil and gas companies to use, for example, constant oil and gas prices. Such estimates are inherently imprecise indications of future net revenues. Actual future production, revenues, taxes, operating expenses, development expenditures and quantities of recoverable oil and gas reserves might vary substantially from those assumed in the estimates. Any significant variance in these assumptions could materially affect the estimated quantity and value of reserves. In addition, the Company's reserves might be subject to revisions based upon future production, results of future exploration and development, prevailing oil and gas prices and other factors. Moreover, estimates of the economically 13 recoverable oil and gas reserves, classifications of such reserves, and estimates of future net cash flows, prepared by different engineers or by the same engineers at different times, may vary substantially. Information about reserves constitutes forward-looking information. Ability to Replace Reserves. The Company's future success depends upon its ability to find, develop and acquire oil and gas reserves that are economically recoverable. As a result, the Company must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. The Company must do this even during periods of low oil and gas prices when it is difficult to raise the capital necessary to finance these activities. Without successful exploration or acquisition activities, the Company's reserves, production and revenues will decline rapidly. No assurances can be made that the Company will be able to find and develop or acquire additional reserves at an acceptable cost. OIL AND GAS ACREAGE As of December 31, 2001, 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 3,960 1,787 261,435 161,760 Pennsylvania 0 0 10,801 5,401 Texas 720 382 0 0 ----- ----- ------- ------- All States 4,680 2,169 272,236 167,161 Bohai Bay Acreage: The table below sets out Ultra's Bohai acreage held as of March 1, 2002: 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

____________ * A 25% relinquishment was made on February 28, 2002 as a requirement for entering the third exploration period. 14 Drilling Activities For each of the three fiscal years ended December 31, 2001, 2000 and 1999, the number of gross and net wells drilled by the Company was as follows: Wyoming - Green River Basin

2001 2000 1999 ----- ----- ----- Gross Net Gross Net Gross Net ---------- --------- ----------- ------- --------- --------- Development Wells Productive........................ 9.00 5.52 14.00 8.92 0.00 0.00 Dry............................... 0.00 0.00 0.00 0.00 0.00 0.00 ----- ---- ----- ---- ---- ---- Total............................. 9.00 5.52 14.00 8.92 0.00 0.00 Exploratory Wells Productive...................... 22.00 8.67 10.00 3.16 2.00 0.92 Dry............................... 1.00* 0.42 1.00* 0.09 4.00 2.13 ----- ---- ----- ---- ---- ---- Total............................. 23.00 9.09 11.00 3.25 6.00 3.05

____________ * The exploratory dry holes drilled in 2000 and 2001 (2 gross wells) were both abandoned at TD due to mechanical failure during drilling operations. China - Bohai Bay Block 04/36 (18.2% W.I.)

2001 2000 1999 ---- ---- ---- Gross Net Gross Net Gross Net --------- --------- --------- --------- --------- --------- Exploratory Wells Productive and Successful Appraisal*........ 8.00 1.45 2.00 0.36 1.00 0.18 Dry Holes...................... 1.00 0.18 1.00 0.18 0.00 0.00 ---- ---- ---- ---- ---- ---- Total Wells........................ 9.00 1.63 3.00 0.54 1.00 0.18

____________ * 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. Block 05/36 (15.0% W.I.)

2001 2000 1999 ---- ---- ---- Gross Net Gross Net Gross Net --------- --------- --------- --------- --------- --------- Exploratory Wells Productive and Successful Appraisal*........ 6.00 0.90 2.00 0.30 0.00 0.00 Dry Holes...................... 0.00 0.00 0.00 0.00 0.00 0.00 ---- ---- ---- ---- ---- ---- Total Wells........................ 6.00 0.90 2.00 0.30 0.00 0.00

__________ * 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. 15

Getuo Block (10.0% W.I.) 2001 2000 1999 ---- ---- ---- Gross Net Gross Net Gross Net --------- --------- --------- --------- --------- --------- Exploratory Wells Productive and Successful Appraisal*........ 0.00 0.00 0.00 0.00 0.00 0.00 Dry Holes...................... 1.00 0.10 0.00 0.00 0.00 0.00 ---- ---- ---- ---- ---- ---- Total Wells........................ 1.00 0.10 0.00 0.00 0.00 0.00

____________ * 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. PRODUCTIVE WELLS As of December 31, 2001, the Company's total gross and net wells were as follows: Productive Wells* Gross Wells Net Wells ---------------- ----------- --------- Natural Gas and Condensate ......... 97 46.41 __________ *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. PRODUCTION VOLUMES, AVERAGE SALES PRICE 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, ----------------------------------------------- 2001 2000 1999 ----------- ----------- ---------- (unaudited) PRODUCTION Natural gas (Mcf) 11,500,446 5,297,421 4,525,570 Oil (Bbl) 116,413 50,386 45,702 ----------------------------------------------- Total (Mcfe)* 12,198,924 5,599,737 4,799,782 REVENUES Gas sales $38,204,298 $19,399,001 $8,229,984 Oil sales 2,996,955 1,603,635 746,722 ----------------------------------------------- Total Revenues 41,201,253 21,002,636 8,976,706 LEASE OPERATING EXPENSES Production costs** 1,439,026 665,999 554,257 Severance/production taxes 4,425,345 2,253,793 863,540 Gathering 3,158,901 1,321,228 1,297,169 ----------------------------------------------- Total Lease Operating Expenses 9,023,271 4,241,020 2,714,966 REALIZED PRICES Natural gas (Mcf) $ 3.32 $ 3.66 $ 1.82 Oil (Bbl) $ 25.74 $ 31.83 $ 16.34 OPERATING COSTS PER MCFE Production costs $ 0.12 $ 0.12 $ 0.12 Severance/production taxes $ 0.36 $ 0.40 $ 0.18 Gathering $ 0.26 $ 0.24 $ 0.27 ----------------------------------------------- Total Operating Costs per Mcfe $ 0.74 $ 0.76 $ 0.57

16 __________ *Equivalent barrels have been calculated on the basis of six thousand cubic feet (6 Mcf) of natural gas equals one barrel of oil. **Average production costs includes lifting costs, remedial workover expenses and production taxes. 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, 2001. 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 2001 and on the TSE from December 31, 1999 though December 31, 2001 as reported by such exchanges, respectively. TORONTO STOCK EXCHANGE (CDN$) 1999 High Low ---- ---- --- First Quarter $ 1.54 $1.06 Second Quarter $ 1.37 $0.96 Third Quarter $ 2.00 $1.07 Fourth Quarter $ 1.49 $0.93 2000 High Low ---- ---- --- First Quarter $ 1.10 $0.75 Second Quarter $ 2.80 $0.78 Third Quarter $ 3.90 $0.95 Fourth Quarter $ 4.70 $2.95 2001 High Low ---- ---- --- First Quarter $ 8.70 $3.76 Second Quarter $10.95 $7.01 Third Quarter $ 9.00 $5.65 Fourth Quarter $10.05 $6.30 17 AMERICAN STOCK EXCHANGE (US$) 2001 High Low ---- ---- --- First Quarter (beginning January 17, 2001) $ 5.50 $2.75 Second Quarter $ 7.34 $4.34 Third Quarter $ 5.92 $3.54 Fourth Quarter $ 6.41 $4.00 On March 26, 2002, the last reported sale price of the common stock on the AMEX was $7.65 per share. As of March 1, 2002 there were approximately 470 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. Under current Canadian tax law and the United States-Canada Tax Convention (1980) (the "Convention"), any dividends paid to U.S. resident shareholders under the Convention are generally subject to a 15% Canadian withholding tax. The Convention provides an exemption from withholding tax on dividends paid or credited to certain tax-exempt organizations that are resident in the United States for purposes of the Convention. Persons who are subject to the United States federal income tax on dividends may be entitled, subject to certain limitations, to either a credit or deduction with respect to Canadian income taxes withheld with respect to dividends paid or credited on the Company's shares. ITEM 6. SELECTED FINANCIAL DATA. The selected consolidated financial information presented below for the years ended December 31, 2001, 2000, the six months ended December 31, 1999 and the years ended June 30, 1999, 1998 and 1997 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 YEARS ENDED ENDED DECEMBER 31, DECEMBER 31, YEARS ENDED JUNE 30, --------------------- ----------------- ------------------------------ 2001 2000 1999 1999 1998 1997 ----- ------ ------- ------- -------- ------- Statement of Operations Data (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Natural gas sales $38,204 $19,399 $ 4,352 $ 6,352 $ 3,472 $ 405 Oil sales 2,997 1,604 434 670 174 21 Interest and other 393 171 18 287 121 14 --------------------------------------------------------------------------- Total revenues 41,594 21,174 4,804 7,309 3,767 440 =========================================================================== Expenses: Production expenses and taxes 9,023 4,241 1,329 2,571 953 78 Depreciation, depletion and amortization 6,687 3,163 1,186 1,794 1,377 77 General and administrative 4,231 3,078 1,668 5,861 3,406 1,381 Interest 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 21,628 11,284 6,368 16,239 14,339 1,536 Income from continuing operations before income taxes 19,966 9,890 (1,564) (8,930) (10,572) (1,096) Income tax provision - deferred 2,087 - - - - - --------------------------------------------------------------------------- Net income $17,879 $ 9,890 $(1,564) $(8,930) $(10,572) $(1,096) =========================================================================== Basic income per common share $ 0.25 $ 0.17 $ (0.03) $ (0.16) $ (0.26) $ (0.04) Diluted income per common share $ 0.24 $ 0.17 $ (0.03) $ (0.16) $ (0.26) $ (0.04)

18

SIX MONTHS YEARS ENDED ENDED DECEMBER 31, DECEMBER 31, YEARS ENDED JUNE 30, ------------------ ------------- ---------------------------- 2001 2000 1999 1999 1998 1997 ------ ----- ---- ---- ---- ---- (IN THOUSANDS) Statement of Cash Flows Data ---------------------------- Net cash provided by (used in): Operating activities $ 35,610 $ 9,046 $ 674 $ 1,913 $ (7,915) $(1,046) Investing activities (61,335) (24,541) (1,624) (1,017) (30,032) (8,899) Financing activities 25,961 16,236 569 (6,010) 39,094 14,559 AS OF DECEMBER 31, AS OF JUNE 30, ----------------------------------- ------------------- 2001 2000 1999 1998 1997 ------- ------ ---- ------- -------- (IN THOUSANDS) Balance Sheet Data ------------------ Cash and cash equivalents $ 1,379 $ 1,144 $ 402 $ 5,896 $ 4,690 Working capital (deficit) (9,227) 241 195 8,107 3,735 Oil and gas properties 155,221 59,729 33,773 37,392 16,304 Total assets 167,582 73,177 38,063 56,137 22,542 Total long term obligations 51,166 24,731 8,767 10,696 - Total stockholders' equity 95,320 35,694 25,632 35,372 21,237

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Statements that are not historical facts contained in this report are forward-looking statements that involve risks and uncertainties that could cause actual results to differ from projected results. Such statements address activities, events or developments that the Company expects, believes, projects, intends or anticipates will or may occur, including such matters as: future availability of capital; development and exploration expenditures (including the amount and nature thereof); drilling of wells; timing and amount of future production of oil and gas; business strategies; operating costs and other expenses; cash flow and anticipated liquidity; prospect development and property acquisitions; and marketing of oil and gas. Factors that could cause actual results to differ materially ("Cautionary Disclosures") are described below in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Certain Considerations." Cautionary Disclosures include, but are not limited to: general economic conditions; the market prices of oil and gas; the risks associated with exploration; the Company's ability to find, acquire, market, develop and produce new properties; operating hazards attendant to the oil and gas business; downhole drilling and completion risks that are generally not recoverable from third parties or insurance; the outcome of the Bureau of Land Management's EIS relating to the Company's core properties in the Green River Basin of southwest Wyoming; uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of exploration and development expenditures; potential mechanical failure or under performance of individually significant productive wells; the strength and financial resources of the Company's competitors; the Company's ability to find and retain skilled personnel; climatic conditions; labor relations; availability and cost of material and equipment; delays in anticipated start-up dates; environmental risks; the results of financing efforts; actions or inactions of third-party operators of the Company's properties; and regulatory developments. All statements attributable to the Company or persons acting on its behalf are expressly qualified in their entity by these Cautionary Disclosures. The Company disclaims any obligation to update or revise any forward-looking statement to reflect events or circumstances occurring hereafter or to reflect the occurrence of anticipated or unanticipated events. The following discussion of the financial condition and operating results of the Company should be read in conjunction with consolidated financial statements and related notes of the Company. Except as otherwise indicated all amounts are expressed in U.S. dollars. 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 19 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, 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 50.0 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 $.118 per Mcfe in 2001, as compared to $.119 per Mcfe in 2000. Production taxes in 2001 were $4.4 million, compared to $2.3 million in 2000, or $.363 per Mcfe in 2001, compared to $.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 from $1.3 million in 2000, attributable to higher production volumes. Depletion, depreciation and amortization (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 $4.2 million during the year ended December 31, 2001 from $3.1 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 certain 2001. Deferred income taxes for the period increased to $2.1 million in 2001 from $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. 20 RESULTS OF OPERATIONS - YEAR ENDED DECEMBER 31, 2000 COMPARED TO UNAUDITED YEAR ENDED DECEMBER 31, 1999 Oil and gas revenues increased 133% to $21.0 million for the year ended December 31, 2000 from $9.0 million for the same period in 1999. This increase was attributable to an increase in both the Company's production and the increase in prices received for that production. During this period the Company's production increased to 5.3 Bcf of gas, and 50.0 thousand barrels of condensate, up from 4.5 Bcf of gas and 45.7 thousand barrels of condensate for the same period in 1999. During the year ended December 31, 2000 the average product prices were $3.66 per Mcf and $31.83 per barrel, compared to $1.82 per Mcf and $16.34 per barrel for the same period in 1999. During the year ended December 31, 2000 production expenses and taxes increased to $4.2 million from $2.7 million in 1999. Direct lease operating expenses increased to $0.7 million in 2000 from $0.6 million in 1999 and on a unit of production basis was $.12 per Mcfe in 2000, as compared to $.12 per Mcfe in 1999. Production taxes in 2000 were $2.3 million, compared to $0.9 million in 1999 or $.40 per Mcfe in 2000, compared to $.18 per Mcfe in 1999. Production taxes are calculated based on a percentage of revenue from production. Therefore higher production and higher prices contributed to the increases. Gathering fees for the period increased slightly in 2000 to $1.32 million from $1.29 million in 1999, attributable to higher production volumes. Depletion, depreciation and amortization expenses (DD&A) increased to $3.2 million during the year ended December 31, 2000 from $2.1 million for the same period in 1999. On a unit basis, DD&A increased to $.57 per Mcfe, from $.44 per Mcfe in 1999 primarily as a result of increases in the proved reserves' full cost pool. General and administrative expenses decreased to $3.1 million during the year ended December 31, 2000 from $3.6 million for the same period in 1999. The decrease was attributable to reductions in personnel and overhead expenses during 2000. Interest expense for the period increased to $0.8 million in 2000 from $0.7 million in 1999. This increase was attributable to the increase in borrowings under the senior credit facility. In November 1999, the Company settled litigation relating to the plugging and abandonment of the White Estate No. 1 well. The settlement and legal costs relating to this litigation totaled $1.9 million. No such settlement occurred during the year ended December 31, 2000. RESULTS OF OPERATIONS - SIX MONTH PERIOD ENDED DECEMBER 31, 1999 COMPARED TO SIX MONTH PERIOD YEAR ENDED DECEMBER 31, 1998 Oil and gas revenues increased to $4.8 million for the six-month period ending December 31, 1999 from $3.1 million for the same period in 1998. The Company incurred a net loss of $1.5 million for the six-month period ending December 31, 1999 compared to a net loss of $6.7 million for the same period in 1998. The increase in gross revenues was attributable to an increase in both the Company's production and the increase in prices received for that production. During this period, the Company's cumulative production increased to 1.90 Bcf of gas, and 20.0 thousand barrels of condensate, up from 1.76 Bcf of gas, and 9.43 thousand barrels of condensate for the same period in 1998. During the six-month period ending December 31, 1999, the average product prices were $2.29 per Mcf and $21.69 per barrel, compared to $1.72 per Mcf and $11.77 per barrel for the same period in 1998. During the six-month period ending December 31, 1999 production expenses and taxes increased to $1.3 million from $1.2 million in 1998. Direct lease operating expenses decreased to 21 $0.3 million in 1999 from $0.4 million in 1998 and on a unit of production basis, to $0.136 per Mcfe in 1999, from $0.225 per Mcfe in 1998. This reduction was primarily attributable to the effects of restructuring operations and reductions in operating field staff. Production taxes for this period in 1999 were $0.5 million, compared to $0.25 million in 1998 or $0.238 per Mcfe in 1999, from $0.143 per Mcfe in 1998. Production taxes are calculated based on a percentage of revenue from production. Therefore, higher production and higher prices contributed to the increases. Depletion and depreciation expenses remained relatively constant for the six-month period ending December 31, 1999 to the same period in 1998. On a unit basis, such expenses decreased to $0.578 per Mcf, from $0.648 in 1998 primarily as a result of increases in proved reserves. General and administrative expenses decreased 58% to $1.7 million during the six-month period ending December 31, 1999 from $4.0 million for the same period in 1998. The decrease was attributable to the restructuring implemented during 1999. Net interest expense for the period increased to $0.3 million in 1999 from $0.1 million in 1998. This increase was attributable to both the increase in borrowings under the senior credit facility and reduction in cash balances earning interest. In November 1999, the Company settled litigation relating to the plugging and abandonment of the White Estate No. 1 well. The settlement and legal costs relating to this litigation totaled $1.9 million. RESULTS OF OPERATIONS - FISCAL YEAR ENDED JUNE 30, 1999 COMPARED TO FISCAL YEAR ENDED JUNE 30, 1998 The Company incurred a net loss of $8.9 million for the year ended June 30, 1999 compared to a net loss of $10.6 million for the year ended June 30, 1998. Oil and gas revenues increased to $7.0 million in fiscal 1999 from $3.6 million in 1998. This was directly attributable to the Company's drilling and completion activities in the Green River Basin of Wyoming. The Company's annual production increased to 4.1 Bcf of gas and 41.9 thousand barrels of condensate during 1999, up from 1.8 Bcf of gas and 14.0 thousand barrels of condensate during 1998. During 1999 the average product prices received were $1.54 per Mcf and $15.95 per barrel, compared to an average of $1.81 per Mcf and $13.26 per barrel in 1998. Depletion and depreciation expense increased to $1.8 million in 1999 from $1.4 million in 1998. The increase in depletion and depreciation expense was attributable to increased production. The per Mcf equivalent oil and gas depletion and depreciation rate fell to $0.41 in 1999. The decline in the per Mcfe depletion and depreciation rate was attributable to the effects of the ceiling test writedown of $3.4 million incurred in December 1998, additions to reserves and reduced finding and development costs. The book value of oil and gas properties was $33.8 million at June 30, 1999, compared to $37.3 million at June 30, 1998. The causes of this decrease were the sale and write-downs of oil and gas properties and the costs of drilling of additional wells. Production taxes and gathering fees increased to $1.7 million in 1999 from $0.7 million in 1998. Both increases were directly attributable to increases in production in the Green River Basin of Wyoming. During 1999, the Company recognized a property impairment charge of $3.4 million, as a result of the capitalized cost of oil and gas properties exceeding a "ceiling" on such costs computed in accordance with GAAP. This impairment was caused by the lower commodity prices at December 31, 1998. The ceiling test impairment is a direct line item on the income statement. In June 1999, the Company sold a working interest in certain undeveloped leaseholds for $5 million in cash, which had been split between proven and unproven properties and $8.2 22 million in carried work commitments which reduced the carrying value of unproven properties. The $8.2 million in carried work commitments will not be reflected on the books until they are incurred which will be in December 1999. General and administrative expenses increased to $5.8 million in 1999 from $3.4 million in 1998. This increase in total general and administrative expenses was primarily attributable to increases in staffing and activity during the first and second quarters of fiscal 1999. During the third and fourth quarters, the Company implemented a restructuring plan to reduce general and administrative expenses. During fiscal 1999, the Company wrote-off $2.0 million of debt that had been on the books in excess of two years. These debts were owed primarily by junior joint venture partners for amounts expended by the Company in drilling farm-out prospects on these partners' behalf for which the Company was never reimbursed. The Company evaluated the ability of the joint venture partners to repay the debts and determined that repayment was unlikely. Included in unproven properties is $2.5 million of prepaid environmental costs, which relate to the Company's agreement to purchase specified nitrogen oxide emission offsets. These offsets are to be utilized by the Company in the future development of its oil and gas properties in the Mesa Area as the asset that will generate the offsets is under construction. Of the total payment, $2.0 million was in the form of a note that bears interest at 10% payable in installments of $0.75 million and $1.25 million on July 15, 1999 and 2000, respectively. The $0.2 million of interest on this note at June 30, 1999 has been capitalized as part of the prepaid environmental cost. LIQUIDITY AND CAPITAL RESOURCES In the twelve-month period ending December 31, 2001 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 32 gross (14.62 net) wells in Wyoming and 15 gross (2.53 net) wells in China blocks and one gross (0.1 net) commitment well on the Getuo block. For the twelve-month period ending December 31, 2001 net capital expenditures were $58.4 million. At December 31, 2001, the Company reported a cash position of $1.4 million compared to $1.1 million at December 31, 2000. Working capital at December 31, 2001 was $(9.3) million as compared to $0.2 million at December 31, 2000. As of December 31, 2001, the Company had incurred bank indebtedness of $43.0 million and other long term debt of $3.1 million which was comprised of accrued capital expenditures that the Company will finance by drawing on the available bank facility. The positive cash flow 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 2001, which are projected to be $50.0 million. Of the $50.0 million budget, the Company plans to spend approximately $35.0 million in Wyoming and approximately $12.5 million in China in 2002. The remaining $2.5 million will go towards seismic, land and other miscellaneous costs in both areas. Of the $35.0 million for Wyoming the Company plans to drill or participate in an estimated 25 gross (11.4 net) wells in 2002, of which approximately $17.9 million is for exploration wells and the remaining $17.1 million will be for development wells. All of the $12.5 million for China will be for exploratory/appraisal wells. The Company currently has no budget for acquisitions of properties in 2002. As of March 1, 2002, the revolving senior credit facility provides for a $150.0 million revolving credit line with a borrowing base of $80.0 million. The credit facility matures on March 1, 2005. The notes bears 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 (1.5%) 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 23 borrowing base is subject to periodic (at least semi-annual) review and redetermination 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, 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. The notes are collateralized by a majority of the Company's proved domestic oil and gas properties and guaranteed by UP Energy and Ultra Petroleum Corp. At December 31, 2001 the Company had $43.0 million of outstanding borrowings under this credit facility, with a current average interest rate of 4.1%. The total amount outstanding at March 1, 2002 was $51.0 million. The Company was in compliance with all loan covenants at December 31, 2001 and 2000. During the year ended December 31, 2001, the Company generated cash from operating activities of $35.6 million as compared to $9.0 million for the year ended December 31, 2000 and $0.3 million for the year ended December 31, 1999. Cash flow from operations before changes in non-cash working capital was $27.5 million as compared to $13.0 million for the year ended December 31, 2000 and $0.3 million for the year ended December 31, 1999. The increase in cash from operating activities was attributable to the increase in earnings and DD&A and the increase in net changes to non-cash working capital items. During the year ended December 31, 2001 cash used in investing activities was to $61.3 million as compared to $24.5 million for the year ended December 31, 2000 and $4.3 million for the year ended December 31, 1999. The change is primarily attributable to increased drilling and completion activity. During the year ended December 31, 2001 cash provided by financing activities was $26.0 million as compared to $16.2 million for the year ended December 31, 2000 and $0.5 million for the year ended December 31, 1999. The change is primarily attributable to increased borrowing under the senior credit facility. The positive cash flow that the Company continues to produce and the availability under the senior credit facility are projected to be sufficient to fund the Company's budgeted capital expenditures for 2002. However, future cash flows and continued availability of financing are subject to a number of uncertainties beyond the Company's control such as production rates, the price of gas and oil, 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 Company's significant accounting policies are described in the notes to the consolidated financial statements. It is increasingly important to understand that the application of generally accepted accounting principles involve certain assumptions, judgments and estimates that affect reported amounts of assets, liabilities, revenues and expenses. The application of principles can result in varying results from company to company. The most significant principles that impact the Company and its subsidiaries relate to oil and gas reserve estimates and deferred taxes. The financial statements included in this report contain estimates of the Company's oil and gas reserves and the discounted future net revenues from those reserves, as prepared by independent petroleum engineers and/or the Company. There are numerous uncertainties 24 inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the control of the Company; and therefore, these estimates are subject to change. We use 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 amounts and their respective income tax bases (temporary differences). Management regularly reviews its deferred taxes assets for recoverability and establishes a valuation allowance based on historical taxable income, projected future taxable income and the expected timing of the reversals of existing temporary differences. During the year, the Company completed the acquisition of Pendaries Petroleum, Ltd., which gave rise to a deferred tax liability. Additionally, the Company fully utilized all of its available net operating carry-forwards attributable to continuing operations for financial statement purposes. The change in valuation allowance reflects management's assessment regarding the future realization of U.S. deferred tax assets and estimates of future earnings. RECENTLY ISSUED ACCOUNTING STANDARDS In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, Business Combinations ("SFAS No. 141") and SFAS No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142"). SFAS No. 141 was effective as of July 1, 2001 and SFAS No. 142 was effective January 1, 2002. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations. SFAS 141 specifies criteria that intangible assets acquired in a business combination must meet to be recognized and reported separately from goodwill. SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. SFAS No. 142 also requires that intangible assets with estimable useful lives be amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with SFAS No. 121 and subsequently, SFAS No. 144 after its adoption. The Canadian Institute of Chartered Accountants ("CICA") has adopted similar standards and accordingly, there will be no U.S. - Canadian GAAP differences arising from the addition of these standards. The Company has no goodwill or intangible assets. In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Company will also record a corresponding asset which is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The Company is required to adopt SFAS No. 143 on January 1, 2003. The Company is currently assessing the impact, if any, on the Company's consolidated financial statements for future periods. 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 25 will be eliminated from ongoing operations. The Company has adopted SFAS 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 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 121. The adoption of SFAS 144 had no impact on the Company's consolidated financial statements. CERTAIN CONSIDERATIONS 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 personal 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 producers, 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. 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. 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; and . require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells. 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 operations are conducted on public lands. These operations are subject to a variety of on-site security regulations as well as other permits and authorizations issued by the U.S. Bureau of Land Management ("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 26 and Gas 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 will be dependent upon its ability to continue to raise significant additional financing 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. 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 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 late 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 27 commercial quantities. Under the full-cost method of accounting these costs are then depleted using the units of production method based on the proven reserves determined by independent petroleum engineers. 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 descriptions of the Company's future drilling plans with respect to its prospects. A prospect is a property on 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 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 results of the BLM's EIS. 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. 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 28 decreases could result in reductions in the carrying value of such assets and an equivalent charge to earnings. Restrictions on Production Due to 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 lose interest in this project, then unless the Bohai Bay properties are sold to another party, the pace of development of the blocks could slow down or stop altogether and the blocks may never be developed. 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 provide cash to meet 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 our share of costs, it could lose or be forced to sell 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 the 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 our international operations; and . currency restrictions and exchange rate fluctuations; Tensions between China and its neighbors or various Western countries, especially the United States, 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 possible participation by China National Offshore Oil Company 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 addition, 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 of the United States. Operating Risk in China. Offshore operations, such as our Bohai Bay properties, are subject to a variety of operating risks specific to the marine environment, such as capsizing, collisions and/or loss from typhoons or other adverse weather conditions. These conditions can 29 cause substantial damage to facilities and interrupt production. As a result, the Company could incur substantial liabilities that could result in financial losses or failure. CERTAIN DEFINITIONS TERMS USED TO DESCRIBE QUANTITIES OF OIL AND NATURAL GAS . Bbl -- One stock tank barrel, or 42 US 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. . MBbl -- One thousand Bbls. . Mcf -- One thousand cubic feet of natural gas. . Mcfe -- One thousand cubic feet of natural gas equivalent. . MMBbl -- One million Bbls of oil or other liquid hydrocarbons. . MMcf -- One million cubic feet of natural gas. . MBOE -- One thousand BOE. . MMBOE -- One million BOE. 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 . Standard measure of proved reserves -- 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. 30 . Pre-tax discounted present value -- 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 OUR RESERVE QUANTITIES . Proved reserves -- The estimated quantities of crude oil, natural gas and natural gas liquids which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions. 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 (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) 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. 31 TERMS WHICH DESCRIBE THE COST TO ACQUIRE THE COMPANY'S RESERVES . Finding costs -- The Company's finding costs compare the amount the Company spent to acquire, explore and develop its oil and gas properties, explore for oil and gas and to drill and complete wells during a period, with the increases in reserves during the period. This amount is calculated by dividing the net change in the Company's evaluated oil and property costs during a period by the change in proved reserves plus production over the same period. The Company's finding costs as of December 31 of any year represent the average finding costs over the three-year period ending December 31 of that year. TERMS WHICH DESCRIBE THE PRODUCTIVE LIFE OF A PROPERTY OR GROUP OF PROPERTIES . Reserve life -- A measure of the productive life of an oil and gas property or a group of oil and gas properties, expressed in years. Reserve life for the years ended December 31, 2001, 2000 or 1999 equal the estimated net proved reserves attributable to a property or group of properties divided by production from the property or group of properties for the four fiscal quarters preceding the date as of which the proved reserves were estimated. TERMS USED TO DESCRIBE THE LEGAL OWNERSHIP OF THE COMPANY'S OIL AND GAS PROPERTIES . Royalty interest -- A real property interest entitling the owner to receive a specified portion of the gross proceeds of the sale of oil and natural gas production or, if the conveyance creating the interest provides, a specific portion of oil and natural gas produced, without any deduction for the costs to explore for, develop or produce the oil and natural gas. A royalty interest owner has no right to consent to or approve the operation and development of the property, while the owners of the working interests have the exclusive right to exploit the mineral on the land. . 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. . 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. 32 . 3-D seismic -- 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 production. Realized pricing is primarily driven by the prevailing price for crude oil and spot prices applicable to Ultra's US 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 $1.72 per Mcf to a monthly high of $7.61 per Mcf during 2001. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Page ---- Independent Auditors' Report Consolidated Balance Sheets December 31, 2001 and 2000 Consolidated Statements of Operations and Deficit for the Years Ended December 31, 2001, 2000, the Six-Months Ended December 31, 1999 and Year Ended June 30, 1999 Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2001, 2000, the Six-Months Ended December 31, 1999 and Year Ended June 30, 1999 Consolidated Statements of Cash Flow for the Years Ended December 31, 2001, 2000, the Six-Months Ended December 31, 1999 and Year Ended June 30, 1999 Notes to Consolidated Financial Statements 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 our definitive proxy statement, which will be filed not later than 120 days after December 31, 2001 and is incorporated herein by reference. 33 ITEM 11. EXECUTIVE COMPENSATION. The information required by this item will be included in our definitive proxy statement, which will be filed not later than 120 days after December 31, 2001 and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. The information required by this item will be included in our definitive proxy statement, which will be filed not later than 120 days after December 31, 2001 and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. The information required by this item will be included in our definitive proxy statement, which will be filed not later than 120 days after December 31, 2001 and is incorporated herein by reference. PART IV ITEM 14. 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) 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 Amended and Restated Credit Agreement dated March 1, 2002 among Bank One, NA, Union Bank of California, N.A., Guaranty Bank, FSB, Hibernia National Bank, Ultra Resources, Inc. and Banc One Capital Markets, Inc. 34 10.2 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) 10.3 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) 10.4 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) 10.5 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) 10.6 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 23.1 Consent of Netherland Sewell & Associates, Inc. (b) Reports on Form 8-K None 35 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 29, 2002 By: /s/ Michael D. Watford ------------------------------------------ Name: Michael D. Watford Title: Director, Chairman of the Board, CEO 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, Chief Executive March 29, 2002 ------------------------- Officer and President Michael D. Watford /s/ W. Charles Helton Director March 29, 2002 ------------------------- W. Charles Helton /s/ James E. Nielson Director March 29, 2002 ------------------------- James E. Nielson /s/ Robert E. Rigney Director March 29, 2002 ------------------------- Robert E. Rigney /s/ James C. Roe Director March 29, 2002 ------------------------- James C. Roe /s/ F. Fox Benton III Vice President, March 29, 2002 ------------------------- Business Development F. Fox Benton III and Finance 36 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 Canada, except for the supplemental disclosures regarding oil and gas producing activities which have been prepared in accordance with disclosure standards generally accepted in the United States of America. 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/ Kristen J. Miller ------------------------------- -------------------------------- Michael D. Watford Kristen J. Miller Chief Executive Officer Financial Reporting Manager March 18, 2002 AUDITORS' REPORT To the Shareholders of Ultra Petroleum Corporation We have audited the consolidated balance sheets of Ultra Petroleum Corporation and subsidiaries as at December 31, 2001 and 2000, and the consolidated statements of operations and deficit, shareholders' equity and cash flows for the years ended December 31, 2001 and 2000, the six months ended December 31,1999 and the year ended June 30, 1999. 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 of America. 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, these financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2001 and 2000, and the results of its operations and its cash flows for the years ended December 31, 2001 and 2000, the six months ended December 31,1999 and the year ended June 30, 1999, in accordance with accounting principles generally accepted in Canada. As required by the Company Act (British Columbia), we report that, in our opinion, these principles have been applied on a consistent basis. /s/ KPMG, LLP --------------------------- KPMG, LLP Denver, Colorado March 18, 2002 ULTRA PETROLEUM CORPORATION CONSOLIDATED BALANCE SHEETS

(Expressed in U.S. Dollars) December 31, ------------------------------------------- 2001 2000 ------------ ------------ ASSETS Current Assets Cash and cash equivalents $ 1,379,462 $ 1,143,591 Restricted cash 207,179 200,126 Accounts receivable, less allowance of $250,000 7,358,742 8,278,538 at December 31, 2000 and 1999 Prepaid drilling costs and other current assets 2,823,613 839,892 Note receivable (Note 8) - 2,530,976 ------------ ------------ 11,768,996 12,993,123 Oil and gas properties, using the full cost method of accounting (Note 3) 155,221,187 59,728,715 Capital assets (Note 4) 592,605 455,448 ------------ ------------ TOTAL ASSETS $167,582,788 $ 73,177,286 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities Accounts payable and accrued liabilities $ 21,096,348 $ 12,752,483 Long-term debt (Note 5) 46,092,928 24,530,612 Deferred income taxes 4,974,008 Deferred revenue 100,000 200,000 Shareholders' equity: Share capital (Note 6) 92,585,148 50,838,663 Retained Earnings (Deficit) 2,734,356 (15,144,472) ------------ ------------ 95,319,504 35,694,191 ------------ ------------ Commitments and contingencies (Note 12) TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $167,582,788 $ 73,177,286 ============ ============ See accompanying notes to consolidated financial statements. Approved on behalf of the Board: /s/ Michael D. Watford /s/ James E. Nielson ------------------------------- ---------------------------------- Michael D. Watford, Director James E. Nielson, Director

ULTRA PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS AND DEFICIT

Six Months (Expressed in U.S. Dollars) Year Ended Ended Year Ended ---------------------------------------------- ------------- ------------- December 31, December 31, December 31, December 31, June 30 2001 2000 1999 1999 1999 ---------------------------------------------- ------------ ------------ (unaudited) REVENUES: Natural gas sales $ 38,204,298 $ 19,399,001 $ 8,229,984 $ 4,352,184 $ 6,352,315 Oil sales 2,996,955 1,603,635 746,722 433,627 670,023 ------------ ------------ ------------ ------------ ------------ 41,201,253 21,002,636 8,976,706 4,785,811 7,022,338 ------------ ------------ ------------ ------------ ------------ EXPENSES: Production expenses and taxes 9,023,271 4,241,020 2,714,966 1,329,034 2,571,081 Depletion and depreciation 6,687,433 3,162,568 2,105,663 1,186,395 1,794,307 Ceiling test write-down - - - - 3,416,786 Bad debt expense (recovery) - - 1,983,828 (35,588) 2,019,416 General and administrative 4,231,214 3,078,156 3,556,564 1,667,846 5,861,125 Interest 1,687,172 802,364 679,491 344,284 576,506 ------------ ------------ ------------ ------------ ------------ 21,629,090 11,284,108 11,040,512 4,491,971 16,239,221 OPERATING INCOME (LOSS) 19,572,163 9,718,528 (2,063,806) 293,840 (9,216,883) OTHER INCOME (EXPENSE): Interest 173,411 87,879 33,900 18,219 151,709 Other 220,016 83,519 135,008 - 135,008 Lawsuit settlement (Note 12) - - (1,875,610) (1,875,610) - ------------ ------------ ------------ ------------ ------------ 393,427 171,398 (1,706,702) (1,857,391) 286,717 ------------ ------------ ------------ ------------ ------------ INCOME (LOSS) FOR THE PERIOD BEFORE 19,965,590 9,889,926 (3,770,508) (1,563,551) (8,930,166) INCOME TAXES Income tax provision - deferred 2,086,762 - - - - INCOME (LOSS) FOR THE PERIOD 17,878,828 9,889,926 (3,770,508) (1,563,551) (8,930,166) DEFICIT, beginning of period (15,144,472) (25,034,398) (21,263,890) (23,470,847) (14,540,681) ------------ ------------ ------------ ------------ ------------ DEFICIT, end of period $ 2,734,356 $ (5,254,546) $(28,804,906) $(26,597,949) $(23,470,847) ============ ============ ============ ============ ============ INCOME (LOSS) PER COMMON SHARE - BASIC $ 0.25 $ 0.17 $ (0.07) $ (0.03) $ (0.16) ============ ============ ============ ============ ============ INCOME (LOSS) PER COMMON SHARE - FULLY DILUTED $ 0.24 $ 0.17 $ (0.07) $ (0.03) $ (0.16) ============ ============ ============ ============ ============ Weighted average common shares outstanding - basic 72,371,839 56,821,748 56,446,086 56,670,808 55,804,459 ============ ============ ============ ============ ============ Weighted average common shares outstanding - fully diluted 75,931,529 58,438,783 56,446,086 56,670,808 55,804,459 ============ ============ ============ ============ ============

See accompanying notes to consolidated financial statements. ULTRA PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

Share Capital Authorized 10,000,000 preferred shares 100,000,000 common shares Year Ended Year Ended Year Ended December 31, 2001 December 31, 2000 December 31, 1999 ------------------------------------------------------------ ---------------------------- Issued Number Amount Number Amount Number Amount ------------------------------------------------------------ ---------------------------- Common Shares Balance, beginning of year 56,939,762 $ 50,838,663 56,751,125 $ 50,666,631 56,493,725 $ 50,485,327 Employee stock option plan 701,500 611,387 5,000 4,032 257,400 181,304 Employee stock plan 682,198 1,098,448 119,403 80,000 - - Acreage option purchase - - 64,234 88,000 - - Merger with Pendaries Petroleum Ltd. 40,036,650 - - - - - ---------- ------------ ---------- ------------ ---------- ------------ Balance, end of period 73,318,418 $ 92,585,148 56,939,762 $ 50,838,663 56,751,125 $ 50,666,631 ========== ============ ========== ============ ========== ============ Retained earnings (deficit) Balance, beginning of year (15,144,472) (25,034,398) (21,263,890) Earnings for period 17,878,828 9,889,926 (3,770,508) ------------ ------------ ------------ Balance, end of period 2,734,356 (15,144,472) (25,034,398) ============ ============ ============ Six Months Ended Year Ended December 31, 1999 June 30, 1999 ------------------------------------------------------------ Issued Number Amount Number Amount ------------------------------------------------------------ Common Shares Balance, beginning of year 56,493,725 $ 50,485,327 48,091,715 $ 32,312,036 Employee stock option plan 257,400 181,304 1,165,910 572,849 Conversion of special warrants - - 7,236,100 17,600,442 ---------- ------------ ---------- ------------ Balance, end of period 56,751,125 $ 50,666,631 56,493,725 $ 50,485,327 ========== ============ ========== ============ Retained earnings (deficit) Balance, beginning of year (23,470,847) (14,540,681) Earnings for period (1,563,551) (8,930,166) ------------ ------------ Balance, end of period (25,034,398) (23,470,847) ============ ============

ULTRA PETROLEUM CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOW

Six Months Year Ended Ended Year Ended -------------------------------------------- ----------------------------- December 31, December 31, December 31, December 31, June 30, 2001 2000 1999 1999 1999 ------------ ------------ ------------ ------------- ---------- (unaudited) CASH PROVIDED BY (USED IN): OPERATING ACTIVITIES: Income (loss) for the year $ 17,878,828 $ 9,889,926 $(3,770,508) $(1,563,551) $ (8,930,166) Add (deduct): Items not involving cash: Depletion and depreciation 6,687,433 3,162,568 2,105,663 1,186,395 1,794,307 Deferred income taxes 2,086,762 Ceiling test write-down - - - - 3,416,786 Provision for bad debts - - 1,983,828 - 2,019,416 Stock compensation 848,448 - - - - Net changes in non-cash working capital: Restricted cash (7,053) 390,145 (413,802) 379,272 (856,062) Accounts receivable 919,796 (5,740,728) 2,748,840 26,782 6,640,176 Prepaid expenses and other current assets (1,983,721) (511,023) 2,348,214 49,896 (186,058) Note receivable (683,137) - - - 750,000 Accounts payable and accrued liabilities 9,962,508 1,955,546 (4,570,146) 645,533 (2,635,020) Deferred revenue (100,000) (100,000) (100,000) (50,000) (100,000) ------------------------------------------------------------------------------ 35,609,864 9,046,434 332,089 674,327 1,913,379 ------------------------------------------------------------------------------ INVESTING ACTIVITIES: Oil and gas property expenditures (61,330,153) (22,157,020) (9,318,200) (6,187,786) (21,996,324) Note receivable - (2,530,976) - - - Purchase of capital assets (317,592) (212,300) (22,392) (45,054) (58,319) Proceeds from sale of oil and gas properties 312,365 359,764 5,000,000 4,608,712 21,038,000 ------------------------------------------------------------------------------ (61,335,380) (24,540,532) (4,340,592) (1,624,128) (1,016,643) FINANCING ACTIVITIES: Long-term debt, net 25,350,000 16,063,966 116,646 387,485 (6,583,126) Issuance of shares 611,387 172,032 369,183 181,304 572,849 ------------------------------------------------------------------------------ 25,961,387 16,235,998 485,829 568,789 (6,010,277) ------------------------------------------------------------------------------ INCREASE (DECREASE) IN CASH DURING THE PERIOD 235,871 741,900 (3,522,674) (381,012) (5,113,541) CASH AND CASH EQUIVALENTS, beginning of period 1,143,591 401,691 3,924,365 782,702 5,896,243 ------------------------------------------------------------------------------ CASH AND CASH EQUIVALENTS, end of period $ 1,379,462 $ 1,143,591 $ 401,691 $ 401,691 $ 782,702 ============================================================================= SUPPLEMENTAL INFORMATION Cash paid for: Interest $ 1,687,172 $ 802,364 $ 679,491 $ 564,810 $ 454,742 Income taxes $ 10,000 $ 25,000 $ 3,000 $ 3,000 $ - 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 ULTRA PETROLEUM CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Expressed in U.S. dollars unless otherwise noted) Years ended December 31, 2001 and 2000, six months ended December 31, 1999 and year ended June 30, 1999. DESCRIPTION OF THE BUSINESS Ultra Petroleum Corporation (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: Fiscal year change. The Company changed its fiscal year-end to a calendar year- end effective December 31, 1999. The six month transition period ended December 31, 1999 is presented herein. (a) Basis of presentation and principles of consolidation: The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, Ultra Petroleum (U.S.A.) Inc., Ultra Resources, Inc, Pendaries Petroleum Ltd. and Sino-American Energy Corporation. 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 Canada. (c) Revenue recognition and deferred revenue: Revenues from oil and gas operations are recognized at the time the oil is sold or natural gas is delivered. The cash received upon dedicating certain production volumes to a gas pipeline is deferred and is being included in natural gas sales on a straight line basis over the term of the five year dedication. (d) Cash and cash equivalents: We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. (e) 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. (f) Capital assets: Capital assets are recorded at cost and depreciated using the declining-balance method based on a seven-year useful life. (g) 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. Separate cost centers are maintained for each country in which the Company has operations. During 2000 and 1999, the Company's primary oil and gas operations were conducted in the United States. During 2001, the Company began drilling activities in Bohai Bay, China. The capitalized costs, together with the costs of production equipment, are depleted using the units-of-production method based on the proven reserves as determined by independent petroleum engineers. Oil and gas reserves and production are converted into equivalent units based upon relative energy content. Costs of acquiring and evaluating unproved properties are initially excluded from the costs subject to depletion. These unproved properties are assessed periodically to ascertain whether impairment has occurred. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the costs subject to depletion. The total capitalized cost of oil and gas properties less accumulated depletion is limited to an amount equal to the estimated future net cash flows from proved reserves, discounted at 10%, using year-end prices, plus the cost (net of impairment) of unproved properties as adjusted for related tax effects (the "full cost ceiling test limitation"). Proceeds from the sale of oil and gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would significantly alter the rate of depletion. Substantially all of the Company's exploration, development and production activities are conducted jointly with others and, accordingly, these financial statements reflect only the Company's proportionate interest in such activities. (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) Foreign currency translation: The Company has adopted the United States dollar as its reporting currency, which is also its functional currency. The Company and its subsidiaries are considered to be integrated operations and accounts in Canadian dollars are translated using the temporal method. Under this method, monetary assets and liabilities are translated at the rates of exchange in effect at the balance sheet date; non-monetary assets at historical rates and revenue and expense items at the average rates for the period other than depletion and depreciation which are translated at the same rates of exchange as the related assets. The net effect of the foreign currency translation is included in current operations. (j) 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, 2001 and 2000, the six months ended December 31, 1999 and the year ended June 30, 1999:

For the six months ended For the year For the years ended December 31, December 31, ended June 30, 2001 2000 1999 1999 --------------------------------- ------------- -------------- Net income (loss) $17,878,828 $ 9,889,926 $(1,563,551) $(8,930,166) =========== =========== =========== =========== Weighted average common shares outstanding during the period 72,371,839 56,821,748 56,670,808 55,804,459 Effect of dilutive instruments 3,559,690 1,617,035 - - ----------- ----------- ----------- ----------- Weighted average common shares outstanding during the period including the effects of dilutive instruments 75,931,529 58,438,783 56,670,808 55,804,459 =========== =========== =========== =========== Basic earnings (loss) per share $ 0.25 $ 0.17 $ (0.03) $ (0.16) =========== =========== =========== =========== Diluted earnings (loss) per share $ 0.24 $ 0.17 $ (0.03) $ (0.16) =========== =========== =========== =========== 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. 373,942 - 1,026,122 359,167 =========== =========== =========== ===========

(k) Use of estimates: Preparation of consolidated financial statements in accordance with generally accepted accounting principles in Canada requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. (l) Reclassifications: Certain amounts in the financial statements of the prior years have been reclassified to conform to the current year financial statement presentation. (m) Impact of recently issued accounting pronouncements: In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, Business Combinations ("SFAS No. 141") and SFAS No. 142, Goodwill and Other Intangible Assets ("SFAS No. 142"). SFAS No. 141 was effective as of July 1, 2001 and SFAS No. 142 was effective January 1, 2002. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations. SFAS 141 specifies criteria that intangible assets acquired in a business combination must meet to be recognized and reported separately from goodwill. SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. SFAS No. 142 also requires that intangible assets with estimable useful lives be amortized over their respective estimated useful lives to their estimated residual values, and reviewed for impairment in accordance with SFAS No. 121 and subsequently, SFAS No. 144 after its adoption. The Canadian Institute of Chartered Accountants ("CICA") has adopted similar standards and accordingly, there will be no U.S. - Canadian GAAP differences arising from the addition of these standards. The Company has no goodwill or intangible assets. In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations ("SFAS No. 143"). SFAS No. 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development and/or normal use of the assets. The Company will also record a corresponding asset which is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation will be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The Company is required to adopt SFAS No. 143 on January 1, 2003. The Company is currently assessing the impact, if any, on the Company's consolidated financial statements for future periods. 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 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 144 to 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 121. The adoption of SFAS 144 had no impact on the Company's consolidated financial statements. 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 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. 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. 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. If the acquisition had occurred at the beginning of 2000, the Company would have reported no additional expense for operating expenses related to the China property as these properties still remain in the development phase. Since the properties are not producing, there would not have been any impact to revenues, net income or earnings per share. Additionally, no deferred tax liability would have been recorded as the net operating losses on a consolidated level would have equaled the variance between the book and tax basis. There would be no material change to the consolidated financial statements for the year ended December 31, 2001 since the acquisition occurred close to the beginning of the year. 3. OIL AND GAS PROPERTIES: DECEMBER 31, DECEMBER 31, 2001 2000 --------------------------- Developed Properties: Acquisition, equipment, exploration, development drilling and environmental costs $100,574,404 $54,362,982 Less accumulated depletion, depreciation and amortization (13,499,605) (7,047,605) ------------- ------------ 87,074,799 47,315,377 Unproved properties - China 55,894,246 - Unproved properties - Wyoming 12,252,142 12,413,338 ------------- ----------- $ 155,221,187 $59,728,715 ============= =========== 4. CAPITAL ASSETS:

December 31, December 31, December 31, December 31, 2001 2001 Accumulated 2001 Net 2000 Net Cost Depreciation Book Value Book Value -------------------------------------------------------------- Computer equipment $ 591,854 $337,648 $254,206 $241,223 Office equipment 228,880 122,051 106,829 67,325 Field equipment 183,775 118,934 64,841 50,420 Other 258,625 91,896 166,729 96,480 ---------- -------- -------- -------- $1,263,134 $670,529 $592,605 $455,448 ========== ======== ======== ========

5. LONG-TERM DEBT: December 31, December 31, 2001 2000 ----------- ----------- Bank indebtedness $43,000,000 $17,650,000 Short term obligations to be refinanced 3,092,928 6,880,612 ----------- ----------- $46,092,928 $24,530,612 =========== =========== Bank indebtedness: On March 22, 2000, the Company entered into a new senior revolving credit facility (New Facility) with Bank One, Texas N.A. Proceeds from the New Facility were used to pay off the outstanding balance of the Initial Facility at March 22, 2000 and to fund the Company's drilling programs. This facility provides for a maximum line of credit of $40 million with an initial borrowing base of $18 million. The borrowing base was increased on January 7, 2002 to $50 million. The outstanding balance on the line bears interest at the bank's Prime Rate or LIBOR plus two and one half percent and is secured by all of the Company's Wyoming oil and gas properties. The New Facility expires on March 1, 2003. On March 1, 2002, the Company closed a syndicated senior revolving credit facility with an initial borrowing base of $80 million. The syndicate of five banks includes: Bank One, NA, Union Bank of California, Hibernia National Bank, Guaranty Bank, and Compass Bank. The outstanding balance on the line bears interest at the bank's prime rate or LIBOR plus 1.75% and is secured by all of the Company's Wyoming oil and gas properties. The revolving credit facility contains various covenants and requires the Company to maintain various financial ratios as defined in the agreement. As of December 31, 2002, the Company was in compliance with the covenants and required ratios. Short term obligations to be refinanced: These costs relate to drilling obligations which will be funded on a long term basis through the use of the available borrowing base of bank indebtedness. 6. SHARE CAPITAL: (a) AUTHORIZED: 100,000,000 common shares with no par value (b) ISSUED: Number of Shares Amount ---------- ----------- Balance, June 30, 1998 48,091,715 $32,312,036 Shares issued during the year: For cash 1,165,910 572,849 For conversion of special warrants 7,236,100 17,600,442 ---------- ----------- Balance, June 30, 1999 56,493,725 50,485,327 Shares issued during the period: For cash 257,400 181,304 ---------- ----------- Balance, December 31, 1999 56,751,125 50,666,631 Shares issued during the period: For cash 5,000 4,032 For services rendered 183,637 168,000 ---------- ----------- Balance, December 31, 2000 56,939,762 50,838,663 Shares issued during the period: For cash 1,383,698 1,709,835 For Pendaries Acquisition 14,994,958 40,036,650 ---------- ----------- Balance, December 31, 2001 73,318,418 $92,585,148 ========== =========== (c) SHARE OPTIONS The following table summarizes the changes in stock options for the three-year period ending December 31, 2001: Weighted Average Number of Exercise Price Options (Cdn) ----------- --------------- Balance, June 30, 1998 3,463,220 $0.50 to $7.10 Granted 2,150,000 $1.46 to $3.85 Exercised (545,600) $0.50 to $1.05 Cancelled (1,445,360) $3.79 to $7.10 ----------- --------------- Balance, June 30, 1999 3,622,260 $1.50 to $6.96 Granted 1,595,000 $1.00 to $1.20 Exercised (257,400) $ 1.05 Cancelled (440,000) $ 1.05 ----------- --------------- Balance, December 31, 1999 4,519,860 $1.00 to $6.63 Granted 1,255,000 $0.81 to $4.15 Exercised (5,000) $ 1.20 Cancelled (1,244,860) $1.20 to $6.63 ----------- --------------- Balance, December 31, 2000 4,525,000 $0.81 to $4.15 Granted 1,630,000 $4.69 to $8.20 Exercised (701,500) $1.00 to $4.90 Cancelled (22,500) $1.79 to $8.20 ----------- --------------- Balance, December 31, 2001 5,431,000 $0.81 to $8.20 =========== =============== The share options outstanding at December 31, 2001 were held as follows: 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. The following table summarizes information about the stock options outstanding at December 31, 2001:

Options Outstanding Options Exercisable --------------------------------------- -------------------------------------- Weighted Weighted Range of Weighted Average Average Average Exercise Number Remaining Exercise Price Number Exercise Price Prices (Cdn) Outstanding Contractual Life (Cdn) Exercisable (Cdn) ----------- ----------- ----------------- -------------- ------------ --------------- $0.81-$1.79 3,743,500 7.7 Years $1.40 3,743,500 $1.40 $4.15-8.20 1,687,500 9.2 Years $6.20 1,023,750 $5.86

(d) SHARE PURCHASE WARRANTS: The following table summarizes the changes in the share purchase warrants for the three-year period ending December 31, 2001:

Number of Special Warrants Price Range (Cdn) ------------------------------------- Balance, June 30, 1998 1,455,000 $0.35 to $3.35 Issued upon conversion of Special Warrants 5,832,100 $4.02 to $5.20 Exercised (205,000) $0.48 to $0.56 Expired (1,250,000) $4.02 to $4.62 ------------- Balance, June 30, 1999 5,832,100 $4.02 to $5.20 Expired (4,428,100) $4.02 to $4.62 ------------- Balance, December 31, 1999 1,404,000 $4.02 to $5.20 ------------- Expired (1,404,000) $4.02 to $5.20 ------------- Balance, December 31, 2000 - =============

Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" (SFAS 123) defines a fair value method of accounting for employee stock options and similar equity instruments. SFAS 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 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, -------------------------------------- 2001 2000 1999 ----------- ---------- ----------- (In thousands, except per share amounts) Net income: As reported $17,878,828 $9,889,926 $(3,770,508) Pro forma $14,924,923 $9,056,297 $(6,000,150) Net income per common share: Basic: As reported $ 0.25 $ 0.17 $ (0.03) Pro forma $ 0.21 $ 0.16 $ (0.11) Diluted: As reported $ 0.24 $ 0.17 $ (0.03) Pro forma $ 0.20 $ 0.16 $ (0.11)

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 31,1999, expected volatility of approximately 68%, at December 31, 2000, expected volatility of approximately 45%, at December 31, 2001, expected volatility of 30%. All options have expected lives of ten years. 7. RELATED PARTY TRANSACTIONS: The following amounts were paid to directors and officers of the Company or its affiliates:

Six months ended Year ended December 31, June 30, 1999 1999 ----------------------------- Office rent and administration services to a company controlled by a director $ 106,899 $404,806 ---------------- ------------- Management bonus to directors and officers $ - $190,743 ---------------- ------------- Wages/fees to directors and officers $ - $193,320 ---------------- ------------- Amounts due from related parties: Enterprise Exploration and Production Inc. (a) - 22,601 Transglobe Energy Corporation (b) 4,299 3,010 ---------------- ------------- Total $ 4,299 $ 44,206 ================ ============= Amounts due to related parties: Arrowhead Minerals Corporation $ - $ 12,200 Enterprise Exploration and Production Inc. - 39,869 ---------------- ------------- Total $ - $ 52,069 ================ =============

The above amounts due from and to related parties were incurred in the normal course of oil and gas operations. There were no related party transactions for the year ended December 31, 2001 and 2000. Related party relationships:(a) Enterprise Exploration and Production Inc. ("Enterprise") One of the Company's directors is the owner of Enterprise. The Company and Enterprise both own working interests in one of the Company's oil and gas properties. (b) Transglobe Energy Corporation ("Transglobe") One of the Company's previous directors is a director and Chairman of Transglobe. The Company and Transglobe both own working interests in a number of the same oil and gas properties. 8. NOTES RECEIVABLE: In conjunction with the arrangement pursuant to which Ultra would acquire all of the issued and outstanding shares of Pendaries Petroleum Ltd (Pendaries) (Note 2), Ultra provided a line of credit to Pendaries' subsidiary, Sino-American Energy Corporation (Sino-American). The line of credit bears interest at the prime rate of Bank One Texas, N.A (9.3% at December 31, 2000). The outstanding balance at December 31, 2000 was $2,530,976. As of January 16, 2001, the closing date of the Pendaries acquisition, the note was converted to an inter-company receivable. 9. INCOME TAXES: The recovery of (provision for) income taxes for the years ended December 31, 2000 and 2001 vary from the amounts that would be computed by applying the U.S. Federal income tax rate of 38.5% to pretax income as a result of the following:

December 31, 2000 December 31, 2001 ----------------- ----------------- Federal tax expense at statutory rate $ 3,598,345 $ 7,133,993 State income tax expense 43,132 468,024 Adjustment to estimated acquired net operating losses and partnership income 1,162,921 169,417 Percentage depletion (477,417) (523,929) Other 5,572 34,870 Decrease in valuation allowance (4,332,553) (5,195,612) ------------ ------------- Actual income tax expense $ - $ 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, 2000 December 31, 2001 ------------------ ----------------- Future tax assets: Property and equipment $ 6,690,227 $ 9,472,486 Net operating loss carry-forward 6,028,824 10,288,856 Other - 36,182 ----------- ------------- 12,719,051 19,797,524 Less valuation allowance (5,208,618) - ----------- ------------- Total future assets 7,510,433 19,797,524 Future tax liabilities - property and equipment (7,510,433) (24,771,533) ----------- ------------- Net future tax assets (liabilities) $ - $ (4,974,009) ----------- ------------- At December 31, 2001, 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) $9,082,955 $ 202,180 $ 8,880,775 2001-2008 ------------------------------------------------------------------------------------- United States (US dollars) $ - $25,967,537 $ 25,967,537 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. 10. 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 $187,255 and $130,341 for the years ended 2001 and 2000, respectively, $27,060 for the six months ended December 31, 1999 and $58,978 for the year ended June 30, 1999. 11. DIFFERENCES BETWEEN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES IN CANADA AND THE UNITED STATES: The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in Canada ("Canadian GAAP"), which differ in certain respects from generally accepted accounting principles in the United States ("US GAAP"). Had the Company followed US GAAP, the carrying value of the oil and gas properties would not be materially different than under Canadian GAAP. Under US GAAP, the Company is required to discount future net revenues at 10% for purposes of calculating any required ceiling test write-down. Under Canadian GAAP, future net revenues are not discounted, however, they are reduced for estimated future general and administrative expenses and interest. For the year ended, the six months ended December 31, 1999 and the years-ended June 1999 and 1998, the calculations of the ceiling test write downs that were recorded under Canadian GAAP approximated amounts determined under US GAAP. Total Shareholders' Equity under US GAAP would be $169,199 lower due to the manner in which escrowed shares were accounted for in fiscal 1995. 12. COMMITMENTS AND CONTINGENCIES: The Company is committed to payments, under an operating lease for office space, of $376,000 in 2002 and $380,000 in fiscal 2003 . Approximately 50% of these payments are offset by a sublease with the same term as the primary lease. During the six months ended December 31, 1999, the Company settled the litigation relating to the 1998 plugging and abandonment of the White Estate No. 1 well in Henderson County, Texas. The settlement and the legal fees associated with this litigation resulted in a charge of $1,875,610. 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. 13. FAIR VALUE OF FINANCIAL INSTRUMENTS: For certain of the Company's financial instruments including accounts receivable, note 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. 14. SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED): As discussed in Note 9, during the year the Company fully utilized all available net operating loss carry-forwards attributable to continuing operations for financial statement purposes. The quarterly numbers presented below reflect that fourth quarter adjustment spread proportionately throughout the year and as a result differ from those previously filed.

Revenues from Net Income Basic Continuing Before Income Income Tax Earnings Per Earnings Per Operations Expenses tax Provision Provision Net Income Share -------------------------------------------------------------------------------------- (in thousands, except for per share data) 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 ======= ======= ======= ====== ======= 2000 First Quarter $ 2,357 $ 1,987 $ 370 - $ 370 $0.01 $0.01 Second Quarter $ 2,652 $ 2,036 $ 616 - $ 616 $0.02 $0.02 Third Quarter $ 3,922 $ 2,122 $ 1,800 - $ 1,800 $0.03 $0.03 Fourth Quarter $12,072 $ 4,969 $ 7,103 - $ 7,103 $0.12 $0.12 ------- ------- ------- ------ ------- $21,003 $11,114 $ 9,889 - $ 9,889 ======= ======= ======= ====== =======

15. 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, 2001, 2000 and 1999 are based upon estimates prepared by Netherland, Sewell & Associates, Inc. dated February 21, 2002, February 12, 2001 and February 4, 2000, respectively. The reserve reports as of July 1, 1999 have been prepared by Gilbert Lausten Jung Associates Ltd. These are estimated quantities of proved oil and gas reserves for the Company and the changes in total proved reserves as of December 31, 2001, 2000 and for the six months ended December 31, 1999 and as of June 30, 1999. All such reserves are located in the United States. B. ANALYSES OF CHANGES IN PROVEN RESERVES:

OIL (BBLS) GAS (MCF) ----------------------- Reserves, July 1, 1998 579,000 57,100,000 --------- ------------- Extensions, discoveries and additions 66,000 8,640,000 Production (42,000) (4,129,000) Revisions 125,000 8,400,000 Acquisition of reserves in place - - Sale of reserves in place (308,000) (28,575,000) --------- ------------- Reserves, July 1, 1999 420,000 41,436,000 --------- ------------- Extensions, discoveries and additions 266,000 33,228,000 Production (19,600) (1,907,600) Revisions (91,400) (1,525,400) Acquisition of reserves in place - - Sale of reserves in place - - --------- ------------- Reserves, July 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 (118,800) (11,499,800) Revisions 88,400 (3,117,600) Acquisition of reserves in place - - Sale of reserves in place - - ----------- ------------ Reserves, January 1, 2002 3,482,800 423,829,600 ----------- ------------ Proved developed reserves: July 1, 1999 350,000 34,400,000 ========== ============ January 1, 2000 297,000 36,480,000 ========== ============ January 1, 2001 683,000 84,550,000 ========== ============ January 1, 2002 1,295,000 150,397,000 ========== ============

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

December 31, December 31, December 31, June 30, 2001 2000 1999 1999 ------------ ------------ ------------ --------- Future cash inflows $ 939,441 $1,301,456 $148,609 $ 81,797 Future production costs (257,960) (205,935) (34,708) (13,638) Future development costs (149,806) (43,395) (20,963) (3,677) Future income taxes (25,135) (293,630) - - ------------ ------------ ------------ --------- Future net cash flows 506,541 758,496 92,938 64,482 Discount at 10% (332,707) (402,909) (51,663) $(38,451) ------------ ------------ ------------ --------- Standardized measure of discounted future net cash flows $ 173,834 $ 355,587 $ 41,275 $ 26,031 ============ ============ ============ ========= Pre tax standardized measure SEC PV-10 $ 182,460 $ 493,243 $ 41,275 $ 26,031 ============ ============ ============ =========

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 (000)

December 31, December 31, December 31, June 30, 2001 2000 1999 1999 ------------ ------------ ------------ --------- Standardized measure, beginning $ 355,587 $ 41,275 $26,031 $ 15,749 Net revisions (1,820) (371) (1,306) 8,511 Extensions, discoveries and other changes 177,819 140,348 24,771 6,641 Sales of reserves in place - - - (21,751) Changes in future development costs (31,066) (9,622) (7,677) (1,241) Sales of oil and gas, net of production costs (39,762) (18,083) (3,457) (4,451) Net change in prices and production costs (313,708) 191,885 (4,330) 8,201 Development costs incurred during the period that reduce future development costs - 1,385 - 15,787 Accretion of discount 35,559 4,127 2,603 1,575 Net change in income taxes (8,775) 4,643 4,640 (2,990) ------------ ------------ ------------ --------- Standardized measure, ending $ 173,834 $355,587 $41,275 $ 26,031 ============ ============ ============ =========

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. E. COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT ACTIVITIES (000):

UNITED STATES ------------- Year Ended Year Ended Six Months Ended Year Ended Years Ended December 31, December 31, December 31, June 30, 2001 2000 1999 1999 --------------------------------------------------------------- Acquisition costs - unproved properties $ 310 $ - $ 375 $ 598 Exploration 33,845 11,175 3,505 3,907 Development 11,950 18,115 2,308 17,491 ----------- ----------- ------------ ------------ Total $46,105 $29,290 $ 6,188 $21,996 =========== =========== ============ ============ CHINA ----- Year Ended Year Ended Six Months Ended Year Ended Years Ended December 31, December 31, December 31, June 30, 2001 2000 1999 1999 --------------------------------------------------------------- Acquisition costs - unproved properties $11,944 $ - $ - $ - Exploration - - - - Development - - - - ----------- ----------- ------------ ------------ Total $11,944 $ - $ $ - =========== =========== ============ ============ F. RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (US$000): Year Ended Year Ended Six Months Ended Year Ended Years Ended December 31, December 31, December 31, June 30, 2001 2000 1999 1999 --------------------------------------------------------------- Oil and gas revenue $41,201 $21,003 $ 4,786 $ 7,022 Production expenses and taxes (9,023) (4,241) (1,329) (2,571) Depletion and depreciation (6,687) (3,163) (1,186) (1,794) ----------- ----------- ------------ ------------ Total $25,491 $13,599 $ 2,271 $ 2,657 =========== =========== ============ ============