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  **UNITED STATES SECURITIES AND EXCHANGE COMMISSION****Washington, D.C. 20549****Form 10-K**   þ     **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE    SECURITIES EXCHANGE ACT OF 1934**   **For the Fiscal Year ended December 31, 2005.** **o** **TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE    SECURITIES EXCHANGE ACT OF 1934**   **For the transition period    from          to          .****Commission File Number: 0-29370****Ultra Petroleum Corp.***(Exact Name of Registrant as Specified in Its Charter)*   **Yukon Territory, Canada** **N/A***(Jurisdiction of Incorporation or Organization)* *(I.R.S. Employer Identification No.)***363 North Sam Houston Parkway East, Suite 1200****Houston, Texas 77060***(Address of Principal Executive Offices) (Zip Code)***281-876-0120****(Registrant’s Telephone Number, Including Area Code)****Securities registered pursuant to Section 12(b) of theAct:**   **Title of Each Class** **Name of Each Exchange on Which Registered**       Common Shares, without par value     American Stock Exchange**Securities registered pursuant to Section 12(g) of theAct:****None**     Indicate by check mark if the registrant is a well-knownseasoned issuer, as defined in Rule 405 of the SecuritiesAct.     YES þ          NO o     Indicate by check mark if the registrant is not required to filereports pursuant to Section 13 or Section 15(d) of theAct.     YES o          NO þ     Indicate by check mark whether the registrant (1) has filedall reports required to be filed by Section 13 or 15(d) ofthe Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrantwas required to file such reports), and (2) has beensubject to such filing requirement for the past90 days.     YES þ          NO o     Indicate by check mark if disclosure of delinquent filerspursuant to Item 405 ofRegulation S-K isnot contained herein, and will not be contained, to the best ofregistrant’s knowledge, in definitive proxy or informationstatements incorporated by reference in Part III of thisForm 10-K or anyamendment to thisForm 10-K.     þ     Indicate by check mark whether the registrant is a largeaccelerated filer, an accelerated filer or a non-acceleratedfiler. See definition of “accelerated filer largeaccelerated filer” inRule 12b-2 of theExchange Act.Large acceleratedfiler þ          Acceleratedfiler o          Non-acceleratedfiler o     Indicate by check mark whether the registrant is a shell company(as defined inRule 12b-2 of theAct.     YES o          NO þ     The aggregate market value of the voting and non-voting commonequity held by non-affiliates of the registrant wasapproximately $4,650,667,733 as of June 30, 2005 (based onthe last reported sales price of $30.36 of such stock on theAmerican Stock Exchange on such date).     As of February 28, 2006, there were 155,235,864 commonshares of the registrant outstanding.     Documents incorporated by reference: The definitive ProxyStatement for the 2006 Annual Meeting of Stockholders, whichwill be filed with the Securities and Exchange Commission within120 days after December 31, 2005, is incorporated byreference in Part III of thisForm 10-K.  

 
**TABLE OF CONTENTS**           **Page**     ** PART I**       Certain Definitions  3      Item 1.      Business  6       Item 1A.      Risk Factors  16      Item 1B.      Unresolved Staff Comments  23      Item 2.      Properties  23      Item 3.      Legal Proceedings  32      Item 4.      Submission of Matters to a Vote of Security    Holders  32  ** PART II**     Item 5.      Market for Registrant’s Common Equity,    Related Stockholder Matters and Issuer Purchases of Equity    Securities  32      Item 6.      Selected Financial Data  34      Item 7.      Management’s Discussion and Analysis    of Financial Condition and Results of Operations  34      Item 7A.      Quantitative and Qualitative Disclosures    About Market Risk  43      Item 8.      Financial Statements and Supplementary    Data  45      Item 9.      Change in and Disagreements With    Accountants on Accounting and Financial Disclosures  71      Item 9A.      Controls and Procedures  71      Item 9B.      Other Information  74  ** PART III**     Item 10.      Directors and Executive Officers of    Registrant  74      Item 11.      Executive Compensation  75      Item 12.      Security Ownership of Certain Beneficial    Owners and Management and Related Stockholder Matters  75      Item 13.      Certain Relationships and Related    Transactions  75      Item 14.      Principal Accountants Fees and Services  75  ** PART IV**     Item 15.      Exhibits, Financial Statement Schedules,    and Reports on Form 8-K  75      Signatures  77  Employment Agreement - Michael D. Watford Consent of Netherland, Sewell & Associates, Inc. Consent of Ryder Scott Company Consent of KPMG, LLP Certification of CEO and CFO pursuant to Rule 13a-14a Certification of CEO and CFO pursuant to Rule 13a-14a
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**Certain Definitions*****Terms used to describe quantities of oil and natural gas    and marketing*** • *Bbl* — One stock tank barrel, or 42    U.S. gallons liquid volume, of crude oil or other liquid    hydrocarbons.  • *Bcf* — One billion cubic feet of natural gas.  • *Bcfe* — One billion cubic feet of natural gas    equivalent.  • *BOE* — One barrel of oil equivalent, converting    natural gas to oil at the ratio of 6 Mcf of natural gas to    1 Bbl of oil.  • *BTU* — British Thermal Unit.  • *CFD* — Caofaedian — the Chinese    designation for the area in Bohai Bay area in the vicinity of    the 04/36 and 05/36 Blocks, offshore China.  • *Condensate* — An oil-like liquid produced in    association with natural gas production that condenses from    natural gas as it is produced and delivered into a separator or    similar equipment and collected in tanks at each well prior to    the delivery of such natural gas to the natural gas gathering    pipeline system.  • *ICP* — Indonesian Crude Price.  • *MBbl* — One thousand barrels.  • *Mcf* — One thousand cubic feet of natural gas.  • *Mcfe* — One thousand cubic feet of natural gas    equivalent, converting oil or condensate to natural gas at the    ratio of 1 Bbl of oil or condensate to 6 Mcf of    natural gas.  • *MMBbl* — One million barrels of oil or other    liquid hydrocarbons.  • *MMcf* — One million cubic feet of natural gas.  • *MBOE* — One thousand BOE.  • *MMBOE* — One million BOE.  • *MMBTU* — One million British Thermal Units.**     *****Terms used to describe the Company’s interests in    wells and acreage*** • *Gross oil and gas wells or acres* — The    Company’s gross wells or gross acres represent the total    number of wells or acres in which the Company owns a working    interest.  • *Net oil and gas wells or acres* — Determined by    multiplying “gross” oil and natural gas wells or acres    by the working interest that the Company owns in such wells or    acres represented by the underlying properties.***Terms used to assign a present value to the Company’s    reserves*** • *Standardized measure of discounted future net cash flows,    after income taxes* — The present value, discounted    at 10%, of the pre-tax future net cash flows attributable to    estimated net proved reserves. The Company calculates this    amount by assuming that it will sell the oil and gas production    attributable to the proved reserves estimated in its independent    engineer’s reserve report for the prices it received for    the production on the date of the report, unless it had a    contract to sell the production for a different price. The    Company also assumes that the cost to produce the reserves will    remain constant at the costs prevailing on the date of the    report. The assumed costs are subtracted from the assumed    revenues resulting in a stream of future net cash flows.    Estimated future income taxes, using rates in effect on the date    of the report, are deducted from the net cash flow stream. The    after-tax cash flows are discounted at 10% to result in the    standardized measure of the Company’s proved reserves.
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 • *Standardized measure of discounted future net cash flows    before income taxes* — The discounted present value    of proved reserves is identical to the standardized measure    described above, except that estimated future income taxes are    not deducted in calculating future net cash flows. The Company    discloses the discounted present value without deducting    estimated income taxes to provide what it believes is a better    basis for comparison of its reserves to the producers who may    have different tax rates.***Terms used to classify the Company’s reserve    quantities***     The Securities and Exchange Commission (“SEC”)definition of proved oil and gas reserves, perArticle 4-10(a)(2) ofRegulation S-X, isas follows:     *Proved oil and gas reserves.* Proved oil and gas reservesare the estimated quantities of crude oil, natural gas, andnatural gas liquids which geological and engineering datademonstrate with reasonable certainty to be recoverable infuture years from known reservoirs under existing economic andoperating conditions, i.e., prices and costs as of the date theestimate is made. Prices include consideration of changes inexisting prices provided only by contractual arrangements, butnot on escalations based upon future conditions.     (a) Reservoirs are considered proved if economicproducibility is supported by either actual production orconclusive formation test. The area of a reservoir consideredproved includes (1) that portion delineated by drilling anddefined by gas-oil and/or oil-water contacts, if any; and(2) the immediately adjoining portions not yet drilled, butwhich can be reasonably judged as economically productive on thebasis of available geological and engineering data. In theabsence of information on fluid contacts, the lowest knownstructural occurrence of hydrocarbons controls the lower provedlimit of the reservoir.     (b) Reserves which can be produced economically throughapplication of improved recovery techniques (such as fluidinjection) are included in the proved classification whensuccessful testing by a pilot project, or the operation of aninstalled program in the reservoir, provides support for theengineering analysis on which the project or program was based.     (c) Estimates of proved reserves do not include thefollowing: (1) oil that may become available from knownreservoirs but is classified separately as “indicatedadditional reserves”; (2) crude oil, natural gas, andnatural gas liquids, the recovery of which is subject toreasonable doubt because of uncertainty as to geology, reservoircharacteristics, or economic factors; (3) crude oil,natural gas, and natural gas liquids, that may occur inundrilled prospects; and (4) crude oil, natural gas, andnatural gas liquids, that may be recovered from oil shales,coal, gilsonite and other such sources. • *Proved developed reserves* — Proved reserves    that can be expected to be recovered through existing wells with    existing equipment and operating methods.  • *Proved undeveloped reserves* — Proved reserves    that are expected to be recovered from new wells on undrilled    acreage, or from existing wells where a relatively major    expenditure is required.***Terms used to describe the legal ownership of the    Company’s oil and gas properties*** • *Working interest* — A real property interest    entitling the owner to receive a specified percentage of the    proceeds of the sale of oil and natural gas production or a    percentage of the production, but requiring the owner of the    working interest to bear the cost to explore for, develop and    produce such oil and natural gas. A working interest owner who    owns a portion of the working interest may participate either as    operator or by voting his percentage interest to approve or    disapprove the appointment of an operator and drilling and other    major activities in connection with the development and    operation of a property.***Terms used to describe seismic operations*** • *Seismic data* — Oil and gas companies use    seismic data as their principal source of information to locate    oil and gas deposits, both to aid in exploration for new    deposits and to manage or enhance production from known    reservoirs. To gather seismic data, an energy source is used to    send sound
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     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.  • *3-D seismic    data* —    3-D seismic data is    collected using a grid of energy sources, which are generally    spread over several miles. A    3-D survey produces a    three dimensional image of the subsurface geology by collecting    seismic data along parallel lines and creating a cube of    information that can be divided into various planes, thus    improving visualization. Consequently,    3-D seismic data is a    more reliable indicator of potential oil and natural gas    reservoirs in the area evaluated.
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**PART I****Item 1.*****Business.***     Ultra Petroleum Corp. (“Ultra” or the“Company”) is an independent oil and gas companyengaged in the development, production, operation, explorationand acquisition of oil and gas properties. The Company wasincorporated on November 14, 1979, under the laws of theProvince of British Columbia, Canada. The Company continued intothe Yukon Territory, Canada under Section 190 of the*Business Corporations Act*(Yukon Territory) onMarch 1, 2000. The Company’s operations are focusedprimarily in the Green River Basin of southwest Wyoming andBohai Bay, offshore China. From time to time, the Companyevaluates other opportunities for the acquisition, explorationand development of oil and gas properties.     As of December 31, 2005, Ultra owns interests inapproximately 148,007 gross (78,688 net) acres inWyoming covering approximately 230 square miles. TheCompany owns working interests in approximately 330 grossproductive wells in this area and is operator of 53% of the330 gross wells. The Company’s current domesticoperations are focused on developing and expanding a tight gassand project located in the Green River Basin in southwestWyoming. In 2005, the Company’s Wyoming production wasapproximately 87.4% of the Company’s total oil and naturalgas production on an MCFE basis and 98.5% of the Company’sestimated net proved reserves were in Wyoming on an MCFE basis.In 2005, capital expenditures in Wyoming comprised approximately93% of the Company’s total capital expenditures.     Following the acquisition of Pendaries Petroleum Ltd.(“Pendaries”) on January 16, 2001, the Companybecame active in oil and gas exploration and developmentcovering the 04/36 Block and the 05/36 Block (jointly the“Blocks”) in Bohai Bay, China. The Company currentlyholds an 18.18% exploration interest in the 04/36 Block. Uponinitiation of development, the interest reduced to an 8.91%working interest in field development and production areas.Originally, the Company held a 15.00% exploration interest inthe 05/36 Block which reduced, upon initiation of development,to a 7.35% working interest for development and productionareas. In 2004, an extension of the 05/36 Block exploration termwas granted (from February 28, 2005 to February 28,2006). One of the parties to the contract elected not toparticipate in this extension of the exploration phase. TheCompany chose to acquire this available exploration interest. Asa result, the Company holds a 23.08% exploration interest in the05/36 Block, which will be reduced to 11.31% for areas that maybe developed in the current exploration acreage.     There are currently three fields (CFD 11-6, 12-1, 12-1S) underdevelopment (located in close proximity and thus developed undera single development plan) within the Blocks that have been“unitized” because the fields are located in both the04/36 and 05/36 Blocks. A Unitization Agreement was executedthat assigned the Company a 7.82% working interest in thecombined field unit. The Company’s interest in the unit wasbased upon the original 15.00% exploration interest in the 05/36Block and an 18.18% exploration interest of the 04/36 Block. OnJuly 19, 2004, oil production began from the CFD 11-1 and11-2 fields and on July 5, 2005, oil production began fromthe CFD 11-3 and 11-5 fields. All four fields are located in the04/36 Block. In 2005, the Company spent approximately 7% of itstotal 2005 capital budget on developing these China fields, aswell as on engineering work focused on development of additionalfields and continuing exploration. A wholly-owned subsidiary ofKerr-McGee Corporation is the operator of the Blocks. At thetime of the Pendaries acquisition, there were three oildiscoveries on the Blocks. Since then, six new discoveries havebeen made. Four of these oil fields are developed and onproduction and three additional fields are being developed.     The Company also owns interests in 26,868 gross(24,610 net) acres in Pennsylvania. The Company drilled1 gross (1.0 net) test well on this acreage during2005. This well has been completed and is waiting on a pipelineconnection. Evaluation is ongoing to determine plans for futureactivity in the area. In Texas, the Company owns a minornon-operated interest in 1 gross (0.12 net) producingwell, plus the associated 80 gross (14 net) acres. TheCompany is currently attempting to divest this property.     The Company’s annual report onForm 10-K,quarterly reports onForm 10-Q, andcurrent reports onForm 8-K, as wellas any amendments to such reports and all other filings we makepursuant to Section 13(a) or 15(d) of the SecuritiesExchange Act of 1934 are available free of charge to the publicon the Company’s website at www.ultrapetroleum.com. Toaccess the Company’s SEC filings, select“Financials” under the
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Investor Relations tab on the Company’s website. TheCompany’s SEC filings are available on its website as soonas they are posted to the EDGAR database on the SEC’swebsite.**Business Strategy*****Green River Basin, Wyoming***     The Company will continue the ongoing program to identify,develop and explore the acreage position now held in the tightgas sand trend in the Green River Basin. The majority of thewells in the 2006 drilling program will be targeting the sandsof the upper Cretaceous Lance Pool in the Pinedale and Jonahfields. The Lance Pool, as administered by the Wyoming Oil andGas Conservation Commission (“WOGCC”), includes sandsof both the Lance (found at subsurface depths of approximately8,000 to 12,000 feet) and Mesaverde (found at subsurfacedepths of approximately 12,000 to 14,000 feet) in thePinedale and Jonah fields area of Sublette County, Wyoming. TheCompany will continue to drill step-out and exploration wells onits Green River Basin acreage positions in an ongoingattempt to further define and expand the current known producingarea. In addition to the ongoing efforts in the Lance Poolsection, the Company is continuing to evaluate the deeper,potentially productive, zones found on its acreage block belowthe Lance Pool. All of the Company’s drilling activity isconducted utilizing its extensive integrated geological andgeophysical data set. This data set is being utilized to map thepotentially productive intervals, to identify areas for futureextension of the Lance fairway and to identify deeper objectiveswhich may warrant drilling.***Bohai Bay, China***     In 2006, the Company plans to continue producing oil at the CFD11-1, 11-2, 11-3 and 11-5 fields, continue development on theCFD 11-6, 12-1 and 12-1S unitized fields and drill additionalexploration wells. The Company has nine discovered oil fields inthe Bohai Blocks. The first two fields, CFD 11-1 and 11-2, beganproducing in July 2004, while the CFD 11-3 and 11-5 fields beganproducing in July 2005. Three additional fields are currentlybeing developed and are scheduled to go on production during thesecond half of 2006, bringing the total to seven producingfields by the end of 2006. Two discoveries remain in theappraisal stage.***Pennsylvania***     The Company will continue to evaluate the initial test wellincluding production testing to sales. The Company continues toacquire additional acreage, seismic and geologic data in thearea. Any decision as to future drilling on the prospect ispending production testing of the initial well and ongoinggeological, geophysical and engineering studies.**Marketing and Pricing**     The Company derives its revenues principally from the sale ofits natural gas and associated condensate production from wellsoperated by the Company and others in the Green River Basin insouthwest Wyoming. To a lesser extent, the Company derivesrevenues from the sale of its share of oil production from itsproducing fields in the Bohai Bay area, offshore China. TheCompany’s revenues are determined, to a large degree, byprevailing natural gas prices for production situated in theRocky Mountain Region of the United States; specifically,southwest Wyoming, as well as prevailing prices for crude oilproduced in the Bohai Bay region of China. Energy commodityprices in general, and the Company’s regional prices inparticular, have been highly volatile in the past, and such highlevels of volatility are expected to continue in the future. TheCompany cannot accurately predict or control the market pricesthat it receives for the sale of its natural gas, condensate, oroil production. However, the Company has, in the regular courseof its business, from time to time, hedged a portion of itsnatural gas production primarily through the use of fixed price,forward sales of physical gas, or through the limited use offinancial swaps with creditworthy financial counterparties. TheCompany may elect to hedge additional portions of its forecastnatural gas production in the future, in much the same manner asit has done previously. The Company has not, to date, hedged anyof its Chinese oil production; although, it may do so in thefuture. For a more detailed description of the Company’shedging activities, see Item 7A
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Quantitative and Qualitative Disclosures About Market Risk. TheCompany’s hedging policy limits amounts hedged to not morethan 50% of its forecast production without board approval. As aresult of its hedging activities, the Company may realize pricesthat are less than the spot prices that it would have received.***Natural Gas Marketing***     The Company currently sells all of its natural gas production toa diverse group of third-party, non-affiliated entities in aportfolio of transactions of various durations (daily, monthlyand longer term). The Company’s customers are situated inthe western United States — primarily California andthe Pacific Northwest, as well as the Front Range area ofColorado and in Utah. The sale of the Company’s natural gasis “as produced”, and the Company does not maintainany significant inventories or imbalances of natural gas. TheCompany maintains credit policies intended to mitigate the riskof uncollectible accounts receivable. The Company does not haveany outstanding, uncollectible accounts for natural gas sales.     During 2005, the Company negotiated several significant new oramended gathering and processing agreements with variousmidstream service providers that gather, compress and/or processnatural gas owned or controlled by the Company from itsproducing wells in the Pinedale Anticline and Jonah Fields insouthwest Wyoming. These agreements provide that the respectivemidstream service providers expand the capacities of theirfacilities in southwest Wyoming to accommodate growing volumesfrom wells in which the Company owns an interest. Most of theseagreements or amendments contain multi-year commitments formidstream services. In more than one instance, the Company wasable to substantially lower some of the fees that it pays forsuch midstream services, in exchange for committing to theselonger term arrangements. The capacity of the midstreaminfrastructure related to the Company’s productioncontinues to be adequate to allow it to sell essentially all ofits available production.     During 2005, the Company realized natural gas prices that werehigher than those historically seen in the southwest Wyomingregion. The market price for natural gas in the Rockiesgenerally, and in southwest Wyoming specifically, is influencedby a number of regional and national factors; all of which arebeyond the ability of the Company to control or to predict.These factors include weather, natural gas supplies, natural gasdemand, and pipeline export capacity. A hotter than normalsummer, plus the impact of two major hurricanes (Katrina andRita) on natural gas production from the Gulf of Mexico, causednatural gas prices in the Rocky Mountain Region, and otherparts of the country, to increase during the third and fourthquarters of 2005.     Because production exceeds local demand for natural gas, theRocky Mountain Region is usually a net-exporter of natural gas.Historically, natural gas production in southwest Wyoming hassold at a discount relative to other U.S. natural gasproduction sources or market areas. These regional pricingdifferentials or discounts are typically referred to as“basis” or “basis differentials”. TheCompany has seen significant basis differentials for its Wyomingproduction, versus the Henry Hub pricing reference point insouth Louisiana in the past. As a result, during that timeperiod, the Company realized prices that were significantlylower than those received by companies with production in otherregions of the U.S. Significant increases in pipelinecapacity to transport production from the Rockies productionareas to markets in the West in recent years have served toimprove (i.e. lower) basis differentials for Wyoming natural gasproduction. (Examples include: Kern River Pipeline —in service May 2003, and the Cheyenne PlainsPipeline — in service February 2005). These expansionsof pipeline export capacity have, in the past, reduced but noteliminated the basis differential for natural gas prices insouthwest Wyoming when compared to prices at the Henry Hubpricing reference point. There have been, from time to time,numerous other proposed pipeline projects that have beenannounced to transport Rockies and Wyoming natural gasproduction to markets.     During 2005, the Company took a major step toward assuring thatthe pipeline infrastructure to move the Company’s naturalgas supplies away from southwest Wyoming will be expanded toprovide sufficient capacity to transport its natural gasproduction and to provide for reasonable basis differentials forits natural gas in the future. The Company agreed to become ananchor shipper on the proposed Rockies Express Pipeline project,sponsored by subsidiaries of Kinder Morgan and Sempra Energy.The Rockies Express Pipeline, if built as proposed, would be thelargest natural gas transmission pipeline project of its typebuilt in the United States in
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more than 20 years, beginning at the Opal Processing Plantin southwest Wyoming and traversing Wyoming and several otherstates to an ultimate terminus in eastern Ohio. This project isprojected to cover more than 1,800 miles and iscontemplated to be a large-diameter (42”), high-pressurenatural gas pipeline. The Rockies Express Pipeline, if built,will be an interstate pipeline and would therefore be subject tothe jurisdiction of the United States Federal Energy RegulatoryCommission (“FERC”).     On December 19, 2005, the Company signed two PrecedentAgreements (“Precedent Agreements”) with RockiesExpress Pipeline, LLC and Entrega Gas Pipeline, LLC governinghow the parties will proceed through the design, regulatoryprocess and construction of the pipeline facilities and, subjectto certain conditions precedent, the Company will take firmtransportation service if and when the pipeline facilities areconstructed. Commencing upon completion of the pipelinefacilities, the Company’s commitment involves capacity of200,000 MMBtu per day of natural gas for a term of10 years, and the Company will be obligated to pay toRockies Express Pipeline, LLC certain demand charges related toits rights to hold this firm transportation capacity as ananchor shipper. Based on current assumptions, currentprojections regarding the cost of the expansion and theparticipation of other shippers in the expansion (notingspecifically that these assumptions are likely to changematerially), the Company currently projects that annual demandcharges due may be approximately $70 million per year forthe term of the contract, exclusive of fuel and surcharges. TheCompany’s Board of Directors approved the PrecedentAgreements on February 6, 2006 and Kinder Morgan, as themanaging member of the Rockies Express Pipeline, LLC advised theCompany of their final approval of the Precedent Agreements, andtheir intent to proceed with the construction of the RockiesExpress Pipeline on February 28, 2006. The pipelinefacilities are currently anticipated to be completed in stagesbetween 2007 and 2009. Although the Company is optimistic thatthe Rockies Express Pipeline project will receive the necessaryregulatory approvals and be constructed in a timely manner,there can be no assurances that the Rockies Express Pipelinewill be built, nor will there be any assurances that, if built,it will prevent large basis differentials from occurring in thefuture.***Oil Marketing***     Through its wholly-owned Sino-American Energy Corporationsubsidiary, the Company continued to market its share of oilproduction from the CFD 11-1 and 11-2 fields during 2005. Inaddition, the next two of its fields in Block 04/36 Bohai Bay,offshore China (CFD 11-3 and 11-5), began producing oil in July2005.     The sale of the Company’s Chinese oil production (“CFDcrude”) is done on a tanker/cargo lifting basis. As theCompany’s share of inventories on the CFD 11-1 and 11-2 and11-3 and 11-5 fields’ Floating Production Storage andOffloading Vessel (“FPSO”) become sufficient toschedule a lifting (typically 200,000 —300,000 barrels per cargo), the Company coordinates withthe operator and its markets to lift a cargo. By necessity, theCompany will, from time to time, carry inventories of crude oilto accommodate the lifting schedules for its share of oil fromthe FPSO. Each of the partners in the CFD 11-1/11-2 and11-3/11-5 fields are responsible for the disposition of theirrespective share of the CFD crude production. Kerr-McGee, asoperator of these fields, manages the lifting schedule forproduction from these fields. The Company has sold most of itsshare of the CFD crude production to an affiliate of its Chinesepartner, Chinese National Offshore Oil Corporation(“CNOOC”) China, Ltd., at prices that reflect a slightdiscount to the Indonesian Crude Price (“ICP”) Durimonthly average price. In 2005, for the first time, the Companysold some of its share of the CFD crude production outside ofChina, and it continues to assess its opportunities to marketits share of the CFD crude production to other markets such asKorea, Japan and Singapore. The Company does not have anyoutstanding, uncollectible accounts for CFD crude oil sales asof December 31, 2005.     Currently, the CFD crude is a heavy, sweet crude oil, with anAPI gravity of approximately 19 degrees. The production fromthese first four fields is from multiple productive reservoirs,which have variability in the quality of oil. The Companybelieves that the quality of the oil produced from these fieldswill tend to improve as additional wells and reservoirs arecompleted and placed into production. Due to its quality andphysical characteristics, refiners and other markets for the CFDcrude oil typically expect to be able to purchase CFD crude atprices that are lower than light sweet crude oils like WestTexas Intermediate or Brent. Oil produced and sold from the fourCFD fields is typically priced based upon the monthly officialICP for Duri field crude. The Duri crude, produced in Indonesia,is of similar quality to the CFD crude produced in the Bohai Bayarea.
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The official ICP Duri price is a monthly weighted average ofthree, independent daily assessments of the price of Duri crude,reported by Platt’s Asian Petroleum Price Index publishedby Seapac Services Limited, and RIM Intelligence Co. To themonthly official ICP Duri marker price, a premium or discount isadded to reflect transportation and quality differentials forthe CFD crude relative to the Duri marker crude. The premium ordiscount for the CFD crude (relative to the Duri price) isnegotiated monthly between the Company and its partners,including CNOOC.**Environmental Matters**     In 1998, the U.S. Bureau of Land Management(“BLM”) initiated a requirement for an EnvironmentalImpact Statement (“EIS”) for the Pinedale Anticlinearea in the Green River Basin. An EIS evaluates the effects thatan industry’s activities will have on the environment inwhich the activity is proposed. This EIS encompasses the areanorth of the Jonah Field, including the Pinedale Anticline,which is where most of the Company’s exploration anddevelopment is taking place. This environmental study includedan analysis of the geological and reservoir characteristics ofthe area plus the necessary environmental studies related towildlife, surface use, socio-economic and air quality issues. OnJuly 27, 2000, the BLM issued its Record of Decision(“ROD”) with respect to the final EIS. The ROD/ EISallows for the drilling of 700 producing surface locationswithin the area covered by the EIS, but does not authorize thedrilling of particular wells. Ultra must submit applications tothe BLM’s Pinedale field manager for permits to drill andfor other required authorizations, such asrights-of-way forpipelines, for each specific well or pipeline location.Development activities in the Pinedale Anticline area, as on allfederal leaseholds, remain subject to regulatory agencyapproval. In making its determination on whether to approvespecific drilling or development activities, the BLM applies therequirements outlined in the ROD/ EIS.     The ROD/ EIS imposes limitations and restrictions on activitiesin the Pinedale Anticline area, including limits on winterdrilling and completion activity, and proposes mitigationguidelines, standard practices for industry activities and bestmanagement practices for sensitive areas. The ROD/ EIS alsoprovides for annual reviews to compare actual environmentalimpacts to the environmental impacts projected in the EIS andprovides for adjustments to mitigate such impacts, if necessary.The review team is comprised of operators, local residents andother affected persons. The Company cannot predict if or howthese changes may affect permitting, development and complianceunder the ROD/EIS. The BLM’s field manager may also imposeadditional limitations and mitigation measures as are deemedreasonably necessary to mitigate the impact of drilling andproduction operations in the area.     As of December 31, 2005, the Company had approximately46 well locations with respect to which both the BLM andthe WOGCC have approved permits to drill on Company-operatedfederal leases in the Pinedale Anticline and Jonah field areas.     To date, the Company has expended significant resources in orderto satisfy applicable environmental laws and regulations in thePinedale Anticline area and other areas of operation under thejurisdiction of the BLM. The Company’s future costs ofcomplying with these regulations may continue to be substantial.Further, any additional limitations and mitigation measurescould further increase production costs, delay exploration,development and production activities and curtail exploration,development and production activities altogether.     The Company also co-owns leases on state and privately ownedlands in the vicinity of the Pinedale Anticline that do not fallunder the jurisdiction of the BLM and are not subject to the EISrequirement.     In August 1999, the BLM required an Environmental Assessment(“EA”) for the potential increased density drilling inthe Jonah Field area. An EA is a more limited environmentalstudy than is conducted under an EIS. The EA was required toaddress the potential environmental impacts of developing thefield on a well density of two wells per 80 acre drillingand spacing unit as opposed to the one well per 80 acredrilling and spacing unit as was approved in the initial JonahField EIS approved in 1998. The new EA was completed in June2000. With the approval of this EA and the earlier approval bythe WOGCC for drilling of two wells per 80 acredrilling and spacing unit, the Company was permitted to drillinfill wells at this well density on the 2,160 gross(1,322 net) acres then owned by the Company in the JonahField. Prior to these approvals, the
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Company had drilled 21 gross (7.7 net) wells in thefield. Since the increased density approvals, the Company hasdrilled an additional 22 gross (14.0 net) wells in thefield. All 43 wells drilled by the Company in the JonahField have been productive. Since this time various otheroperators have received approval for the drilling of increaseddensity wells in pilot areas at well densities ranging from fourwells per 80 acre drilling and spacing unit to sixteenwells per drilling and spacing unit. Results of all of thesepilot projects were utilized in acquiring approval from theWOGCC in November 2004 to increase the overall density ofdevelopment for the Jonah Field to eight wells per 80 acredrilling and spacing unit. The BLM is currently conducting a newEIS covering the Jonah Field to assess the impacts of thisincreased density development and define the parameters underwhich this increased density development will be allowed toproceed. The draft EIS was made available mid-February 2005.After review and comment by all parties the BLM is now preparingthe final ROD. It is expected that the ROD for the new Jonah EISshould be issued during the first half of 2006.     During 2003, 2004 and 2005, Ultra and other operators in thePinedale Field received approval from the WOGCC to drillincreased density pilot project wells in several areas of thePinedale Field. These pilot projects are designed to test thefeasibility of developing this field in well densities greaterthan the currently approved one well per 40 acres. Theresults of some of this work led to the WOGCC in July 2004approving the development of the northern portion of theanticline on a two wells per 40 acre density. The acreageis operated by Questar Exploration and Production Company(“Questar”), a working interest partner of theCompany, and the Company owns a working interest in the majorityof this acreage. This approval covers approximately14,432 gross acres. Since this time, additional increaseddensity pilot wells have been drilled by Ultra and others on thepilot areas within the Pinedale field. Based on the datagathered through these pilot projects, the WOGCC approvedseveral additional Increased Density applications during 2005.In August 2005, approval was granted for development of asignificant portion of the northern portion of the Pinedalefield for drilling on a four wells per 40 acre density.This approval covers approximately 11,256 gross acres inwhich Ultra owns an interest and are operated by Questar. InNovember 2005, approval was granted for development of asignificant portion of the central Pinedale Field andsurrounding area on a two wells per 40 acre density.This approval covers approximately 23,816 gross acres inwhich Ultra owns an interest. Ultra operates the majority of theacreage covered by this approval. Further drilling within theseareas and the other pilot areas approved for increased densitycontinues and the results of these are being evaluated todetermine the appropriate course of action as to the overalldevelopment strategy for the Pinedale Field.     In April 2004, Questar asked the BLM to modify winter-accessrestrictions to specifically allow them to operate on threeactive pads with two drilling rigs per pad. This requestrequired an EA to weigh the negative impacts of winter activityrelative to the extensive mitigation measures proposed byQuestar. On November 9, 2004 they received approval in theform of a “Finding of No Significant Impact”(“FONSI”) from the BLM to phase in over the next yeartheir proposed year-round drilling program which allowed twodrilling rigs on one pad during the winter of 2004-2005. Questarproposed mitigation measures including construction of a waterand condensate gathering system during the summer of 2005.Questar’s proposal allows them to operate six rigs fromthree active pads beginning in the winter of 2005-2006 throughthe winter of 2013-2014 once they have completed implementationof the proposed mitigation measures.     The BLM approved the Questar proposal after consideringextensive input from the participating agencies received duringthe public comment process. Key components of the approval are:1) One pad with two drilling rigs during the winter of2004-2005; 2) three pads with two drilling rigs per pad inthe winter of 2005-2006 and thereafter through the winter of2013/2014; 3) activities during the May-November periodwill continue to be governed by the original Pinedale AnticlineEIS; 4) directional drilling with up to 16 wells perpad resulting in only one-third of the drilling phase surfacedisturbance contemplated under the original EIS;5) construction of a produced water and condensategathering system in 2005; 6) funding for continuedmonitoring of mule deer and other critical wildlife for theduration of development activity; 7) use offlareless-completion technology to reduce noise, air and visualpollution during well-completion operations; 8) funding forair-quality monitoring; and 9) wildlife habitat enhancementas well as other monitoring and mitigation measures described inthe BLM decision record.     Questar has met their commitments under the terms of thisapproval and is now proceeding with the winter drilling programas proposed. Currently there are six Questar operated drillingrigs operating within the
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area of this approval, two rigs on each of three separate winterpads. These wells will be drilled to total depth, logged andcased during the winter restriction period with completionactivity to commence in the spring with the lifting of thenormal seasonal wildlife restrictions.     In early 2005, Ultra, along with Anschutz and Shell(“Proponents”) proposed to the BLM a winter accessdemonstration project for the Mesa area of the Pinedale Field.This area is normally subject to the winter big game stipulationwhich prohibits drilling and completion activities in the areafromNovember 15th untilApril 30th.Under the terms of the proposal, the Proponents would be able tooperate a total of six rigs, two each on three different winterpads. During this winter demonstration project, the Proponentsplan to employ innovative technologies and practices foroperations to provide a more beneficial alternative to thecurrent wildlife restrictions. Upon successful completion of thewinter demonstration project, the Proponents intend to apply theoperations principles demonstrated to implement a long-termdevelopment plan that will result in substantially less impactto wildlife, habitat, and local communities than what is allowedunder the current Pinedale Anticline Project Area(“PAPA”) ROD while providing assurance of year roundaccess from the BLM to permit the implementation of acomprehensive development scenario for the Pinedale Field. An EAwas conducted by the BLM to evaluate the winter demonstrationproject proposal and associated impacts and the Proponentsreceived approval in the form of a FONSI ruling from the BLM inSeptember 2005. The proponents began activities in the winterdemonstration project in November 2005 and are currently runningthe six rigs as proposed. The FONSI ruling includes severalconditions of approval requiring monitoring and mitigation ofimpacts on wildlife and monitoring and mitigation of rig engineemissions and noise levels associated with project drillingactivities.     Subsequent to the FONSI ruling allowing implementation of thewinter demonstration project, the Proponents submitted adevelopment proposal for the Pinedale Field which includes broadapplication of operations principles being evaluated in thedemonstration project area. The Proponents have now entered intoa Memorandum of Understanding with the BLM to commence thepreparation of a Supplemental Environmental Impact Statement(“SEIS”) for year-round access in the Pinedale field.     The SEIS process is proceeding and impacts of the developmentproposal will be analyzed to assess alternative considerationsand mitigation requirements that should be considered asalternatives to those included in the proposal or in addition tothose measures now proposed. The proposed action includescommitments to reduce surface disturbance by utilizing feweroverall pads and drilling more directional wells than called forin the PAPA ROD. Also, if approved, the Proponents proposalcommits to reduced air emissions. The Proponents have proposedto apply technology to drilling rig engines to reduce emissions,to reduce vehicle traffic by installing a liquids gatheringsystem as appropriate in the field, and by expanding the use oftelemetry to reduce production operations traffic requirements.The Proponents have also proposed additional monitoring toassess benefits of mitigation activities on the impacts ofdevelopment activities on the wildlife in the project area. Theproposal commits to offsite mitigation measures should themonitoring indicate it is warranted. If approved, theProponents’ proposal commits to reduced reserve pit use andto accelerated surface reclamation. The SEIS process calls for aROD in late 2006.     In September 2002, the Company received the “Oil and GasWildlife Stewardship” award from the Wyoming Game and FishDepartment in recognition of its contribution to wildlifemanagement in the Pinedale area. During 2001, the Companyreceived the “Agency/ Corporation of the Year” awardfrom the Wyoming Wildlife Federation and the “RegionalAdministrator’s Award for Environmental Achievement”from the U.S. Environmental Protection Agency.**Regulation*****Oil and Gas Regulation***     The availability of a ready market for oil and gas productiondepends upon numerous factors beyond the Company’s control.These factors may include state and federal regulation of oiland gas production and transportation, as well as regulationsgoverning environmental quality and pollution control, statelimits on allowable rates of production by a well or prorationunit, the amount of oil and gas available for sale, theavailability of adequate pipeline and other transportation andprocessing facilities and the marketing of
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competitive fuels. For example, a productive natural gas wellmay be “shut-in” because of a lack of an availablenatural gas pipeline in the areas in which the Company mayconduct operations. State and federal regulations are generallyintended to prevent waste of oil and gas, protect rights toproduce oil and gas between owners in a common reservoir,control the amount of oil and gas produced by assigningallowable rates of production and control contamination of theenvironment. Pipelines and natural gas plants are also subjectto the jurisdiction of various federal, state and local agencies.     The Company’s sales of natural gas are affected by theavailability, terms and costs of transportation both in thegathering systems that transport from the wellhead to theinterstate pipelines and in the interstate pipelines themselves.The rates, terms and conditions applicable to the interstatetransportation of natural gas by pipelines are regulated by theFERC under the Natural Gas Act, as well as underSection 311 of the Natural Gas Policy Act. Since 1985, theFERC has implemented regulations intended to increasecompetition within the natural gas industry by making naturalgas transportation more accessible to natural gas buyers andsellers on an open-access, non-discriminatory basis. OnFebruary 25, 2000, the FERC issued a statement of policyand a final rule concerning alternatives to its traditionalcost-of-servicerate-making methodology to establish the rates interstatepipelines may charge for services. The final rule revises theFERC’s pricing policy and current regulatory framework toimprove the efficiency of the market and further enhancecompetition in natural gas markets. The FERC is also consideringa number of regulatory initiatives that could affect the termsand costs of interstate transportation of natural gas byinterstate pipelines on behalf of natural gas shippers,including policy inquiries about natural gas quality andinterchangeability, selective discounting of transportationservices by pipelines to shippers, and proposed rules governingpipeline creditworthiness and collateral standards. Becausethese regulatory initiatives have not been made final, theapproach the FERC will take and the potential impact on naturalgas suppliers are not clear.     The Company’s sales of oil are also affected by theavailability, terms and costs of transportation. The rates,terms, and conditions applicable to the interstatetransportation of oil by pipelines are regulated by the FERCunder the Interstate Commerce Act. The FERC has implemented asimplified and generally applicable ratemaking methodology forinterstate oil pipelines to fulfill the requirements ofTitle XVIII of the Energy Policy Act of 1992 comprised ofan indexing system to establish ceilings on interstate oilpipeline rates.     In the event the Company conducts operations on federal, tribalor state lands, such operations must comply with numerousregulatory restrictions, including various operationalrequirements and restrictions, nondiscrimination statutes androyalty and related valuation requirements. In addition, certainof such operations must be conducted pursuant to certainon-site securityregulations, bonding requirements and applicable permits issuedby the BLM or Minerals Management Service, Bureau of IndianAffairs, tribal or other applicable federal, state and/or IndianTribal agencies.     The Mineral Leasing Act of 1920 (“Mineral Act”)prohibits direct or indirect ownership of any interest infederal onshore oil and gas leases by a foreign citizen of acountry that denies “similar or like privileges” tocitizens of the United States. Such restrictions on citizens ofa non-reciprocal country include ownership or holding orcontrolling stock in a corporation that holds a federal onshoreoil and gas lease. If this restriction is violated, thecorporation’s lease can be canceled in a proceedinginstituted by the United States Attorney General. Althoughthe 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 Companyowns interests in numerous federal onshore oil and gas leases.It is possible that holders of the Company’s equityinterests may be citizens of foreign countries, which at sometime in the future might be determined to be non-reciprocalunder the Mineral Act.     See *“Risk Factors”*for a discussion of therisks involved in our international operations.***Environmental Regulations***     *General.* The Company’s activities in the UnitedStates are subject to existing federal, state and local laws andregulations governing environmental quality, oil spills andpollution control and its activities in China are subject to thelaws and regulations of China. It is anticipated that, absentthe occurrence of an extraordinary event, compliance withexisting federal, state and local laws, rules and regulationsgoverning the
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release of materials in the environment or otherwise relating tothe protection of the environment will not have a materialeffect upon the Company’s operations, capital expenditures,earnings or competitive position.     The Company’s activities with respect to exploration,drilling and production from wells and natural gas facilities,including the operation and construction of pipelines, plantsand other facilities for transporting, processing, treating orstoring oil, natural gas and other products, are subject tostringent environmental regulation by state and federalauthorities, including the Environmental Protection Agency(“EPA”). Such regulation can increase the cost ofplanning, designing, installing and operating such facilities.In most instances, the regulatory requirements relate to waterand air pollution control measures.     *Solid and Hazardous Waste.* The Company currently owns orleases, and has in the past owned or leased, numerous propertiesthat have been used for the exploration and production of oiland gas for many years. Although the Company utilized operatingand disposal practices that were standard in the industry at thetime, hydrocarbons or other solid wastes may have been disposedof or released on or under the properties that the Companycurrently owns or leases or properties that the Company hasowned or leased or on or under locations where such wastes havebeen taken for disposal. In addition, many of these propertieshave been operated by third parties over whom the Company had nocontrol as to such entities’ treatment of hydrocarbons orother wastes or the manner in which such substances may havebeen disposed of or released. State and federal laws applicableto oil and gas wastes and properties have gradually becomestricter over time. Under new laws, the Company could berequired to remediate property, including ground water,containing or impacted by previously disposed wastes (includingwastes disposed of or released by prior owners or operators) orto perform remedial plugging operations to prevent future, ormitigate existing, contamination.     The Company may generate wastes, including hazardous wastes thatare subject to the federal Resource Conservation and RecoveryAct (“RCRA”) and comparable state statutes. The EPAand various state agencies have limited the disposal options forcertain wastes, including wastes designated as hazardous underthe RCRA and state analogs (“Hazardous Wastes”) and isconsidering the adoption of stricter disposal standards fornon-hazardous wastes. Furthermore, certain wastes generated bythe Company’s oil and gas operations that are currentlyexempt from treatment as Hazardous Wastes may in the future bedesignated as Hazardous Wastes under the RCRA or otherapplicable statutes, and therefore be subject to more rigorousand costly operating and disposal requirements.     *Superfund.* The federal Comprehensive EnvironmentalResponse, Compensation and Liability Act (“CERCLA”),also known as the “Superfund” law, generally imposesjoint and several liability for costs of investigation andremediation and for natural resource damages, without regard tofault or the legality of the original conduct, on certainclasses of persons with respect to the release into theenvironment of substances designated under CERCLA as hazardoussubstances (“Hazardous Substances”). These classes ofpersons, or so-called potentially responsible parties(“PRP”), include current and certain past owners andoperators of a facility where there has been a release or threatof release of a Hazardous Substance and persons who disposed ofor arranged for the disposal of the Hazardous Substances foundat such a facility. CERCLA also authorizes the EPA and, in somecases, third parties to take actions in response to threats tothe public health or the environment and to seek to recover fromthe PRP the costs of such action. Although CERCLA generallyexempts “petroleum” from the definition of HazardousSubstance, in the course of its operations, the Company hasgenerated and will generate wastes that fall withinCERCLA’s definition of Hazardous Substances. The Companymay also be an owner or operator of facilities on whichHazardous Substances have been released. The Company may beresponsible under CERCLA for all or part of the costs to cleanup facilities at which such substances have been released andfor natural resource damages. To its knowledge, the Company hasnot been named a PRP under CERCLA nor have any prior owners oroperators of its properties been named as PRP’s related totheir ownership or operation of such property.     *National Environmental Policy Act.* The federal NationalEnvironmental Policy Act provides that, for those federalactions that are major federal actions significantly affectingthe quality of the human environment, the federal agency takingsuch action must follow certain steps in evaluating theenvironmental impacts of the federal action. This evaluationgenerally takes the form of an EIS. In the EIS, the agency isrequired to evaluate alternatives to the proposed action and theenvironmental impacts of the alternatives.
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Actions such as drilling on federal lands, to the extent thedrilling requires federal approval, likely trigger therequirements of the National Environmental Policy Act, with fewexceptions. Certain of the Company’s activities may triggerthese requirements. The requirements of the NationalEnvironmental Policy Act may result in increased costs,significant delays and the imposition of restrictions orobligations, including the restriction or prohibition ofdrilling, upon the Company’s activities.     *Oil Pollution Act.* The Oil Pollution Act of 1990(“OPA”), which amends and augments oil spillprovisions of the Clean Water Act (“CWA”), imposescertain duties and liabilities on certain “responsibleparties” related to the prevention of oil spills anddamages resulting from such spills in or threateningUnited States waters or adjoining shorelines. A liable“responsible party” includes the owner or operator ofa facility, vessel or pipeline that is a source of an oildischarge or that poses the substantial threat of discharge or,in the case of offshore facilities, the lessee or permittee ofthe area in which a discharging facility is located. The OPAassigns joint and several liability, without regard to fault, toeach liable party for oil removal costs and a variety of publicand private damages. Although defenses and limitations exist tothe liability imposed by OPA, they are limited. In the event ofan oil discharge or substantial threat of discharge, we may beliable for costs and damages.     *Air Emissions.* The Company’s operations are subjectto local, state and federal regulations for the control ofemissions from sources of air pollution. Federal and state lawsrequire new and modified sources of air pollutants to obtainpermits prior to commencing construction. Major sources of airpollutants are subject to more stringent, federally imposedrequirements including additional permits. Federal and statelaws designed to control hazardous (toxic) air pollutants,might require installation of additional controls.Administrative enforcement actions for failure to complystrictly with air pollution regulations or permits are generallyresolved by payment of monetary fines and correction of anyidentified deficiencies. Alternatively, regulatory agenciescould bring lawsuits for civil penalties or require the Companyto forego construction, modification or operation of certain airemission sources.     *Clean Water Act.* The CWA imposes restrictions and strictcontrols regarding the discharge of wastes, including producedwaters and other oil and natural gas wastes, into waters of theUnited States, a term broadly defined. These controls havebecome more stringent over the years, and it is probable thatadditional restrictions will be imposed in the future. Permitsmust be obtained to discharge pollutants into federal waters.The CWA provides for civil, criminal and administrativepenalties for unauthorized discharges of pollutants and of oiland hazardous substances. It imposes substantial potentialliability for the costs of removal or remediation associatedwith discharges of oil or hazardous substances. State lawsgoverning discharges to water also provide varying civil,criminal and administrative penalties and impose liabilities inthe case of a discharge of petroleum or its derivatives, orother hazardous substances, into state waters. In addition, theEPA has promulgated regulations that may require the Company toobtain permits to discharge storm water runoff, includingdischarges associated with construction activities. In the eventof an unauthorized discharge of wastes, the Company may beliable for penalties and costs.     *Endangered Species Act.* The Endangered Species Act(“ESA”) was established to provide a means to conservethe ecosystems upon which endangered and threatened speciesdepend, to provide a program for conservation of theseendangered and threatened species, and to take the appropriatesteps that are necessary to bring any endangered or threatenedspecies to the point where measures provided for in the ESA areno longer necessary. The Company conducts operations on federaloil and gas leases that have species, such as sage grouse orother sensitive species, that potentially could be listed asthreatened or endangered under the ESA. If a species is listedas threatened or endangered, the U.S. Fish and WildlifeService must also designate the species’ critical habitatand suitable habitat as part of the effort to ensure survival ofthe species. A critical habitat or suitable habitat designationcould result in further material restrictions to federal landuse and may materially delay or prohibit land access for oil andgas development. If the Company were to have a portion of itsleases designated as critical or suitable habitat, it mayadversely impact the value of the affected leases.     *OSHA and other Regulations.* The Company is subject to therequirements of the federal Occupational Safety and Health Act(“OSHA”) and comparable state statutes. The OSHAhazard communication standard, the EPA communityright-to-knowregulations under Title III of CERCLA and similar state
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statutes require us to organize and/or disclose informationabout hazardous materials used or produced in its operations.     The Company believes that it is in substantial compliance withcurrent applicable environmental laws and regulations and thatcontinued compliance with existing requirements will not have amaterial adverse impact on the Company.**Employees**     As of December 31, 2005, the Company had 57 full timeemployees, including officers.**Item 1A.     *****Risk Factors.******There are inherent limitations in all control systems, and    misstatements due to error or fraud that could seriously harm    our business may occur and not be detected.***     Our management, including our Chief Executive Officer and ChiefFinancial Officer, does not expect that our internal controlsand disclosure controls will prevent all possible error and allfraud. A control system, no matter how well conceived andoperated, can provide only reasonable, not absolute, assurancethat the objectives of the control system are met. In addition,the design of a control system must reflect the fact that thereare resource constraints and the benefit of controls must berelative to their costs. Because of the inherent limitations inall control systems, no evaluation of controls can provideabsolute assurance that all control issues and instances offraud, if any, in our Company have been detected. These inherentlimitations include the realities that judgments indecision-making can be faulty and that breakdowns can occurbecause of simple error or mistake. Further, controls can becircumvented by the individual acts of some persons or bycollusion of two or more persons. The design of any system ofcontrols is based in part upon certain assumptions about thelikelihood of future events, and there can be no assurance thatany design will succeed in achieving its stated goals under allpotential future conditions. Over time, a control may beinadequate because of changes in conditions or the degree ofcompliance with the policies or procedures may deteriorate.Because of inherent limitations in a cost-effective controlsystem, misstatements due to error or fraud may occur and not bedetected. A failure of our controls and procedures to detecterror or fraud could seriously harm our business and results ofoperations.***Our reserve information represents estimates that may turn    out to be incorrect if the assumptions upon which these    estimates are based are inaccurate. Any material inaccuracies in    these reserve estimates or underlying assumptions will    materially affect the quantities and present value of our    reserves.***     There are numerous uncertainties inherent in estimatingquantities of proved reserves and projected future rates ofproduction and timing of development expenditures, includingmany factors beyond the control of the Company. The reserve dataand standardized measures set forth herein represent onlyestimates. Reserve engineering is a subjective process ofestimating underground accumulations of oil and gas that cannotbe measured in an exact way and the accuracy of any reserveestimate is a function of the quality of available data and ofengineering and geological interpretation and judgment. As aresult, estimates of different engineers often vary. Inaddition, results of drilling, testing and production subsequentto the date of an estimate may justify revision of suchestimates. Accordingly, reserve estimates are often differentfrom the quantities of oil and gas that are ultimatelyrecovered. Further, the estimated future net revenues fromproved reserves and the present value thereof are based uponcertain assumptions, including geologic success, prices, futureproduction levels and costs that may not prove correct overtime. Predictions of future production levels are subject togreat uncertainty, and the meaningfulness of such estimates ishighly dependent upon the accuracy of the assumptions upon whichthey are based. Historically, oil and gas prices have fluctuatedwidely.***Competitive industry conditions may negatively affect our    ability to conduct operations.***     The Company competes with numerous other companies in virtuallyall facets of its business. The competitors in development,exploration, acquisitions and production include majorintegrated oil and gas companies as well as numerousindependents, including many that have significantly greaterresources.
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Therefore, competitors may be able to pay more for desirableleases and evaluate, bid for and purchase a greater number ofproperties or prospects than the financial or personnelresources of the Company permit. The ability of the Company toincrease reserves in the future will be dependent on its abilityto select and acquire suitable prospects for future explorationand development.     Factors that affect our ability to compete in the marketplaceinclude: •     our access to the capital necessary to drill wells and acquire    properties;  •     our ability to acquire and analyze seismic, geological and other    information relating to a property;  •     our ability to retain the personnel necessary to properly    evaluate seismic and other information relating to a    property; and  •     the location of, and our ability to access platforms, pipelines    and other facilities used to produce and transport oil and gas    production;***Factors beyond our control affect our ability to market    production and our financial results.***     The ability to market oil and natural gas depends on numerousfactors beyond the Company’s control. These factors include: •     the extent of domestic production and imports of oil and natural    gas;  •     the availability of pipeline capacity;  •     the effects of inclement weather;  •     the demand for oil and natural gas by utilities and other end    users;  •     the availability of alternative fuel sources;  •     the proximity of natural gas production to natural gas pipelines;  •     state and federal regulations of oil and natural gas    marketing; and  •     federal regulation of natural gas sold or transported in    interstate commerce.     Because of these factors, the Company may be unable to marketall of the oil and natural gas that it produces, including oiland natural gas that may be produced from the Bohai Bayproperties in China. In addition, the Company may be unable toobtain favorable prices for the oil and natural gas it produces.***We may experience a temporary decline in revenues if we    lose one of our significant customers.***     In 2005, the Company had three significant customers, CNOOC,Occidental Energy Marketing, Inc. and Sempra Energy Trading,that individually accounted for 10% or more of theCompany’s total natural gas and oil sales. To the extentthese or any other significant customer reduces the volume ofits oil or gas purchases from us, we could experience atemporary interruption in sales of, or a lower price for, ouroil and natural gas.***A decrease in oil and gas prices may adversely affect our    results of operations and financial condition.***     The Company’s revenues are determined, to a large degree,by prevailing natural gas prices for production situated in theRocky Mountain Region of the United States, specifically,southwest Wyoming, as well as prevailing prices for crude oilproduced in the Bohai Bay region of China. Energy commodityprices in general, and the Company’s regional prices inparticular, have been highly volatile in the past, and such highlevels of volatility are expected to continue in the future. TheCompany cannot accurately predict or control the market pricesthat it receives for the sale of its natural gas, condensate, oroil production.     Prices for oil and gas are subject to large fluctuations inresponse to relatively minor changes in the supply of and demandfor oil and gas, market uncertainty and a variety of additionalfactors beyond the Company’s control. These factors includebut are not limited to weather conditions in the United States,the condition of the United States economy, the actions of theOrganization of Petroleum Exporting Countries, governmental
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regulation, political stability in the Middle East andelsewhere, the foreign supply of oil and gas, the price offoreign oil and gas imports and the availability of alternatefuel sources and transportation interruption. Any substantialand extended decline in the price of oil or gas could have anadverse effect on the carrying value of the Company’sproved reserves, borrowing capacity, the Company’s abilityto obtain additional capital, and the Company’s revenues,profitability and cash flows from operations.     Volatile oil and gas prices make it difficult to estimate thevalue of producing properties for acquisition and divestitureand often cause disruption in the market for oil and gasproducing properties, as buyers and sellers have difficultyagreeing on such value. Price volatility also makes it difficultto budget for and project the return on acquisitions anddevelopment and exploitation projects.***A price decrease may more adversely affect the price    received for the Company’s Wyoming production than    production in other U.S. regions.***     The price of natural gas in the southwest Wyoming region iscritical to the Company’s business. The market price forthis natural gas differs from the market indices for natural gasin the Gulf Coast region of the United States due potentially toinsufficient pipeline capacity and/or low demand in the summermonths for natural gas in the Rocky Mountain region of theUnited States. Therefore, a price decrease may more adverselyaffect the price received for the Company’s Wyomingproduction than production in the other U.S. regions. Therehave been, from time to time, numerous proposed pipelineprojects, including the Rockies Express Pipeline, that have beenannounced to transport Rockies’ and Wyoming natural gasproduction to markets. There can be no assurance that suchinfrastructure will be built or that if built, it will preventlarge basis differentials from occurring in the future.***Compliance with environmental and other government    regulations could be costly and could negatively impact    production.***     The Company’s operations are subject to numerous laws andregulations governing the discharge of materials into theenvironment or otherwise relating to environmental protection.These laws and regulations may: •     require that the Company acquire permits before commencing    drilling;  •     restrict the substances that can be released into the    environment in connection with drilling and production    activities;  •     limit or prohibit drilling activities on protected areas such as    wetlands or wilderness areas;  •     require remedial measures to mitigate pollution from former    operations, such as plugging abandoned wells; and  •     require governmental approval of the overall development plan    prior to the start of development of fields in China.     Under these laws and regulations, the Company could be liablefor personal injury andclean-up costs andother environmental and property damages, as well asadministrative, civil and criminal penalties. The Companymaintains limited insurance coverage for sudden and accidentalenvironmental damages, but does not maintain insurance coveragefor the full potential liability that could be caused by suddenand accidental environmental damages. Accordingly, the Companymay be subject to liability or may be required to ceaseproduction from properties in the event of environmental damages.     A significant percentage of the Company’s United Statesoperations are conducted on federal lands. These operations aresubject to a variety ofon-site securityregulations as well as other permits and authorizations issuedby the BLM, the Wyoming Department of Environmental Quality andother agencies. A portion of the Company’s acreage isaffected by winter lease stipulations that prohibit exploration,drilling and completing activities generally fromNovember 15th toApril 30th,but allow production activities all year round. To drill wellsin Wyoming, the Company is required to file an Application forPermit to Drill with the WOGCC. Drilling on acreage controlledby the federal government requires the filing of a similarapplication
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with the BLM. These permitting requirements may adversely affectthe Company’s ability to complete its drilling program atthe cost and in the time period currently anticipated. Onlarge-scale projects, lessees may be required to perform an EISto assess the environmental impact of potential development,which can delay project implementation and/or result in theimposition of environmental restrictions that could have amaterial impact on cost or scope.***We may not be able to replace our reserves or generate    cash flows if we are unable to raise capital. We will be    required to make substantial capital expenditures to develop our    existing reserves and to discover new oil and gas    reserves.***     The Company’s ability to continue exploration anddevelopment of its properties and to replace reserves may bedependent upon its ability to continue to raise significantadditional financing, including debt financing that may besignificant, or obtain some other arrangements with industrypartners in lieu of raising financing. Any arrangements that maybe entered into could be expensive to the Company. There can beno assurance that the Company will be able to raise additionalcapital in light of factors such as the market demand for itssecurities, the state of financial markets for independent oiland gas companies (including the markets for debt), oil and gasprices and general market conditions. See“Management’s Discussion and Analysis of FinancialCondition and Results of Operations — Liquidity andCapital Resources” for a discussion of the Company’scapital budget.     The Company expects to continue using its bank credit facilityto borrow funds to supplement its available cash flow. Theamount the Company may borrow under the credit facility may notexceed a borrowing base determined by the lenders based on theirprojections of the Company’s future production, futureproduction costs and taxes, commodity prices and other factors.The Company cannot control the assumptions the lenders use tocalculate the borrowing base. The lenders may, without theCompany’s consent, adjust the borrowing base at any time.If the Company’s borrowings under the credit facilityexceed the borrowing base, the lenders may require that theCompany repay the excess. If this were to occur, the Company mayhave to sell assets or seek financing from other sources. TheCompany can make no assurances that it would be successful inselling assets or arranging substitute financing. For adescription of the bank credit facility and its principal termsand conditions, see “Management’s Discussion andAnalysis of Financial Condition and Results ofOperations — Liquidity and Capital Resources.”***The Company’s operations may be interrupted by severe    weather, particularly in the Rocky Mountain region.***     The Company’s operations are conducted principally in theRocky Mountain region of the United States. The weather in thisarea can be extreme and can cause interruption in theCompany’s exploration and production operations. Moreover,especially severe weather can result in damage to facilitiesentailing longer operational interruptions and significantcapital investment. Likewise, the Company’s Rocky Mountainoperations are subject to disruption from winter storms andsevere cold, which can limit operations involving fluids andimpair access to the Company’s facilities. A portion of theCompany’s acreage is affected by winter lease stipulationsthat restrict the period of time during which operations may beconducted on the leases. The Company’s leases that areaffected by the winter stipulations prohibit drilling andcompleting activities fromNovember 15th toApril 30th,but allow production activities all year round.***Our focus on exploration projects increases the risks    inherent in our oil and gas activities.***     The Company has historically invested a significant portion ofits capital budget in drilling exploratory wells in search ofunproved oil and gas reserves. The Company cannot be certainthat the exploratory wells it drills will be productive or thatit will recover all or any portion of its investments. In orderto increase the chances for exploratory success, the Companyoften invests in seismic or other geoscience data to assist itin identifying potential drilling objectives. Additionally, thecost of drilling, completing and testing exploratory wells isoften uncertain at the time of the Company’s initialinvestment. Depending on complications encountered whiledrilling, the final cost of the well may significantly exceedthat which the Company originally estimated. The Company usesthe full cost method of accounting for exploration anddevelopment
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activities as defined by the SEC. Under this method ofaccounting, the costs of unsuccessful, as well as successful,exploration and development activities are capitalized asproperties and equipment and are then depleted using the unit ofproduction method based on the Company’s proved reserves.***Unless we are able to replace reserves which we have    produced, our cash flows and production will decrease over    time.***     The Company’s future success may depend on its ability tofind, develop and acquire additional oil and gas reserves thatare economically recoverable. Without successful exploration,development or acquisition activities, the Company’sreserves and production will decline. The Company can give noassurance that it will be able to find, develop or acquireadditional reserves at acceptable costs.***We are exposed to operating hazards and uninsured risks    that could adversely impact our results of operations and cash    flow.***     The oil and gas business involves a variety of operating risks,including fire, explosion, pipe failure, casing collapse,abnormally pressured formations, and environmental hazards suchas oil spills, natural gas leaks, and discharges of toxic gases.The occurrence of any of these events with respect to anyproperty operated or owned (in whole or in part) by the Companycould have a material adverse impact on the Company. The Companyand the operators of its properties maintain insurance inaccordance with customary industry practices and in amounts thatmanagement believes to be reasonable. However, insurancecoverage is not always economically feasible and is not obtainedto cover all types of operational risks. The occurrence of asignificant event that is not fully insured could have amaterial adverse effect on the Company’s financialcondition.***There are risks associated with our drilling activity that    could impact the results of our operations.***     The Company’s oil and gas operations are subject to all ofthe risks and hazards typically associated with drilling for,and production and transportation of, oil and gas. These risksinclude the necessity of spending large amounts of money foridentification and acquisition of properties and for drillingand completion of wells. In the drilling of exploratory ordevelopment wells, failures and losses may occur before anydeposits of oil or gas are found. The presence of unanticipatedpressure or irregularities in formations, blow-outs or accidentsmay cause such activity to be unsuccessful, resulting in a lossof the Company’s investment in such activity. If oil or gasis encountered, there can be no assurance that it can beproduced in quantities sufficient to justify the cost ofcontinuing such operations or that it can be marketedsatisfactorily.***Our decision to drill a prospect is subject to a number of    factors and we may decide to alter our drilling schedule or not    drill at all.***     This report includes certain descriptions of the Company’sfuture drilling plans with respect to its prospects. A prospectis an area which the Company’s geoscientists haveidentified what they believe, based on available seismic andgeological information, to be indications of hydrocarbons. TheCompany’s prospects are in various stages of review.Whether or not the Company ultimately drills a prospect maydepend 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;
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 •     the approval of partners to participate in the drilling or, in    the case of CNOOC, approval of expenditures for budget purposes;  •     the Company’s ability to attract other industry partners to    acquire a portion of the working interest to reduce exposure to    costs and drilling risks;  •     decisions of the Company’s joint working interest    owners; and  •     the BLM’s interpretation of an EIS and the results of the    permitting process.     The Company will continue to gather data about its prospects,and it is possible that additional information may cause theCompany to alter its drilling schedule or determine that aprospect should not be pursued at all.***If oil and gas prices decrease, we may be required to take    writedowns of the carrying value of our oil and gas    properties.***     The Company follows the full cost method of accounting for itsoil and gas properties. A separate cost center is maintained forexpenditures applicable to each country in which the Companyconducts exploration and/or production activities. Under suchmethod, the net book value of properties on a country-by-countrybasis, less related deferred income taxes, may not exceed acalculated “ceiling.” The ceiling is the estimatedafter tax future net revenues from proved oil and gasproperties, discounted at 10% per year. In calculatingdiscounted future net revenues, oil and gas prices in effect atthe time of the calculation are held constant, except forchanges which are fixed and determinable by existing contracts.The net book value is compared to the ceiling on a quarterlybasis. The excess, if any, of the net book value above theceiling is required to be written off as an expense. Under SECfull cost accounting rules, any write-off recorded may not bereversed even if higher oil and gas prices increase the ceilingapplicable to future periods. Future price decreases couldresult in reductions in the carrying value of such assets and anequivalent charge to earnings.***We are not the operator, and have limited influence over    the operations, of our Bohai Bay properties.***     Because the Company is not the operator and holds a minorityinterest, it cannot control the pace of exploration ordevelopment in the Bohai Bay properties or major decisionsaffecting the drilling of wells or the plan for development andproduction, although contract provisions give the Companycertain consent rights in some matters. Kerr-McGee’sinfluence, as operator, over these matters can affect the paceat which the Company spends money on this project. If Kerr-McGeewere to shift its focus from this project, the pace ofdevelopment could slow down or stop altogether. On the otherhand, if Kerr-McGee were to decide to accelerate development ofthis project, the Company could be required to fund its share ofcosts at a faster pace than anticipated, which might exceed itsability to raise funds. If, because of this, the Company wereunable to pay its share of costs, it could lose or be forced tosell its interest in the Bohai Bay properties or be forced tonot participate in the exploration or development of specificprospects or fields, potentially diminishing the value of itsBohai Bay assets.***Political, economic or legal factors associated with our    ownership of properties in China could impact the results of our    operations.***     Ownership of property interests and production operations inareas outside the United States are subject to various risksinherent 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;
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 •     other uncertainties arising out of foreign government    sovereignty over its international operations; and  •     currency restrictions and exchange rate fluctuations.     Tensions between China and its neighbors or various westerncountries, regional political or military disruption, changes ininternal Chinese leadership, social or political disruptionswithin China, a downturn in the Chinese economy, or a change inChinese laws or attitudes toward foreign investment could makeChina an unfavorable environment in which to invest. Althoughall the foreign interest owners in the Bohai Bay properties havethe right to sell production in the world market, the regulationof the concession by China, and the likely participation byCNOOC as a large working interest owner, make Chinese internaland external affairs important to the investment in the BohaiBay property. If any of these negative events were to occur, itcould lead to a decision that there is an intolerable level ofrisk in continuing with the investment, or the Company may beunable to attract equity investors or lenders, or satisfy anythen existing lenders.     In the event of a dispute arising from foreign operations, theCompany may be subject to the exclusive jurisdiction of foreigncourts or may not be successful in subjecting foreign persons tothe jurisdiction of courts in the United States or a potentiallymore favorable country.     In addition, the Company’s China PSC terminates after15 years of production, unless extended as provided for,which may be prior to the end of the productive life of thefields.***Our operations in China have special operational risks    that may negatively affect the value of those assets.***     Offshore operations, such as the Company’s Bohai Bayproperties, are subject to a variety of operating risks specificto the marine environment, such as capsizing, collisions and/orloss from storms or other adverse weather conditions. Theseconditions can cause substantial damage to facilities andinterrupt production. As a result, the Company could incursubstantial liabilities that could result in financial losses orfailures. China has many regulations similar to those addressedin Item 1, Environmental Regulation, that may expose theCompany to liability. Offshore projects, like the China fielddevelopments, are typically large, complex construction projectsthat are potentially subject to delays which may cause delays inachieving production and profitability.**Forward-Looking Statements**     This report contains or incorporates by referenceforward-looking statements within the meaning ofSection 27A of the Securities Act of 1933, as amended,Section 21E of the Securities Exchange Act of 1934 and thePrivate Securities Litigation Reform Act of 1995. All statementsother than statements of historical facts included in thisdocument, including without limitation, statements inItem 7, Management’s Discussion and Analysis ofFinancial Condition and Results of Operations regarding ourfinancial position, estimated quantities and net present valuesof reserves, business strategy, plans and objectives of theCompany’s management for future operations, covenantcompliance and those statements preceded by, followed by or thatotherwise include the words “believe”,“expects”, “anticipates”,“intends”, “estimates”,“projects”, “target”, “goal”,“plans”, “objective”, “should”, orsimilar expressions or variations on such expressions areforward-lookingstatements. The Company can give no assurances that theassumptions upon which suchforward-lookingstatements are based will prove to be correct.     Forward-looking statements include statements regarding: •     our oil and gas reserve quantities, and the discounted present    value of those reserves;  •     the amount and nature of our capital expenditures;  •     drilling of wells;  •     the timing and amount of future production and operating costs;
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 •     business strategies and plans of management; and  •     prospect development and property acquisitions.     Some of the risks which could affect our future results andcould cause results to differ materially from those expressed inour forward-looking statements include: •     general economic conditions;  •     the volatility of oil and natural gas prices;  •     the uncertainty of estimates of oil and natural gas reserves;  •     the impact of competition;  •     the availability and cost of seismic, drilling and other    equipment;  •     operating hazards inherent in the explorations for and    production of oil and natural gas;  •     difficulties encountered during the explorations for and    production of oil and natural gas;  •     difficulties encountered in delivering oil and natural gas to    commercial markets;  •     changes in customer demand and producers’ supply;  •     the uncertainty of our ability to attract capital;  •     compliance with, or the effect of changes in, the extensive    governmental regulations regarding the oil and natural gas    business;  •     actions of operators of our oil and gas properties; and  •     weather conditions.     The information contained in this report, including theinformation set forth under the heading “RiskFactors,” identifies additional factors that could affectour operating results and performance. We urge you to carefullyconsider these factors and the other cautionary statements inthis report. Our forward-looking statements speak only as of thedate made, and we have no obligation to update theseforward-looking statements.**Item 1B.*****Unresolved Staff Comments.***     None**Item 2.*****Properties.*****Location and Characteristics**     The Company is dependent on oil and gas leases in Wyoming andtwo petroleum contracts in China in order to explore for andproduce oil and gas. The leases in Wyoming are primarily federalleases with 10-yearlease terms until establishment of production. Production on thelease extends the lease terms until cessation of thatproduction. There are approximately 93,865 gross(42,298 net) acres currently held by production in Wyoming.The China petroleum contracts are for a maximum of 30 yearsand are divided into 3 periods; exploration, development andproduction. The exploration period is for approximately7 years and work is to be performed and expenditures are tobe incurred to delineate the extent and amount of hydrocarbons,if any, for each block. The development period occurs when afield is discovered and commences on the date of approval of theMinistry of Energy. There is no limit on the time allowed todevelop a field other than the combined maximum of30 years. The production period of any oil and gas field ina block is a period of 15 consecutive years beginning on thedate of commencement of commercial production from the field,unless extended.
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***Green River Basin, Wyoming***     As of December 31, 2005, the Company owned developed oiland gas leases totaling 12,552 gross (5,284 net) acresin the Green River Basin of Sublette County, Wyoming whichrepresents 99.7% of the Company’s total domestic developednet acreage. The Company owns undeveloped oil and gas leasestotaling 135,455 gross (73,404 net) acres in the GreenRiver Basin of Sublette County, Wyoming which represents 74.9%of the Company’s total domestic undeveloped net acreage.The Company’s acreage in the Green River Basin primarilycovers the Pinedale Anticline with several other undevelopedacreage blocks north and west of the Pinedale Anticline as wellas acreage in the Jonah Field. Holding costs of leases inWyoming not held by production were approximately $122,530 forthe fiscal year ended December 31, 2005. The primary targeton the Company’s Wyoming acreage is the tight gas sands ofthe upper Cretaceous Lance Pool formation.     *Exploratory Wells.* During the year-endedDecember 31, 2005, the Company participated in the drillingand completion of a total of 18 gross (8.62 net)productive exploratory wells on the Green River Basinproperties. At December 31, 2005, there were 11 gross(4.28 net) additional exploratory wells that commencedduring the year that were either still drilling, had drillingoperations suspended or are in various stages of completion.     *Development Wells.* During the year-endedDecember 31, 2005, the Company participated in the drillingand completion of 60 gross (23.68 net) productivedevelopment wells in the Pinedale Field area. AtDecember 31, 2005, there were 19 gross (6.28 net)additional development wells that commenced during 2005 thatwere either still drilling, had drilling operations suspended orare in various stages of completion. Additionally, 2 gross(1.28 net) wells in Jonah field had drilling operationscommenced during 2005 that were either still drilling, haddrilling operations suspended or are in various stages ofcompletion. For purposes of this report, development wells arewells identified as proven, undeveloped locations by theCompany’s independent petroleum engineering firmNetherland, Sewell & Associates, Inc. at the previousyear-end reserve evaluation. When drilled, these locations willbe counted as development wells.***Bohai Bay, China***     *Block 04/36:* The Petroleum Sharing Contract(“PSC”) covering this block became effectiveOctober 1, 1994. Negotiations with the Chinese governmentin 2005 resulted in an extension of the third exploration termto September 2007. As the PSC now stands, the exploration periodwill end at the end of September 2007. Barring anotherextension, at that time, all acreage not under appraisal,development or production must be relinquished. The Companyholds an 18.18% exploration interest in the exploration portionof the block and an 8.91% working interest in the CFD 11-1 and11-2 and the CFD 11-3 and 11-5 producing oil fields. This blockcovers 413,623 gross (75,197 net) acres under theexploration phase and 40,377 gross (3,598 net) acresunder development, or approximately 66% of the Company’stotal gross international acreage.     *Block 05/36:* The PSC covering this block became effectiveMarch 1, 1996. Negotiations with CNOOC at the end of 2005resulted in a two year extension of the third exploration termto February 28, 2008 when, barring an extension, allacreage not under appraisal, development or production must berelinquished. The extension granted by CNOOC must be ratified bythe Chinese Government which we anticipate will happen during2006. The Company holds a 23.08% exploration interest in thisblock which covers 218,079 gross (50,376 net) acresunder the exploration phase and 15,221 gross(1,119 net) acres under development. This acreageconstitutes approximately 34% of the Company’s total grossinternational acreage.     *Exploration/ Appraisal Activity:* In 2005, the Companyparticipated in drilling 1 exploration well (0.18 net)which failed to find commercial quantities of oil. The primarytarget formations on the Blocks are the Upper and LowerMinghuazhen, Guantao and Dongying formations.     *Development Activity:* In July 2004, the Company startedproduction at the CFD 11-1 and 11-2 fields on the 04/36 Block.Production well drilling at these fields continued through 2005and will continue into the first half of 2006. The Company hasparticipated in drilling a total of 47 production wells at theCFD 11-1 and CFD 11-2 fields. In July 2005, the Companycommenced production at the CFD 11-3 and 11-5 fields on the
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04/36 Block. The Company has participated in drilling a total of6 production wells at the CFD 11-3 and CFD 11-5 fields. The fourfield production complex currently consists of 53 producingwells, three production platforms and an anchored FPSO vessel.     Upon declaration of commerciality of a field or area by CNOOC,the Company’s share of all expenses within that area isdecreased by 51%, with the participation by CNOOC. For example,the Company’s 18.18% exploration interest is reduced to an8.91% working interest in the fields on production in the 04/36Block. Upon initiation of production, the sharing of productionis determined by the language of the PSC which states that foreach individual field: 1) a Chinese National Industrial Taxand Royalty are applied to 100% of the gross volumes of oil,2) Lease Operating Expenses (“LOE”) are thentaken out of the remainder oil and 3) after thesedeductions, 62.5% of the remaining production stream isdedicated to Exploration and Development Cost Recovery for theparticipants. The Exploration Cost Recovery shall be recoveredwithout interest, while the Development Cost Recovery shall becalculated with a fixed annual interest rate of 9% uplift, and4) the remaining 37.5% of production goes to the“remainder oil” category which is divided into a“share oil” for CNOOC and an “allocable remainderoil” for the contractors determined by a sliding scale(determined by yearly production), “X” factor. Projectprofit is subject to Chinese corporate tax.     There are three new fields, the CFD 11-6, CFD 12-1 and CFD 12-1Sthat are currently being developed. The CFD 11-6 field area ison the 04/36 Block. The CFD 12-1 and CFD 12-1S field areas areon the 05/36 Block. These development areas are located in closeproximity and thus will be developed as a single unit within theBlocks. The development areas have been unitized because thefields are within both the 04/36 and 05/36 Blocks wheredifferent parties have different levels of interest. The unitallows for an equitable distribution of production known toexist within the known areas of the fields to the variousparties. On May 27, 2005, a Unitization Agreement wassigned that assigned the Company a 7.82% working interest in thecombined field unit.     On October 16, 2003, a 15 year contract which providesfor extension for up to an additional 10 years, was signedby the operator to lease the FPSO. The Company ratified thecontract for its net share. The FPSO is a 110,000 —150,000 dead weight tons, double-hull FPSO with a900,000 — 1,100,000 barrels storage capacity,with single point mooring and a processing plant capable ofprocessing 60,000 barrels oil per day (expandable to80,000 barrels oil per day). The FPSO service agreementcalls for a day rate lease payment and a sliding scale perbarrel payment that decreases based on cumulative barrelsprocessed.***Pennsylvania***     The Company owns 26,868 gross (24,610 net) acres inPennsylvania, which represents 25.1% of the Company’s totaldomestic undeveloped net acreage. Holding costs of leases inPennsylvania not held by production were approximately $247,000for the fiscal year ended December 31, 2005.     *Exploratory Wells.* During the year endedDecember 31, 2005, the Company participated in the drillingand completion of a total of 1 gross (1.0 net)successful exploratory well on the Pennsylvania properties.Based on the test results, Ultra is preparing to lay a pipelineto connect this well to sales. It is anticipated that thisconnection should be completed during the first half of 2006.***Texas***     During the year ended, December 31, 2005, the Companydivested itself of a portion of its Texas properties. TheCompany sold one gross (0.66 net) operated well along withthe associated 640 gross (369 net) acres. The Companyis currently attempting to divest itself of its remaininginterest in Texas which consist of 1 gross (0.12 net)non-operated producing well, plus the associated 80 gross(14.0 net) acres. This represents 0.3% of theCompany’s total developed net acreage.
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**Oil and Gas Reserves**     The following table sets forth the Company’s quantities ofdomestic proved reserves, for the years-ended December 31,2005, 2004 and 2003 as estimated by independent petroleumengineers Netherland, Sewell & Associates, Inc. Thetable summarizes the Company’s domestic proved reserves,the estimated future net revenues from these reserves and thestandardized measure of discounted future net cash flowsattributable thereto at December 31, 2005, 2004 and 2003.In accordance with Ultra’s three-year planning andbudgeting cycle, proved undeveloped reserves included in thistable include only economic locations that are forecast to be onproduction before January 1, 2009. Proved undevelopedreserves represent 66.6% of total proved reserves.                **December 31,**     **2005** **2004** **2003**         **(In thousands)**    Proved Undeveloped Reserves                 Natural gas (MMcf)  1,264,632   899,315   664,295      Oil (MBbl)  10,117   7,195   5,314     Proved Developed Reserves                 Natural gas (MMcf)  635,591   514,686   359,072      Oil (MBbl)  5,087   4,195   3,028     Total Proved Reserves (MMcfe)  1,991,447   1,482,341   1,073,419     Estimated future net cash flows, before income tax $12,067,267  $5,889,630  $4,456,478     Standardized measure of discounted future net cash flows, before    income taxes(1) $5,311,312  $2,438,837  $1,784,314     Future income tax $1,809,228  $823,372  $648,801     Standardized measure of discounted future net cash flows, after    income tax $3,502,084  $1,615,465  $1,135,513  (1)     Management believes that the presentation of the standardized    measure of discounted future net cash flows, before income    taxes, of estimated proved reserves, discounted at 10% per    annum, may be considered a non-GAAP financial measure as defined    in Item 10(e) of Regulation S-K, therefore the Company has    included this reconciliation of the measure to the most directly    comparable GAAP financial measure (Standardized measure of    discounted future net cash flows, after income taxes).    Management believes that the presentation of the standardized    measure of future net cash flows before income taxes, provides    useful information to investors because it is widely used by    professional analysts and sophisticated investors in evaluating    oil and gas companies. Because many factors that are unique to    each individual company may impact the amount of future income    taxes to be paid, the use of the pre-tax measure provides    greater comparability when evaluating companies. It is relevant    and useful to investors for evaluating the relative monetary    significance of the Company’s oil and natural gas    properties. Further, investors may utilize the measure as a    basis for comparison of the relative size and value of the    Company’s reserves to other companies. The standardized    measure of discounted future net cash flows, before income    taxes, is not a measure of financial or operating performance    under GAAP, nor is it intended to represent the current market    value of the estimated oil and natural gas reserves owned by the    Company. Standardized measure of discounted future net cash    flows, before income taxes, should not be considered in    isolation or as a substitute for the standardized measure of    discounted future net cash flows as defined under GAAP.
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     The following table sets forth the Company’s quantities ofproved reserves in China, for the year-ending December 31,2005, as estimated by independent petroleum engineers RyderScott Company. In accordance with the Company’s “newfield” reserve booking policy, proved reserves were bookedafter production commenced. The table summarizes theCompany’s proved reserves in China, the estimated futurenet revenues from these reserves and the standardized measure ofdiscounted future net cash flows attributable thereto atDecember 31, 2005. In accordance with Ultra’sthree-year planning and budgeting cycle, proved undevelopedreserves included in this table include only economic locationsthat are forecast to be on production before January 1,2009. Proved undeveloped reserves represent 50.9% of totalproved reserves.                **December 31,**     **2005** **2004** **2003**         **(In thousands)**    Proved Undeveloped Reserves                 Natural gas (MMcf)  —   —   —      Oil (MBbl)  2,577   3,231   —     Proved Developed Reserves                 Natural gas (MMcf)  —   —   —      Oil (MBbl)  2,484   4,356   —     Total Proved Reserves (MMcfe)  30,366   45,526   —     Estimated future net cash flows, before income tax $166,931  $137,762  $—     Standardized measure of discounted future net cash flows, before    income taxes(1) $134,271  $103,518  $—     Future Income Tax  59,861   49,647   —     Standardized measure of discounted future net cash flows, after    income tax $74,410  $53,871  $—  (1)     Management believes that the presentation of the standardized    measure of discounted future net cash flows, before income    taxes, of estimated proved reserves, discounted at 10% per    annum, may be considered a non-GAAP financial measure as defined    in Item 10(e) of Regulation S-K, therefore the Company has    included this reconciliation of the measure to the most directly    comparable GAAP financial measure (Standardized measure of    discounted future net cash flows, after income taxes).    Management believes that the presentation of the standardized    measure of future net cash flows, before income taxes, provides    useful information to investors because it is widely used by    professional analysts and sophisticated investors in evaluating    oil and gas companies. Because many factors that are unique to    each individual company may impact the amount of future income    taxes to be paid, the use of the pre-tax measure provides    greater comparability when evaluating companies. It is relevant    and useful to investors for evaluating the relative monetary    significance of the Company’s oil and natural gas    properties. Further, investors may utilize the measure as a    basis for comparison of the relative size and value of the    Company’s reserves to other companies. The standardized    measure of discounted future net cash flows, before income    taxes, is not a measure of financial or operating performance    under GAAP, nor is it intended to represent the current market    value of the estimated oil and natural gas reserves owned by the    Company. Standardized measure of discounted future net cash    flows, before income taxes, should not be considered in    isolation or as a substitute for the standardized measure of    discounted future net cash flows as defined under GAAP.
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     The following table sets forth the Company’s quantities oftotal proved reserves both domestically and in China, for theyears-ended December 31, 2005, 2004 and 2003 as estimatedby independent petroleum engineers Netherland, Sewell &Associates, Inc. and Ryder Scott Company. The table summarizesthe Company’s total proved reserves, the estimated futurenet revenues from these reserves and the standardized measure ofdiscounted future net cash flows attributable thereto atDecember 31, 2005, 2004 and 2003. In accordance withUltra’s three-year planning and budgeting cycle, provedundeveloped reserves included in this table include onlyeconomic locations that are forecast to be on production beforeJanuary 1, 2009. Proved undeveloped reserves represent66.3% of total proved reserves.                **December 31,**     **2005** **2004** **2003**         **(In thousands)**    Proved Undeveloped Reserves                 Natural gas (MMcf)  1,264,632   899,315   664,295      Oil (MBbl)  12,694   10,426   5,314     Proved Developed Reserves                 Natural gas (MMcf)  635,591   514,686   359,072      Oil (MBbl)  7,571   8,551   3,028     Total Proved Reserves (MMcfe)  2,021,813   1,527,867   1,073,419     Estimated future net cash flows, before income tax $12,234,198  $6,027,392  $4,456,478     Standardized measure of discounted future net cash flows, before    income taxes(1) $5,445,583  $2,542,355  $1,784,314     Future income tax $1,869,089  $873,019  $648,801     Standardized measure of discounted future net cash flows, after    income tax $3,576,494  $1,669,336  $1,135,513  (1)     Management believes that the presentation of the standardized    measure of discounted future net cash flows, before income    taxes, of estimated proved reserves, discounted at 10% per    annum, may be considered a non-GAAP financial measure as defined    in Item 10(e) of Regulation S-K, therefore the Company has    included this reconciliation of the measure to the most directly    comparable GAAP financial measure (Standardized measure of    discounted future net cash flows, after income taxes).    Management believes that the presentation of the standardized    measure of future net cash flows, before income taxes, provides    useful information to investors because it is widely used by    professional analysts and sophisticated investors in evaluating    oil and gas companies. Because many factors that are unique to    each individual company may impact the amount of future income    taxes to be paid, the use of the pre-tax measure provides    greater comparability when evaluating companies. It is relevant    and useful to investors for evaluating the relative monetary    significance of the Company’s oil and natural gas    properties. Further, investors may utilize the measure as a    basis for comparison of the relative size and value of the    Company’s reserves to other companies. The standardized    measure of discounted future net cash flows, before income    taxes, is not a measure of financial or operating performance    under GAAP, nor is it intended to represent the current market    value of the estimated oil and natural gas reserves owned by the    Company. Standardized measure of discounted future net cash    flows, before income taxes, should not be considered in    isolation or as a substitute for the standardized measure of    discounted future net cash flows as defined under GAAP.
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**Production Volumes, Average Sales Prices and AverageProduction Costs**     The following table sets forth certain information regarding theproduction volumes and average sales prices received for andaverage production costs associated with the Company’s saleof oil and natural gas for the periods indicated.                 **Year Ended December 31,**     **2005** **2004** **2003**       **Production**                  Natural gas (Mcf)  61,722,349   43,667,384   27,621,759       Oil (Bbl) — US  464,330   349,673   211,591       Oil (Bbl) — China  1,556,280   624,560   —                 Total (Mcfe)  73,846,009   49,512,782   28,891,305 **Revenues**                  Natural Gas sales $422,091,034  $224,207,694  $114,840,558       Oil sales — US  26,639,931   14,659,219   6,740,539       Oil sales — China  67,762,036   20,179,534   —                 Total Revenues  516,493,001   259,046,447   121,581,097 **Lease Operating Expenses**                  Production costs — US*  9,047,390   6,286,715   3,627,639       Production costs — China*  7,352,000   2,286,000   —       Severance/production taxes — WY  52,689,060   28,151,661   13,767,668       Severance/production taxes — China  3,388,089   1,009,098   —       Gathering  17,125,147   13,135,809   7,828,372                 Total Lease Operating Expenses $89,601,686  $50,869,283  $25,223,679 **Realized Prices**                  Natural gas ($/Mcf) $6.84  $5.13  $4.16       Oil ($/Bbl) — US $57.37  $41.92  $31.86       Oil ($/Bbl) — China $43.54  $32.31  $— **Operating Costs per Mcfe**                  Production costs — Total $0.22  $0.17  $0.13       Severance/production taxes $0.76  $0.59  $0.48       Gathering $0.23  $0.27  $0.27       DD&A $0.79  $0.61  $0.56       Interest $0.04  $0.08  $0.10                Total Operating Costs per Mcfe $2.04  $1.72  $1.54  *     Average production costs include lifting costs and remedial    workover expenses.
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**Productive Wells**     As of December 31, 2005, the Company’s total gross andnet wells were as follows:          **Productive Wells*** **Gross Wells** **Net Wells**         Domestic             Natural Gas and Condensate  332.00   140.84     China             China Oil  53.00   4.73             TOTAL  385.00   145.57  *     Productive wells are producing wells plus shut-in wells the    Company deems capable of production. A gross well is a well in    which a working interest is owned. The number of net wells    represents the sum of fractional working interests the Company    owns in gross wells.**Oil and Gas Acreage**     As of December 31, 2005, the Company had total gross andnet developed and undeveloped oil and gas leasehold acres in theUnited States as set forth below. The developed acreage isstated on the basis of spacing units designated by stateregulatory authorities. The acreage and other additionalinformation concerning the Company’s oil and gas operationsare presented in the following tables.**     *****United States Acreage:***                   **Developed Acres** **Undeveloped Acres**       **Gross** **Net** **Gross** **Net**             Wyoming  12,552   5,284   135,455   73,404     Pennsylvania  —   —   26,868   24,610     Texas  80   14   —   —                  All States  12,632   5,298   162,323   98,014      As of December 31, 2005, the Company had total gross andnet developed and undeveloped oil and gas leasehold acres in theBohai Bay, China as set forth below.**     *****Bohai Bay Acreage:***                   **Developed Acres** **Undeveloped Acres**       **Gross** **Net** **Gross** **Net**             Block 04/36  40,377   3,598   413,623   75,197     Block 05/36  15,221   1,119   218,079   50,376                  Total Bohai Acreage  55,598   4,717   631,702   125,573 
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**Drilling Activities**     For each of the three fiscal years ended December 31, 2005,2004 and 2003, the number of gross and net wells drilled by theCompany was as follows:***Wyoming — Green River Basin***                            **2005** **2004** **2003**         **Gross** **Net** **Gross** **Net** **Gross** **Net**                 Development Wells                             Productive  60.00   23.68   34.00   14.48   24.00   6.88      Dry  0.00   0.00   0.00   0.00   0.00   0.00                        Total  60.00   23.68   34.00   14.48   24.00   6.88      At year end there were 21 gross (7.56 net) additionaldevelopment wells that were either drilling, had drillingoperations suspended or were in various stages of completion.This includes wells in both the Pinedale and Jonah fields.                            **2005** **2004** **2003**         **Gross** **Net** **Gross** **Net** **Gross** **Net**                 Exploratory Wells                             Productive  18.00   8.62   32.00   14.00   24.00   9.86      Dry  0.00   0.00   0.00   0.00   1.00   0.32                        Total  18.00   8.62   32.00   14.00   25.00   10.18      At year end there were 11 gross (4.28 net) additionalexploratory wells that were either drilling, had drillingoperations suspended or were in various stages of completion.***Pennsylvania***                            **2005** **2004** **2003**         **Gross** **Net** **Gross** **Net** **Gross** **Net**                 Exploratory Wells                             Productive  1.00   1.00   0.00   0.00   0.00   0.00      Dry  0.00   0.00   0.00   0.00   0.00   0.00                        Total  1.00   1.00   0.00   0.00   0.00   0.00 ***Texas***                            **2005** **2004** **2003**         **Gross** **Net** **Gross** **Net** **Gross** **Net**                 Exploratory Wells                             Productive  0.00   0.00   0.00   0.00   0.00   0.00      Dry  0.00   0.00   1.00   0.73   0.00   0.00                        Total  0.00   0.00   1.00   0.73   0.00   0.00 
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***China — Bohai Bay***                            **2005** **2004** **2003**         **Gross** **Net** **Gross** **Net** **Gross** **Net**                 Development Wells                             Productive  17.00   1.52   36.00   3.21   0.00   0.00      Dry  0.00   0.00   0.00   0.00   0.00   0.00                        Total  17.00   1.52   36.00   3.21   0.00   0.00     Exploratory Wells                             Productive and Successful Appraisal*  0.00   0.00   0.00   0.00   6.00   1.03      Dry  1.00   0.18   1.00   0.18   4.00   0.66                        Total  1.00   0.18   1.00   0.18   10.00   1.69  *     A successful appraisal well is a well that is drilled into a    formation shown to be productive of oil or gas by an earlier    well for the purpose of obtaining more information about the    reservoir.**Item 3. *Legal Proceedings.***     The Company is currently involved in various routine disputesand allegations incidental to its business operations. While itis not possible to determine the ultimate disposition of thesematters, the Company believes that the resolution of all suchpending or threatened litigation is not likely to have amaterial adverse effect on the Company’s financialposition, or results of operations.**Item 4. *Submission of Matters to a Vote of SecurityHolders.***     No matters were submitted to a vote of the Company’ssecurity holders during the fourth quarter of the fiscal yearended December 31, 2005.**PART II****Item 5.*****Market for Registrant’s Common Equity, Related    Stockholder Matters and Issuer Purchases of Equity    Securities.***     The common shares of the Company have been listed and posted fortrading on the American Stock Exchange (“AMEX”) sinceJanuary 17, 2001 under the symbol “UPL” and weretraded on the Toronto Stock Exchange (“TSX”) fromSeptember 30, 1998 to March 31, 2004 under the symbol“UP”. The following table sets forth the high and lowintra-day sales prices on the AMEX and TSX for 2005 and 2004 asreported by each exchange, respectively. The prices are adjustedfor a 2 for 1 stock split effective May 10, 2005.**AMERICAN STOCK EXCHANGE (US$)**         **2005** **High** **Low**         First Quarter $29.17  $22.20     Second Quarter $30.50  $21.48     Third Quarter $57.89  $30.36     Fourth Quarter $60.32  $45.10 
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**AMERICAN STOCK EXCHANGE (US$)**         **2004** **High** **Low**         First Quarter $15.65  $10.25     Second Quarter $19.00  $13.80     Third Quarter $25.50  $17.53     Fourth Quarter $27.83  $21.69 **TORONTO STOCK EXCHANGE (CDN$)**         **2004** **High** **Low**         First Quarter $20.13  $14.83     Second Quarter $—  $—     Third Quarter $—  $—     Fourth Quarter $—  $—      On February 28, 2006 the last reported sales price of thecommon stock on the AMEX was $52.04 per share. As ofFebruary 28, 2006 there were approximately 456 holders ofrecord of the common stock.     The Company has not declared or paid and does not anticipatedeclaring or paying any dividends on its common stock in thenear future. The Company intends to retain its cash flow fromoperations for the future operation and development of itsbusiness. In addition, the Company’s current creditfacility limits payment of dividends on its common stock.
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**Item 6.*****Selected Financial Data.***     The selected consolidated financial information presented belowfor the years ended December 31, 2005, 2004, 2003, 2002 and2001 is derived from the Consolidated Financial Statements ofthe Company. The earnings per share information (Basic incomeper common share and Diluted income per common share) have beenupdated to reflect the 2 for 1 stock split on May 10, 2005.                          **Year Ended December 31,**     **2005** **2004** **2003** **2002** **2001**             **(In thousands, except per share data)**    Statement of Operations Data                         Revenues:                          Natural gas sales $422,091  $224,208  $114,841  $38,503  $38,204       Oil sales  94,402   34,839   6,740   3,839   2,997       Interest and other  612   91   37   23   393                        Total revenues $517,105  $259,138  $121,618  $42,365  $41,594                      Expenses:                          Production expenses and taxes  89,602   50,869   25,224   11,411   9,023       Depreciation, depletion and amortization  58,103   30,249   16,216   9,712   6,687       General and administrative  11,484   6,152   5,733   4,199   3,894       Stock compensation  2,859   924   1,018   1,211   337       Interest  3,286   3,783   2,851   2,691   1,687                        Total expenses  165,333   91,977   51,042   29,224   21,628      Income before income taxes  351,772   167,160   70,576   13,141   19,966      Income tax provision — deferred  123,472   58,010   25,254   5,059   2,087                      Net income $228,300  $109,150  $45,323  $8,082  $17,879                      Basic income per common share $1.49  $0.73  $0.31  $0.05  $0.13      Diluted income per common share $1.41  $0.68  $0.29  $0.05  $0.12     Statement of Cash Flows Data                         Net cash provided by (used in):                          Operating activities $414,353  $175,343  $90,051  $21,490  $34,136       Investing activities  (306,547)  (165,014)  (103,622)  (64,360)  (59,862)      Financing activities  (80,344)  4,770   13,988   42,908   25,961     Balance Sheet Data                         Cash and cash equivalents $44,395  $16,933  $1,834  $1,418  $1,379      Working capital (deficit)  42,713   (9,969)  (22,057)  (4,415)  (6,635)     Oil and gas properties  702,663   474,634   307,864   207,362   155,221      Total assets  847,266   537,186   345,770   221,874   167,583      Total long-term debt  —   102,000   99,000   86,000   43,000      Other long-term obligations  20,577   9,735   5,120   3,859   3,193      Deferred income taxes, net  155,746   85,035   33,446   10,033   4,974      Total shareholders’ equity  571,201   267,992   149,453   104,067   95,320 **Item 7.*****Management’s Discussion and Analysis of Financial    Condition and Results of Operations.***     The following discussion of the financial condition andoperating results of the Company should be read in conjunctionwith the consolidated financial statements and related notes ofthe Company. Except as
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otherwise indicated all amounts are expressed inU.S. dollars. We operate in one segment, natural gas andoil exploration and development with two geographical segments,the United States and China.     The Company currently generates the majority of its revenue,earnings and cash flow from the production and sales of naturalgas and oil from its property in southwest Wyoming. The price ofnatural gas in the southwest Wyoming region is a critical factorto the Company’s business. The price of natural gas insouthwest Wyoming historically has been volatile. The averageannual realizations for the period 2001-2005 have ranged from$2.33 to $8.64 per Mcf. This volatility could be verydetrimental to the Company’s financial performance. TheCompany seeks to limit the impact of this volatility on itsresults by entering into forward sales and derivative contractsfor natural gas in southwest Wyoming. The average realizationfor the Company’s natural gas during calendar 2005 was$6.84 per Mcf, basis Opal, Wyoming, including the effect ofhedges. For the quarter ended December 31, 2005, theaverage realization for the Company’s natural gas was$8.49 per Mcf, basis Opal, Wyoming, including the effect ofhedges.     On July 18, 2004 the Company initiated production at thefirst two fields of the nine fields discovered on its oilproperties offshore Bohai Bay, China. Production from thesefields is characterized as a heavy, sweet crude. The Companysold its first cargos of oil in September 2004. During thetwelve-month period ended December 31, 2005, the Companysold 1,556,280 barrels of its Chinese oil production at aprice based on the official ICP posting for Duri field crude,less a discount for location and quality differences. Thesesales were made to an affiliate of CNOOC at an average price of$43.54 USD per barrel for the year ended December 31, 2005.For the quarter ended December 31, 2005, the Company sold393,084 barrels of its Chinese crude for an average priceof $48.16 USD per barrel. There can and will be differences intiming between the sale of the Company’s crude oil cargosand the Company’s pro-rata share of production. As a resultof these timing differences, the Company may, from time to time,carry inventories or imbalances of crude oil. As ofFebruary 28, 2006, the Duri price was approximately $54.56USD (before discount) per barrel.     The Company expects to sell at least one cargo of its Chinesecrude oil production approximately every two months during 2006.The Company has the right to export and sell its crude at marketprices into the international markets, and is evaluating optionsto do so in the future. Other markets for the Company’sChinese oil may potentially be developed in South Korea, Japan,Singapore or other countries.     The Company has grown its natural gas and oil productionsignificantly over the past five years and management believesit has the ability to continue growing production by drillingalready identified locations on its leases in Wyoming and bybringing into production the already discovered oil fields inChina. The Company delivered 25% production growth on an Mcfebasis during the quarter ended December 31, 2005 ascompared to the same quarter in 2004 and 49% production growthfor the year-ended December 31, 2005 compared to the sameperiod in 2004. Management expects to deliver additionalproduction growth during 2006 by drilling and bringing intoproduction additional wells in Wyoming and bringing intoproduction additional fields in China.           **2002** **2003** **2004** **2005**             Production — Bcfe     17.4     28.9     49.5     73.8     The Company conducts operations in both the United States andChina. Separate cost centers are maintained for each country inwhich the Company has operations. Substantially all of the oiland gas activities are conducted jointly with others and,accordingly, amounts presented reflect only the Company’sproportionate interest in such activities. Inflation has not hada material impact on the Company’s results of operationsand is not expected to have a material impact on theCompany’s results of operations in the future.**Critical Accounting Policies**     The discussion and analysis of the Company’s financialcondition and results of operations is based upon consolidatedfinancial statements, which have been prepared in accordancewith U.S. Generally Accepted Accounting Principles(“GAAP”). In addition, application of GAAP requiresthe use of estimates, judgments and assumptions that affect thereported amounts of assets and liabilities as of the date of thefinancial
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statements as well as the revenues and expenses reported duringthe period. Changes in these estimates, judgments andassumptions will occur as a result of future events, and,accordingly, actual results could differ from amounts estimated.     *Use of Estimates.* The more significant areas requiringthe use of assumptions, judgments and estimates relate tovolumes of oil and gas reserves used in calculating depletion,the amount of future net revenues used in computing the ceilingtest limitations and the amount of abandonment obligations usedin such calculations. Assumptions, judgments and estimates arealso required in determining impairments of undevelopedproperties and the valuation of deferred tax assets.     *Oil and Gas Reserves.* The Company emphasizes that thevolumes of reserves are estimates which, by their nature, aresubject to revision. The estimates are made using all availablegeological and reservoir data as well as production performancedata. These estimates are currently made annually by independentpetroleum engineers and reviewed by the Company’sengineers. The reserves are periodically reviewed and revised,either upward or downward, if warranted based upon additionaldata. Revisions are necessary due to changes in assumptionsbased on, among other things, reservoir performance, prices,economic conditions and governmental restrictions. Estimates ofproved crude oil and natural gas reserves significantly affectthe Company’s depreciation, depletion and amortization(“DD&A”) expense. For example, if estimates ofproved reserves decline, the Company’s DD&A rate willincrease, resulting in a decrease in net income. A decline inestimates of proved reserves could also result in a full costceiling write-down (see discussion below).     The present value of oil and gas properties represents theestimated future net cash flows from proved oil and gasreserves, discounted using a prescribed 10% discount rate(“PV 10”). Proved oil and gas reserves are theestimated quantities of natural gas, crude oil, condensate andnatural gas liquids that geological and engineering datademonstrate with reasonable certainty can be recovered in futureyears from known reservoirs under existing economic andoperating conditions. Reserves are considered “proved”if they can be produced economically as demonstrated by eitheractual production or conclusive formation tests. “Proveddeveloped” oil and gas reserves can be expected to berecovered through existing wells with existing equipment andoperating methods.     Due to the volatility of commodity prices, the oil and gasprices on the last day of the period significantly impact thecalculation of the PV 10. The present value of future net cashflows does not purport to be an estimate of the fair marketvalue of the Company’s proved reserves. An estimate of fairvalue would also take into account, among other things,anticipated changes in future prices and costs, the expectedrecovery of reserves in excess of proved reserves and a discountfactor more representative of the time value of money and therisks inherent in producing oil and gas.     *Full Cost Method of Accounting.* The Company uses the fullcost method of accounting for its oil and gas operations.Separate cost centers are maintained for each country in whichthe Company incurs costs. All costs incurred in the acquisition,exploration and development of properties (including costs ofsurrendered and abandoned leaseholds, delay lease rentals, dryholes and overhead related to exploration and developmentactivities) are capitalized. Effective with the adoption ofStatement of Financial Accounting Standard (“SFAS”)No. 143, “Accounting for Asset RetirementObligations,” the carrying amount of oil and gas propertiesincludes estimated asset retirement costs recorded based on thefair value of the asset retirement obligation when incurred. Thesum of net capitalized costs and estimated future developmentcosts of oil and gas properties for each full cost center aredepleted using theunits-of-productionmethod. Changes in estimates of reserves, future developmentcosts or asset retirement obligations are accounted forprospectively in our depletion calculation.     Investments in unproved properties are not depleted pending thedetermination of the existence of proved reserves. Unprovedproperties are assessed periodically to ascertain whetherimpairment has occurred. Unproved properties whose costs areindividually significant are assessed individually byconsidering the primary lease terms of the properties, theholding period of the properties, and geographic and geologicdata obtained relating to the properties. Where it is notpracticable to individually assess the amount of impairment ofproperties for which costs are not individually significant,such properties are grouped for purposes of
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assessing impairment. The amount of impairment assessed is addedto the costs to be amortized in the appropriate full cost pool.     Companies that use the full cost method of accounting for oiland gas exploration and development activities are required toperform a ceiling test calculation each quarter. The full costceiling test is an impairment test prescribed by SECRegulation S-XRule 4-10. The ceiling test is performed quarterly on acountry-by-country basis. The ceiling limits such pooled coststo the aggregate of the present value of future net revenuesattributable to proved crude oil and natural gas reservesdiscounted at 10% plus the lower of cost or market value ofunproved properties less any associated tax effects. If suchcapitalized costs exceed the ceiling, the Company will record awrite-down to the extent of such excess as a non-cash charge toearnings. Any such write-down will reduce earnings in the periodof occurrence and result in lower DD&A expense in futureperiods. A write-down may not be reversed in future periods,even though higher oil and natural gas prices may subsequentlyincrease the ceiling.     The Company did not have any write-downs related to the fullcost ceiling limitation in 2005, 2004 or 2003. As ofDecember 31, 2005, the ceiling limitation exceeded thecarrying value of the Company’s oil and gas properties.Estimates of discounted future net cash flows atDecember 31, 2005 were based on average natural gas pricesof approximately $8.00 per MCF in the U.S. and on averageliquids prices of approximately $60.81 per barrel in theU.S. In China, estimates of discounted future net cashflows on crude oil were based on a net realized price of$48.74 per barrel. A reduction in oil and gas prices and/orestimated quantities of oil and gas reserves would reduce theceiling limitation and could result in a ceiling test write-down.     *Asset Retirement Obligation.* The Company’s assetretirement obligations (“ARO”) consist primarily ofestimated costs of dismantlement, removal, site reclamation andsimilar activities associated with its oil and gas properties.SFAS No. 143 requires that the discounted fair valueof a liability for an ARO be recognized in the period in whichit is incurred with the associated asset retirement costcapitalized as part of the carrying cost of the oil and gasasset. The recognition of an ARO requires that management makenumerous estimates, assumptions and judgments regarding suchfactors as the existence of a legal obligation for an ARO,estimated probabilities, amounts and timing of settlements; thecredit-adjusted, risk-free rate to be used; inflation rates, andfuture advances in technology. In periods subsequent to initialmeasurement of the ARO, the Company must recognizeperiod-to-periodchanges in the liability resulting from the passage of time andrevisions to either the timing or the amount of the originalestimate of undiscounted cash flows. Increases in the AROliability due to passage of time impact net income as accretionexpense. The related capitalized cost, including revisionsthereto, is charged to expense through DD&A.     *Entitlements Method of Accounting for Oil and Gas Sales.*The Company generally sells natural gas, condensate and crudeoil under both long-term and short-term agreements at prevailingmarket prices. The Company recognizes revenues when the productsare delivered, which occurs when the customer has taken titleand has assumed the risks and rewards of ownership, prices arefixed or determinable and collectibility is reasonably assured.The Company accounts for oil and gas sales using the“entitlements method.” Under the entitlements method,revenue is recorded based upon the Company’s ownershipshare of volumes sold, regardless of whether it has taken itsownership share of such volumes. The Company records areceivable or a liability to the extent it receives less or morethan its share of the volumes and related revenue. Under thealternative “sales method” of accounting for oil andgas sales, revenue would be recorded based on volumes taken bythe Company or allocated to it by third parties, regardless ofwhether such volumes are more or less than its ownership shareof volumes produced. Reserve estimates would be adjusted toreflect any over- produced or under-produced positions.Receivables or payables would be recognized on a company’sbalance sheet only to the extent that remaining reserves are notsufficient to satisfy volumes over- or under-produced.     Make-up provisions andultimate settlements of volume imbalances are generally governedby agreements between the Company and its partners with respectto specific properties or, in the absence of such agreements,through negotiation. The value of volumes over- orunder-produced can change based on changes in commodity prices.The Company prefers the entitlements method of accounting foroil and gas sales because it allows for recognition of revenuebased on its actual share of jointly owned production, results in
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better matching of revenue with related operating expenses, andprovides balance sheet recognition of the estimated value ofproduct imbalances.     *Valuation of Deferred Tax Assets.* The Company uses theasset and liability method of accounting for income taxes. Underthis method, future income tax assets and liabilities aredetermined based on differences between the financial statementcarrying values and their respective income tax basis (temporarydifferences).     To assess the realization of deferred tax assets, managementconsiders whether it is more likely than not that some portionor all of the deferred tax assets will not be realized. Theultimate realization of deferred tax assets is dependent uponthe generation of future taxable income during the periods inwhich those temporary differences become deductible. Managementconsiders the scheduled reversal of deferred tax liabilities,projected future taxable income and tax planning strategies inmaking this assessment. As of December 31, 2004, theCompany had U.S. federal regular tax net operating losscarryforwards (“NOL’s”) of approximately$16.7 million which were fully utilized to offsetU.S. taxable income in 2005.     *Commodity Derivative Instruments and Hedging Activities.*The Company may, from time to time, enter into commodityderivative contracts and/or fixed-price physical contracts tomanage its exposure to oil and natural gas price volatility. TheCompany has, in the past, primarily utilized fixed price forwardsales of physical gas when it hedges some portion of its Wyomingnatural gas production. These transactions are generally placedwith major financial institutions or with counter-parties ofhigh credit quality that present minimal credit risks to theCompany. The Company may also secure payments under these typesof transactions by requiring the counterparty to provideletter(s) of credit. On a less frequent basis, the Company mayenter into commodity derivative contracts to manage pricevolatility. To the extent that it does enter into suchderivative transactions, the Company expects that the oil andnatural gas reference prices of these commodity derivativescontracts will be based upon crude oil and/or natural gasfutures contracts which, when adjusted for location basisdifferentials, will have a high degree of historical correlationwith actual prices the Company receives. UnderSFAS No. 133, all derivative instruments are recordedon the balance sheet at fair value. Changes in thederivative’s fair value are recognized currently inearnings unless specific hedge accounting criteria are met. Forqualifying cash flow hedges, the gain or loss on the derivativeis deferred in Accumulated Other Comprehensive Income (Loss) tothe extent the hedge is effective. For qualifying fair valuehedges, the gain or loss on the derivative is offset by therelated results of the hedged item in the income statement.Gains and losses on hedging instruments included in AccumulatedOther Comprehensive Income (Loss) on the balance sheet arereclassified to Oil and Natural Gas Sales Revenue in the periodthat the related production is delivered. Derivative contractsthat do not qualify for hedge accounting treatment are recordedas derivative assets and liabilities at market value in theconsolidated balance sheet, and the associated unrealized gainsand losses are recorded as current expense or income in theconsolidated statement of operations. The Company currently doesnot have any derivative contracts related to the marketing ofits natural gas or oil production in effect, the last one havingexpired on December 31, 2005.     *Legal, Environmental and Other Contingencies.* A provisionfor legal, environmental and other contingencies is charged toexpense when the loss is probable and the cost can be reasonablyestimated. Determining when expenses should be recorded forthese contingencies and the appropriate amounts for accrual is acomplex estimation process that includes the subjective judgmentof management. In many cases, management’s judgment isbased on interpretation of laws and regulations, which can beinterpreted differently by regulators and/or courts of law. TheCompany’s management closely monitors known and potentiallegal, environmental and other contingencies and periodicallydetermines when the Company should record losses for these itemsbased on information available to the Company.     *Share-Based Payment Arrangements.* In December 2004, theFinancial Accounting Standards Board (“FASB”) issuedSFAS No. 123R, “Share-Based Payments”(“SFAS No. 123R”). SFAS No. 123Ris a revision of SFAS No. 123, “Accounting forStock Based Compensation”, and supersedes APB OpinionNo. 25 (“APB Opinion 25”). Among other items,SFAS No. 123R eliminates the use of APB Opinion 25 and theintrinsic value method of accounting, and requires companies torecognize the cost of employee services received in exchange forawards of equity instruments, based on the grant date fair valueof those awards, in the financial statements. Pro formadisclosure is no longer an alternative under the new standard.The
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Company will adopt SFAS No. 123R as of the requiredeffective date for calendar year companies, which isJanuary 1, 2006.     SFAS No. 123R permits companies to adopt itsrequirements using either a “modified prospective”method, or a “modified retrospective” method. Underthe “modified prospective” method, compensation costis recognized in the financial statements beginning with theeffective date, based on the requirements ofSFAS No. 123R for all share-based payments grantedafter that date, and based on the requirements ofSFAS No. 123 for all unvested awards granted prior tothe effective date of SFAS No. 123R. Under the“modified retrospective” method, the requirements arethe same as under the “modified prospective” method,but also permit entities to restate financial statements ofprevious periods based on proforma disclosures made inaccordance with SFAS No. 123. At December 31,2005, all stock options granted to date were fully vested.     The Company currently utilizes a standard option pricing model(i.e., Black-Scholes) to measure the fair value of stock optionsgranted to Employees. While SFAS No. 123R permitsentities to continue to use such a model, the standard alsopermits the use of a more complex binomial, or“lattice” model. Based upon research done by theCompany on the alternative models available to value optiongrants, and in conjunction with the type and number of stockoptions expected to be issued in the future, the Company hasdetermined that it will continue to use the Black-Scholes modelfor option valuation as of the current time.     SFAS No. 123R includes several modifications to theway that income taxes are recorded in the financial statements.The expense for certain types of option grants is onlydeductible for tax purposes at the time that the taxable eventtakes place, which could cause variability in the Company’seffective tax rates recorded throughout the year.SFAS No. 123R does not allow companies to“predict” when these taxable events will take place.Furthermore, it requires that the benefits associated with thetax deductions in excess of recognized compensation cost bereported as a financing cash flow, rather than as an operatingcash flow as required under current literature. This requirementwill reduce net operating cash flows and increase net financingcash flows in periods after the effective date. These futureamounts cannot be estimated, because they depend on, among otherthings, when employees exercise stock options.**Results of Operations — Year EndedDecember 31, 2005 Compared to Year Ended December 31,2004**     Oil and gas revenues increased to $516.5 million for theyear ended December 31, 2005 from $259.0 million forthe same period in 2004. This increase was attributable to anincrease in both the Company’s production volumes andprices received for that production coupled with a fullyear’s production from the China asset. During 2005, theCompany’s production increased to 61.7 Bcf of naturalgas and 464.3 thousand barrels of condensate in Wyoming and1.6 million barrels of crude oil in China, up from 2004levels of 43.7 Bcf of natural gas and 349.7 thousandbarrels of condensate in Wyoming and 624.6 thousand barrels ofcrude oil in China . This 49% increase on an Mcfe basis wasattributable to the Company’s successful drillingactivities during 2005 and 2004 in Wyoming and initiation ofproduction in China during July 2004. During the year endedDecember 31, 2005, the average product prices received were$6.84 per Mcf and $57.37 per barrel of condensate inWyoming and $43.54 per barrel for crude oil in China,compared to $5.13 per Mcf and $41.92 per barrel ofcondensate in Wyoming and $32.31 per barrel of crude oil inChina for the same period in 2004.     In Wyoming, direct lease operating costs increased to$9.0 million in 2005 from $6.3 million in 2004 duelargely to higher production volumes. On a unit of productionbasis, LOE costs were flat at $0.14 per Mcfe in 2005 whencompared to 2004. Production taxes in Wyoming during the yearended December 31, 2005 were $52.7 million compared to$28.2 million in 2004, or $0.82 per Mcfe in 2005,compared to $0.62 per Mcfe in 2004. Production taxes inWyoming are calculated based on a percentage of revenue fromproduction. Therefore, higher prices received increasedproduction taxes on a per unit basis. Gathering fees in Wyomingfor the year ended December 31, 2005 increased to$17.1 million, or $0.27 per Mcfe in 2005 from$13.1 million, or $0.29 per Mcfe, in 2004 as a resultof higher production volumes.     In Wyoming, DD&A expenses increased to $48.5 millionduring the year ended December 31, 2005 from$27.3 million for the same period in 2004, attributable toincreased production volumes and a higher depletion
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rate due to forecasted increased future development costs. On aunit basis, DD&A expense in Wyoming increased to$0.75 per Mcfe in 2005 from $0.60 per Mcfe in 2004.     In China, production costs were $7.4 million in 2005, or$0.79 per Mcfe or $4.72 per BOE, compared with$2.3 million in 2004, or $0.61 per Mcfe or$3.66 per BOE. Severance taxes in China during the yearended December 31, 2005 were $3.4 million compared to$1.0 million in 2004, or $0.36 per Mcfe($2.18 per BOE) in 2005 compared to $0.27 per Mcfe($1.62 per BOE) in 2004. The increase in severance taxesrelates to a full year of production during 2005 compared tohalf year in 2004. In China, DD&A expense was$9.6 million or $1.03 per Mcfe or $6.20 per BOE,in 2005 compared to $2.9 million, or $0.77 per Mcfe or$4.65 per BOE in 2004. Production commenced in China duringJuly 2004.     Interest expense decreased to $3.3 million in 2005 from$3.8 million in 2004. This decrease was largelyattributable to the decrease in borrowings under the seniorcredit facility and was partially offset by increased interestrates during 2005.     Deferred income tax expense increased to $123.5 million in2005 from $58.0 million in 2004. This increase wasprimarily attributable to an increase in net income fromcontinuing operations combined with an increase in the tax rate.Deferred income taxes were booked at the rate of 35.1% for theyear ended December 31, 2005 as compared to a rate of 34.7%in 2004. The Company was not liable for current payment of anymaterial amount of income taxes for the period endingDecember 31, 2005.**Results of Operations — Year EndedDecember 31, 2004 Compared to Year Ended December 31,2003**     Oil and gas revenues increased to $259.0 million for theyear ended December 31, 2004 from $121.6 million forthe same period in 2003. This increase was attributable to anincrease in both the Company’s production and pricesreceived for that production as well as the production from theChina assets beginning in July 2004. During this period theCompany’s production increased to 43.7 Bcf of naturalgas and 349.7 thousand barrels of condensate in Wyoming and624.6 thousand barrels of crude oil in China, up from27.6 Bcf of natural gas and 211.6 thousand barrels ofcondensate for the same period in 2003. This 71% increase on anMcfe basis was attributable to the Company’s successfuldrilling activities during 2004 and 2003. During the year endedDecember 31, 2004 the average product prices were$5.13 per Mcf and $41.92 per barrel of condensate inWyoming and $32.31 per barrel for crude oil in China,compared to $4.16 per Mcf and $31.86 per barrel ofcondensate in Wyoming for the same period in 2003. The Chinaproduction began in July 2004.     In Wyoming, direct lease operating costs increased to$6.3 million in 2004 from $3.6 million in 2003 due tohigher production. On a unit of production basis, LOE costs were$0.14 per Mcfe in 2004, as compared to $0.13 per Mcfein 2003. Production taxes in Wyoming during 2004 were$28.2 million, compared to $13.8 million in 2003, or$0.62 per Mcfe in 2004, compared to $0.48 per Mcfe in2003. Production taxes are calculated based on a percentage ofrevenue from production. Therefore, higher prices receivedincreased the cost on a per unit basis. Gathering fees inWyoming increased to $13.1 million in 2004 from$7.8 million in 2003, attributable to higher productionvolumes.     In Wyoming, DD&A expenses increased to $27.3 millionduring the year ended December 31, 2004 from$16.2 million for the same period in 2003, attributable toincreased production volumes and a higher depletion rate,attributable to forecasted increased future development costs.On a unit basis, DD&A increased to $0.60 per Mcfe in2004 from $0.56 per Mcfe in 2003.     In China, production costs were $2.3 million in 2004, or$0.61 per Mcfe or $3.66 per BOE. Severance taxes inChina during the year ended December 31, 2004 were$1.0 million, or $0.27 per Mcfe ($1.62 per BOE).DD&A was $2.9 million or $0.77 per Mcfe or$4.65 per BOE in 2004.. Production in China started duringJuly 2004.     Interest expense increased to $3.8 million during 2004 from$2.8 million in 2003. This increase was attributable to theincrease in borrowings under the senior credit facility combinedwith increasing interest rates.
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     Deferred income tax expense for the period increased to$58.0 million in 2004 from $25.3 million in 2003. Thisincrease was attributable to an increase in net income fromcontinuing operations. Deferred income taxes were booked at therate of 34.7% as compared to a rate of 35.8% in 2003. TheCompany was not liable for current payment of any materialamount of income taxes for the period ending December 31,2004.**Liquidity and Capital Resources**     During the year-ended December 31, 2005, the Company reliedon cash provided by operations and borrowings under its seniorcredit facility to finance its capital expenditures. The Companyparticipated in the drilling of 110 wells in Wyoming andcontinued to participate in the development process in the Chinablocks, including the ongoing drilling of development wells. Forthe year-ended December 31, 2005 net capitalexpenditures were $282.7 million. At December 31,2005, the Company reported a cash position of $44.4 millioncompared to $16.9 million at December 31, 2004.Working capital at December 31, 2005 was $42.7 millionas compared to $(10.0) million at December 31, 2004.As of December 31, 2005, the Company had no outstandingbank indebtedness and other long-term obligations of$20.6 million comprised of items payable in more than oneyear, primarily related to production taxes.     The Company’s positive cash provided by operatingactivities, along with availability under its senior creditfacility, are projected to be sufficient to fund theCompany’s budgeted capital expenditures for 2006, which arecurrently projected to be $425.0 million. Of the$425.0 million budget, the Company plans to spendapproximately $400.0 million in Wyoming and approximately$20.0 million in China with the balance allocated toevaluating other areas. With the $400.0 million budgetedfor Wyoming, the Company plans to drill or participate in anestimated 160 gross wells in 2006, of which approximately25% will be for exploration wells and the remaining will be fordevelopment wells. Of the $20.0 million budgeted for China,approximately 33% will be for exploratory/appraisal activity andthe balance will be for development activity. The Companycurrently has no budget for acquisitions in 2006.     The Company (through its subsidiary) participates in a revolvingcredit facility with a group of banks led by JP Morgan ChaseBank, N.A. The agreement specifies a maximum loan amount of$500 million, an aggregate borrowing base of$800 million and a commitment amount of $200 millionat November 14, 2005. The commitment amount may beincreased up to the lesser of the borrowing base amount or$500 million at any time at the request of the Company.Each bank shall have the right, but not the obligation, toincrease the amount of their commitment as requested by theCompany. In the event that the existing banks increase theircommitment to an amount less than the requested commitmentamount, then it would be necessary to bring additional banksinto the facility. At December 31, 2005, the Company had noamounts outstanding and $200 million unused and availableunder the current committed amount.     The credit facility matures on May 1, 2010. The note bearsinterest at either (A) the bank’s prime rate plus amargin of zero percent (0.00%) to three-quarters of one percent(0.75%) based on the percentage of available credit drawn or at(B) LIBOR plus a margin of one percent (1.00%) to one andthree-quarters of one percent (1.75%) based on the percentage ofavailable credit drawn. For purposes of calculating interest,the available credit is equal to the borrowing base. An averageannual commitment fee of 0.25% to 0.375%, depending on thepercentage of available credit drawn, is charged quarterly forany unused portion of the commitment amount. The Company’stotal commitment fees were $354,017, $374,096 and $249,788 forthe years ended December 31, 2005, 2004 and 2003,respectively.     The borrowing base is subject to periodic (at least semi-annual)review and re-determination by the banks and may be decreased orincreased depending on a number of factors, including theCompany’s proved reserves and the bank’s forecast offuture oil and gas prices. If the borrowing base is reduced toan amount less than the balance outstanding, the Company hassixty days from the date of written notice of the reduction inthe borrowing base to pay the difference. Additionally, theCompany is subject to quarterly reviews of compliance with thecovenants under the bank facility including minimum coverageratios relating to interest, working capital and advances toSino-American Energy Corporation. In the event of a defaultunder the covenants, the Company may not be able to access fundsotherwise available under the facility. As of December 31,2005, the Company was in compliance with required ratios of thebank facility.
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     The debt outstanding under the credit facility is secured by amajority of the Company’s proved domestic oil and gasproperties.     During the year ended December 31, 2005, net cash providedby operating activities was $414.4 million as compared to$175.3 million for the year ended December 31, 2004.The increase in cash provided by operating activities wasprimarily due to the increase in earnings which was due tohigher production levels and higher prices received for thatproduction.     During the year ended December 31, 2005, cash used ininvesting activities was $306.5 million as compared to$165.0 million for the year ended December 31, 2004.The change is primarily attributable to increased activity fordrilling and completion operations in Wyoming. The$288.9 million used in oil and gas property expendituresconsists of $282.7 million incurred for drilling andcompletion activities in 2005, and $6.2 millionattributable to the timing of capital expenditures incurred butnot yet paid.     During the year ended December 31, 2005, cash used infinancing activities was $80.3 million as compared to cashprovided by financing activities of $4.8 million for theyear ended December 31, 2004. The change is primarilyattributable to debt repayment under the senior credit facilityoffset by proceeds from employee stock option exercises.**Contractual Obligations —**     The following table summarizes our contractual obligations as ofDecember 31, 2005:                       **Payments Due by Period:**       **Less Than**   **More Than**  **Total** **One Year** **1-3 Years** **3-5 Years** **5 Years**               Long-term debt $—  $—  $—  $—  $—     Drilling contracts  108,410,500   —   104,610,500   3,800,000   —     Operating leases  132,020   132,020   —   —   —     Office space lease  813,583   367,329   446,254   —   —                     Total contractual obligations $109,356,103  $499,349  $105,056,754  $3,800,000  $—                      As of December 31, 2005, the Company had committed todrilling obligations with certain rig contractors that willcontinue into 2009. The mentioned drilling rigs were contractedto fulfill the 2006-2008 drilling program initiatives in Wyoming.     On October 16, 2003 the operator of the Company’sproperties in China, Kerr-McGee, signed a 15 year contract,which provides for up to an additional 10 years, to leasethe FPSO. The Company ratified the contract for its net sharewhich is 8.91%. The FPSO service agreement calls for a day ratelease payment and a sliding scale per barrel processing fee thatdecreases based on cumulative barrels processed. The leasecontains a cancellation fee for the Company based on a slidingtime-scale (cancellation fee decreases with time) which as ofDecember 31, 2005 was $3.3 million net to theCompany’s 8.91% interest. The Company considers it veryunlikely that a lease cancellation situation will occur. Due tothe terms of the lease, the Company cannot estimate with anydegree of accuracy the costs it may incur during the life of thelease. The Company’s net share for the costs of the FPSO in2005 was approximately $1.8 million.     In May 2003, the Company amended its prior office lease inEnglewood, Colorado, which it has committed to through June2008. The Company’s total remaining commitment of thislease is $677,791 at December 31, 2005 ($265,485 in 2006,$273,530 in 2007 and $138,776 in 2008). In December 2003, theCompany signed a lease for office space in Houston, Texas, whichit has committed to through April 2007 for a total remainingcommitment of $135,792 ($101,844 in 2006 and $33,948 in 2007) atDecember 31, 2005. The total remaining commitment for bothoffices is $813,583.     During 2005, the Company took a major step toward assuring thatthe pipeline infrastructure to move the Company’s naturalgas supplies away from southwest Wyoming will be expanded toprovide sufficient capacity to transport its natural gasproduction and to provide for reasonable basis differentials forits natural gas in the
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future. The Company agreed to become an anchor shipper on theproposed Rockies Express Pipeline project, sponsored bysubsidiaries of Kinder Morgan and Sempra Energy. The RockiesExpress Pipeline, if built as proposed, would be the largestnatural gas transmission pipeline project of its type built inthe United States in more than 20 years, beginning at theOpal Processing Plant in southwest Wyoming and traversingWyoming and several other states to an ultimate terminus ineastern Ohio. This project is projected to cover more than1,800 miles and is contemplated to be a large- diameter(42”), high-pressure natural gas pipeline. The RockiesExpress Pipeline, if built, will be an interstate pipeline andwould therefore be subject to the jurisdiction of the UnitedStates Federal Energy Regulatory Commission (“FERC”).     On December 19, 2005, the Company signed two PrecedentAgreements with Rockies Express Pipeline, LLC and Entrega GasPipeline LLC governing how the parties will proceed through thedesign, regulatory process and construction of the pipelinefacilities and, subject to certain conditions precedent, theCompany will take firm transportation service if and when thepipeline facilities are constructed. Commencing upon completionof the pipeline facilities, the Company’s commitmentinvolves capacity of 200,000 MMBtu per day of natural gasfor a term of 10 years, and the Company will be obligatedto pay to Rockies Express certain demand charges related to itsrights to hold this firm transportation capacity as an anchorshipper. Based on current assumptions, current projectionsregarding the cost of the expansion and the participation ofother shippers in the expansion (noting specifically that theseassumptions are likely to change materially), the Companycurrently projects that annual demand charges due may beapproximately $70 million per year for the term of thecontract, exclusive of fuel and surcharges. The Company’sBoard of Directors approved the Precedent Agreements onFebruary 6, 2006 and Kinder Morgan, as the Managing Memberof the Rockies Express Pipeline LLC advised the Company of theirfinal approval of the Precedent Agreements, and their intent toproceed with the construction of the Rockies Express Pipeline onFebruary 28, 2006. The pipeline facilities are currentlyanticipated to be completed in stages between 2007 and 2009.Although the Company is optimistic that the Rockies ExpressPipeline project will receive the necessary regulatory approvalsand be constructed in a timely manner, there can be noassurances that the Rockies Express Pipeline will be built, norwill there be any assurances that, if built, it will preventlarge basis differentials from occurring in the future.     Additionally, in maintaining its acreage base that is not heldby production, the Company incurs certain expenses, includingdelay rental costs. From year to year, the Company’sacreage base varies, sometimes dramatically, rendering itimpossible to forecast with any accuracy what the amount ofthese delay rental costs will be. In 2005, delay rental costsfor all of the Company’s leases not held by production were$289,660.**Item 7A.*****Quantitative and Qualitative Disclosures About Market    Risk.***     The Company’s major market risk exposure is in the pricingapplicable to its natural gas and oil production. Realizedpricing is currently driven primarily by the prevailing pricefor the Company’s Wyoming natural gas production.Historically, prices received for natural gas production havebeen volatile and unpredictable. Pricing volatility is expectedto continue. Natural gas price realizations ranged from amonthly low of $5.50 per Mcf to a monthly high of$8.64 per Mcf during 2005. Realized natural gas prices arederived from the financial statements which include the effectsof hedging and natural gas balancing.     The Company may, from time to time, use derivative instrumentsas one way to manage its exposure to commodity prices. TheCompany has periodically entered into fixed price to index priceswap agreements in order to hedge a portion of its production.The purpose of the swaps is to provide a measure of stability tothe Company’s cash flows in an environment of volatile oiland gas prices. The derivatives reduce the Company’sexposure on the hedged volumes to decreases in commodity pricesand limit the benefit the Company might otherwise have receivedfrom any increases in commodity prices on the hedged volumes.The Company recognizes all derivative instruments as assets orliabilities on the balance sheet at fair value. The accountingtreatment of the changes in fair value as specified inSFAS No. 133 is dependent upon whether or not aderivative instrument is designated as a hedge. For derivativesdesignated as cash flow hedges, changes in fair value, to theextent the hedge is effective, are recognized in OtherComprehensive Income (Loss) on the balance sheet until thehedged item is recognized in earnings as oil and gas revenue.For all other derivatives, changes in fair value are recognizedin earnings as income or expense. As of December 31, 2005,the Company no longer assesses the future liability of cash flowhedges as all agreements qualifying as such have expired.
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     During 2005, the Company recognized costs associated withfinancially settled swaps to counterparties totaling $9,286,000as its net realization from hedging activities. This totalincludes $999,900 for the first quarter of 2005, $1,440,800 forthe second quarter of 2005, $2,090,600 for the third quarter of2005, and $4,754,700 for the fourth quarter of 2005.     At December 31, 2005, the Company had no open derivativecontracts to manage price risk on its natural gas production.     The Company also utilizes fixed price forward natural gas salesat southwest Wyoming delivery points to hedge its commodityexposure. In addition to the derivative contracts discussedabove, the Company had the following physical delivery contractsin place at December 31, 2005. (The Company’s averagenet interest in physical natural gas sales is approximately 80%.)           **Volume —** **Average****Contract Period** **MMBTU/Day** **Price/MMbtu**         Calendar 2006  70,000  $5.86      As of February 28, 2006, the Company’s fixed priceforward natural gas sales contracts represented net volumesequal to approximately 24% of the Company’s currentlyforecasted natural gas production for Calendar 2006.
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**Item 8.*****Financial Statements and Supplementary Data.*****REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**To the Board of Directors and ShareholdersUltra Petroleum Corp.:     We have audited the accompanying consolidated balance sheets ofUltra Petroleum Corp. and subsidiaries as of December 31,2005 and 2004, and the related consolidated statements ofoperations and retained earnings, shareholders’ equity andcash flows for each of the years in the three-year period endedDecember 31, 2005. These consolidated financial statementsare the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financialstatements based on our audits.     We conducted our audits in accordance with the standards of thePublic Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtainreasonable assurance about whether the financial statements arefree of material misstatement. An audit includes examining, on atest basis, evidence supporting the amounts and disclosures inthe financial statements. An audit also includes assessing theaccounting principles used and significant estimates made bymanagement, as well as evaluating the overall financialstatement presentation. We believe that our audits provide areasonable basis for our opinion.     In our opinion, the consolidated financial statements referredto above present fairly, in all material respects, the financialposition of Ultra Petroleum Corp. and subsidiaries as ofDecember 31, 2005 and 2004, and the results of theiroperations and their cash flows for each of the years in thethree-year period ended December 31, 2005, in accordancewith U.S. generally accepted accounting principles.     As explained in Note 1 to the consolidated financialstatements, the Company adopted Statement of FinancialAccounting Standards No. 143,*Accounting for AssetRetirement Obligations*, effective January 1, 2003.     We also have audited, in accordance with the standards of thePublic Company Accounting Oversight Board (United States), theeffectiveness of the Company’s internal control overfinancial reporting as of December 31, 2005, based oncriteria established in *Internal Control —Integrated Framework*issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO), and our reportdated March 30, 2006 expressed an unqualified opinion onmanagement’s assessment of, and an adverse opinion on theeffective operation of, internal control over financialreporting.     /s/ KPMG LLP       KPMG LLPDenver, ColoradoMarch 30, 2006
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**ULTRA PETROLEUM CORP.****CONSOLIDATED BALANCE SHEETS**            **December 31,**     **2005** **2004**       **(Expressed in U.S. dollars)****ASSETS**    Current assets             Cash and cash equivalents $44,394,775  $16,932,661      Restricted cash  213,899   211,961      Accounts receivable  75,656,031   35,749,287      Deferred tax asset  —   1,327,489      Inventory  22,062,585   5,180,024      Prepaid drilling costs and other current assets  128,044   1,725,843            Total current assets  142,455,334   61,127,265     Oil and gas properties, using the full cost method of accounting             Proved  612,960,790   385,794,926      Unproved  89,702,465   88,839,460     Capital assets  2,147,528   1,424,367            TOTAL ASSETS $847,266,117  $537,186,018         **LIABILITIES AND SHAREHOLDERS’ EQUITY**    Current liabilities             Accounts payable and accrued liabilities $49,297,861  $14,238,836      Fair value of derivative instruments  —   3,739,406      Current taxes payable  3,564,990   —      Capital cost accrual  46,879,289   53,118,385            Total current liabilities  99,742,140   71,096,627     Long-term debt  —   102,000,000     Deferred income tax liability  155,746,465   86,362,741     Other long-term obligations  20,576,574   9,734,904     Shareholders’ equity:             Common stock — no par value; authorized —    unlimited; issued and outstanding — 155,075,864 and    150,234,936 at December 31, 2005 and 2004, respectively  178,806,030   106,513,852      Treasury stock  (1,193,650)  (1,193,650)     Accumulated other comprehensive loss  —   (2,616,767)     Retained earnings  393,588,558   165,288,311            Total shareholders’ equity  571,200,938   267,991,746            Commitments and contingencies (Note 11)            TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY $847,266,117  $537,186,018        See accompanying notes to consolidated financial statements.Approved on behalf of the Board:/s/ Michael D. Watford, Director/s/ James E. Nielson, Director
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**ULTRA PETROLEUM CORP.****CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINEDEARNINGS**                **Year Ended December 31,**     **2005** **2004** **2003**         **(Expressed in U.S. Dollars)**    REVENUES:                 Natural gas sales $422,091,034  $224,207,694  $114,840,558      Oil sales  94,401,967   34,838,753   6,740,539              516,493,001   259,046,447   121,581,097               EXPENSES:                 Production expenses and taxes  89,601,686   50,869,283   25,223,679      Depletion, depreciation and amortization  58,102,871   30,249,061   16,215,714      General and administrative  14,342,178   7,075,720   6,751,367              162,046,735   88,194,064   48,190,760               OPERATING INCOME  354,446,266   170,852,383   73,390,337     OTHER INCOME (EXPENSE):                 Interest income  612,153   90,760   36,889      Interest expense  (3,286,087)  (3,783,070)  (2,850,916)             (2,673,934)  (3,692,310)  (2,814,027)              INCOME BEFORE INCOME TAXES  351,772,332   167,160,073   70,576,310     Income tax provision  123,472,085   58,010,278   25,253,671               NET INCOME  228,300,247   109,149,795   45,322,639     RETAINED EARNINGS, beginning of year  165,288,311   56,138,516   10,815,877               RETAINED EARNINGS, end of year $393,588,558  $165,288,311  $56,138,516               NET INCOME PER COMMON SHARE — BASIC $1.49  $0.73  $0.31               NET INCOME PER COMMON SHARE — DILUTED $1.41  $0.68  $0.29               Weighted average common shares outstanding — basic  153,100,067   149,735,666   148,198,106               Weighted average common shares outstanding — diluted  161,943,400   161,205,534   157,037,878           See accompanying notes to consolidated financial statements.
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**ULTRA PETROLEUM CORP.****CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY**                                  **Accumulated**            **Other**            **Comprehensive**   **Total**  **Shares** **Common** **Retained** **Income** **Treasury** **Shareholders’**  **Issued** **Stock** **Earnings** **(Loss)** **Stock** **Equity**                 Balances at December 31, 2002  147,973,336  $95,098,690  $10,815,877  $(653,875) $(1,193,650) $104,067,042      Stock options exercised  886,000   988,247   —   —   —   988,247      Employee stock plan grants  236,000   1,148,630   —   —   —   1,148,630      Fair value of non-employee stock option grants  —   212,654   —   —   —   212,654     Comprehensive earnings:                             Net earnings  —   —   45,322,639   —   —   45,322,639      Change in derivative instruments fair value  —   —   —   (2,286,482)  —   (2,286,482)    Total comprehensive earnings                      43,036,157                        Balances at December 31, 2003  149,095,336   97,448,221   56,138,516   (2,940,357)  (1,193,650)  149,452,730      Stock options exercised  1,106,600   1,770,099   —   —   —   1,770,099      Employee stock plan grants  33,000   560,175   —   —   —   560,175      Fair value of non-employee stock option grants  —   100,550   —   —   —   100,550      Tax benefit of stock options exercised  —   6,634,807   —   —   —   6,634,807     Comprehensive earnings:                             Net earnings  —   —   109,149,795   —   —   109,149,795      Change in derivative instruments fair value  —   —   —   323,590   —   323,590     Total comprehensive earnings                      109,473,385                        Balances at December 31, 2004  150,234,936   106,513,852   165,288,311   (2,616,767)  (1,193,650)  267,991,746      Stock options exercised  4,793,700   20,266,680   —   —   —   20,266,680      Employee stock plan grants  47,228   1,389,380   —   —   —   1,389,380      Fair value of non-employee stock option grants  —   —   —   —   —   —      Tax benefit of stock options exercised  —   50,636,118   —   —   —   50,636,118     Comprehensive earnings:                             Net earnings  —   —   228,300,247   —   —   228,300,247      Change in derivative instruments fair value  —   —   —   2,616,767   —   2,616,767     Total comprehensive earnings                      230,917,014                        Balances at December 31, 2005  155,075,864  $178,806,030  $393,588,558  $—  $(1,193,650) $571,200,938                    See accompanying notes to consolidated financial statements.
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**ULTRA PETROLEUM CORP.****CONSOLIDATED STATEMENTS OF CASH FLOW**                 **Year Ended December 31,**     **2005** **2004** **2003**           Cash flows from operating activities:                Net income $228,300,247  $109,149,795  $45,322,639     Adjustments to reconcile net income to net cash provided by    operating activities:                  Depletion, depreciation and amortization  58,102,871   30,249,061   16,215,714       Deferred income taxes  69,270,977   57,748,452   25,253,671       Tax benefit of stock options exercised  50,636,118   —   —       Stock compensation  2,858,515   923,623   1,018,220      Net changes in working capital:                  Restricted cash  (1,938)  (1,292)  (1,363)      Accounts receivable  (39,906,744)  (16,400,426)  (7,950,378)      Inventory  (518,576)  (275,424)  —       Prepaid expenses and other current assets  1,597,799   (14,106)  (1,237,458)      Accounts payable and accrued liabilities  32,518,107   (10,169,082)  10,168,164       Other long-term obligations  7,931,130   3,870,179   1,261,403       Taxation payable  3,564,990   261,826   —                Net cash provided by operating activities  414,353,496   175,342,606   90,050,612                Cash flows from investing activities:                  Oil and gas property expenditures  (282,668,055)  (195,598,484)  (115,837,250)      Change in capital costs accrual  (6,239,096)  22,501,473   26,541,083       Inventory  (16,054,472)  9,037,557   (13,589,270)      Purchase of capital assets  (1,585,819)  (954,702)  (737,021)              Net cash (used in) investing activities  (306,547,442)  (165,014,156)  (103,622,458)              Cash flows from financing activities:                  Borrowings of long-term debt, gross  22,000,000   44,000,000   43,000,000       Payments on long-term debt, gross  (124,000,000)  (41,000,000)  (30,000,000)      Proceeds from issuance of common stock  20,266,680   1,770,099   988,247       Stock issued for compensation  1,389,380   —   —               Net cash (used in) provided by financing activities  (80,343,940)  4,770,099   13,988,247               Net increase in cash and cash equivalents  27,462,114   15,098,549   416,401     Cash and cash equivalents, beginning of year  16,932,661   1,834,112   1,417,711               Cash and cash equivalents, end of year $44,394,775  $16,932,661  $1,834,112               SUPPLEMENTAL INFORMATION                 Cash paid for:                  Interest $3,393,279  $3,783,070  $2,850,916       Income taxes $326,502  $153,905  $—       Non-cash tax benefit of stock options exercised $50,636,118  $6,634,807  $— See accompanying notes to consolidated financial statements.
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIAL STATEMENTS****(Expressed in U.S. dollars unless otherwise noted)****Years ended December 31, 2005, 2004 and 2003****DESCRIPTION OF THE BUSINESS**     Ultra Petroleum Corp. (the “Company”) is anindependent oil and gas company engaged in the acquisition,exploration, development, and production of oil and gasproperties. The Company is incorporated under the laws of theYukon Territory, Canada. The Company’s principal businessactivities are in the Green River Basin of southwest Wyoming andBohai Bay, China.**1.****SIGNIFICANT ACCOUNTING POLICIES:**     (a) *Basis of presentation and principles ofconsolidation:* The consolidated financial statements includethe accounts of the Company and its wholly owned subsidiaries UPEnergy Corporation, Ultra Resources, Inc. and Sino-AmericanEnergy Corporation. The Company presents its financialstatements in accordance with U.S. Generally AcceptedAccounting Principles (“GAAP”). All materialinter-company transactions and balances have been eliminatedupon consolidation.     (b) *Accounting principles:* The consolidatedfinancial statements are prepared in accordance with accountingprinciples generally accepted in the United States.     (c) *Cash and cash equivalents:* We consider allhighly liquid investments with an original maturity of threemonths or less to be cash equivalents.     (d) *Restricted cash:* Restricted cash represents cashreceived by the Company from production sold where the finaldivision of ownership of the production is unknown or indispute. Wyoming law requires that these funds be held in afederally insured bank in Wyoming.     (e) *Capital assets:* Capital assets are recorded atcost and depreciated using the declining-balance method based ona seven-year useful life.     (f) *Oil and gas properties:* The Company uses thefull cost method of accounting for exploration and developmentactivities as defined by the Securities and Exchange Commission(“SEC”). Separate cost centers are maintained for eachcountry in which the Company incurs costs. Under this method ofaccounting, the costs of unsuccessful, as well as successful,exploration and development activities are capitalized asproperties and equipment. This includes any internal costs thatare directly related to exploration and development activitiesbut does not include any costs related to production, generalcorporate overhead or similar activities. Effective with theadoption of Statement of Financial Accounting Standard(“SFAS”) No. 143 in 2003, the carrying amount ofoil and gas properties also includes estimated asset retirementcosts recorded based on the fair value of the asset retirementobligation when incurred. Gain or loss on the sale or otherdisposition of oil and gas properties is not recognized, unlessthe gain or loss would significantly alter the relationshipbetween capitalized costs and proved reserves of oil and gasattributable to a country.     The sum of net capitalized costs and estimated futuredevelopment costs of oil and gas properties are amortized usingthe units-of-productionmethod based on the proven reserves as determined by independentpetroleum engineers. Oil and gas reserves and production areconverted into equivalent units based on relative energycontent. Operating fees received related to the properties inwhich the Company owns an interest are netted against expenses.Fees received in excess of costs incurred are recorded as areduction to the full cost pool. Effective with the adoption ofSFAS No. 143, asset retirement obligations areincluded in the base costs for calculating depletion.     Oil and gas properties include costs that are excluded fromcapitalized costs being amortized. These amounts representinvestments in unproved properties and major developmentprojects. The Company excludes these costs on acountry-by-country basis until proved reserves are found oruntil it is determined that the costs are impaired. All costsexcluded are reviewed, at least quarterly, to determine ifimpairment has
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**occurred. The amount of any impairment is transferred to thecapitalized costs being amortized (the depreciation, depletionand amortization (“DD&A”) pool) or a charge ismade against earnings for those international operations where areserve base has not yet been established. For internationaloperations where a reserve base has not yet been established, animpairment requiring a charge to earnings may be indicatedthrough evaluation of drilling results, relinquishing drillingrights or other information.     Companies that use the full cost method of accounting for oiland gas exploration and development activities are required toperform a ceiling test calculation each quarter. The full costceiling test is an impairment test prescribed by SECRegulation S-XRule 4-10. The ceiling test is performed quarterly on acountry-by-country basis. The ceiling limits such pooled coststo the aggregate of the present value of future net revenuesattributable to proved crude oil and natural gas reservesdiscounted at 10% plus the lower of cost or market value ofunproved properties less any associated tax effects. If suchcapitalized costs exceed the ceiling, the Company will record awrite-down to the extent of such excess as a non-cash charge toearnings. Any such write-down will reduce earnings in the periodof occurrence and result in lower DD&A expense in futureperiods. A write-down may not be reversed in future periods,even though higher oil and natural gas prices may subsequentlyincrease the ceiling. The effect of implementingSFAS No. 143 had no effect on the ceiling testcalculation as the future cash outflows associated with settlingasset retirement obligations are excluded from this calculation.     (g) *Inventories:* Crude oil products and materialsand supplies inventories are carried at the lower of currentmarket value or cost. Inventory costs include expenditures andother charges directly and indirectly incurred in bringing theinventory to its existing condition and location and the Companyuses the weighted average method of recording its inventory.Selling expenses and general and administrative expenses arereported as period costs and excluded from inventory cost.Inventories of materials and supplies are valued at cost orless. Crude oil product inventory at December 31, 2005 and2004 includes depletion and lease operating expenses(“LOE”) of $1,456,400 and $628,311, respectively,associated with the Company’s crude oil production inChina. Drilling and completion supplies inventory of$20.6 million primarily includes the cost of pipe that willbe utilized during the 2006 drilling program.     (h) *Derivative transactions:* The Company has enteredinto commodity price risk management transactions to manage itsexposure to natural gas price volatility. These transactions arein the form of fixed price forward natural gas sales contractswith financial institutions and other creditworthycounterparties. These transactions have been designated by theCompany as cash flow hedges. As such, unrealized gains andlosses related to the change in fair market value of thederivative contracts are recorded in other comprehensive incomein the balance sheet to the extent the hedges are effective.     (i) *Income taxes:* Income taxes are accounted forunder the asset and liability method. Deferred tax assets andliabilities are recognized for the future tax consequencesattributable to differences between the financial statementcarrying amounts of existing assets and liabilities and theirrespective tax basis and operating loss and tax creditcarryforwards. Deferred tax assets and liabilities are measuredusing enacted tax rates expected to apply to taxable income inthe years in which those temporary differences are expected tobe recovered or settled. The effect on deferred tax assets andliabilities of a change in tax rates is recognized in income inthe period that includes the enactment date.     (j) *Earnings per share:* Basic earnings per share iscomputed by dividing net earnings attributable to common stockby the weighted average number of common shares outstandingduring each period. Diluted earnings per share is computed byadjusting the average number of common shares outstanding forthe dilutive effect, if any, of common stock equivalents. TheCompany uses the treasury stock method to determine the dilutiveeffect.
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**     The following table provides a reconciliation of the componentsof basic and diluted net income per common share for the yearsended December 31, 2005, 2004 and 2003: (The earnings pershare information (Basic income per common share and Dilutedincome per common share) have been updated to reflect the 2 for1 stock split on May 10, 2005).               **Year Ended December 31,**     **2005** **2004** **2003**           Net income $228,300,247  $109,149,795  $45,322,639               Weighted average common shares outstanding during the period  153,100,067   149,735,666   148,198,106     Effect of dilutive instruments  8,843,333   11,469,868   8,839,772               Weighted average common shares outstanding during the period    including the effects of dilutive instruments  161,943,400   161,205,534   157,037,878     Basic earnings per share $1.49  $0.73  $0.31               Diluted earnings per share $1.41  $0.68  $0.29               Number of shares not included in dilutive earnings per share    that would have been anti-dilutive because the exercise price    was greater than the average market price of the common shares  540,000   —   27,260                (k) *Use of estimates:* Preparation of consolidatedfinancial statements in accordance with accounting principlesgenerally accepted in the United States requires management tomake estimates and assumptions that affect the reported amountsof assets and liabilities, the disclosure of contingent assetsand liabilities at the date of the financial statements, and thereported amounts of revenues and expenses during the reportingperiod. Actual results could differ from those estimates.     (l) *Reclassifications:* Certain amounts in thefinancial statements of the prior years have been reclassifiedto conform to the current year financial statement presentation.     (m) *Accounting for stock-based compensation:*SFAS No. 123 defines a fair value method of accountingfor employee stock options and similar equity instruments.SFAS No. 123 allows for the continued measurement ofcompensation cost for such plans (see Note 6) using theintrinsic value based method prescribed by APB OpinionNo. 25 (“APB Opinion 25”), “Accounting forStock Issued to Employees”, provided that pro forma resultsof operations are disclosed for those options granted. TheCompany accounts for stock options granted to employees anddirectors of the Company under the intrinsic value method and nocompensation expense is recognized when the exercise price ofoptions equals or is greater than the fair market value of theunderlying stock on the date of grant. Had the Company reportedcompensation costs as
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**determined by the fair value method of accounting for optiongrants to employees and directors, net income and net income percommon share would approximate the following pro forma amounts:                 **For the Year Ended December 31,**     **2005** **2004** **2003**           Net income:                 As reported $228,300,247  $109,149,795  $45,322,639      Deduct: Fair value of stock options issued, net of tax  (13,511,140)  (17,714,486)  (1,522,968)               Pro forma $214,789,107  $91,435,309  $43,799,671     Net income per common share:                 Basic earnings per share:                  As reported $1.49  $0.73  $0.31       Pro forma $1.40  $0.61  $0.30      Diluted earnings per share:                  As reported $1.41  $0.68  $0.29       Pro forma $1.33  $0.57  $0.28      For purposes of pro forma disclosures, the estimated fair valueof options is amortized to expense over the options’vesting period. The weighted-average fair value of each optiongranted is estimated on the date of grant using theBlack-Scholes option pricing model with the followingassumptions: at December 31, 2005 expected volatility of34.8% to 44.9% and a risk free rate of 4.18% to 4.41%; atDecember 31, 2004 expected volatility of 38.4% and a riskfree rate of 3.713%; and at December 31, 2003, expectedvolatility of 25.0% and a risk free rate of 4.35%. AtDecember 31, 2005 options have expected lives of1.9 years, at December 31, 2004 options had expectedlives of 6.5 years, and December 31, 2003 options hadexpected lives of 10 years. At December 31, 2005, allstock options issued to date have fully vested.     In the fourth quarter of 2004, the Financial AccountingStandards Board (“FASB”) issued SFAS No. 123(revised 2004), or SFAS No. 123R, Share-Based Payment,which replaces SFAS No. 123 and supersedes APB Opinion25. SFAS No. 123R eliminates the option to use APBOpinion 25’s intrinsic value method of accounting andrequires recording expense for stock compensation based on afair value based method. After a phase-in period forSFAS No. 123R, pro forma disclosure will no longer beallowed. In the first quarter of 2005, the SEC issued StaffAccounting Bulletin No. 107 which provided furtherclarification on the implementation of SFAS No. 123R.     Alternative phase-in methods are allowed under StatementNo. 123R and the Company’s effective date forimplementation of SFAS No. 123R is January 1,2006. The Company expects it will use the modified-prospectivephase-in method that requires entities to recognize compensationcosts in financial statements issued after the date of adoptionfor all share-based payments granted, modified or settled afterthe date of adoption as well as for any awards that were grantedprior to the adoption date for which the required service hasnot yet been performed. The Company does not believe that any ofthe alternative phase-in methods would have a materiallydifferent effect on the Company’s Consolidated Statement ofOperations or Balance Sheet.     (n) *Revenue Recognition.* Within the Company’sUnited States segment, natural gas revenues are recorded on theentitlement method. Under the entitlement method, revenue isrecorded when title passes based on the Company’s netinterest. The Company records its entitled share of revenuesbased on estimated production volumes. Subsequently, theseestimated volumes are adjusted to reflect actual volumes thatare supported by third party pipeline statements or cashreceipts. Since there is a ready market for natural gas, theCompany sells the majority of its products soon after productionat various locations at which time title and
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**risk of loss pass to the buyer. Natural gas imbalances occurwhen the Company sells more or less than its entitled ownershippercentage of total natural gas production. Any amount receivedin excess of the Company’s share is treated as a liability.If the Company receives less than its entitled share, theunderproduction is recorded as a receivable. AtDecember 31, 2005 the Company had a net natural gasimbalance liability of $0.5 million and atDecember 31, 2004, the Company had a net natural gasimbalance receivable of $2.0 million.     In China, revenues are recognized when production is sold to apurchaser at a fixed or determinable price, when delivery hasoccurred and title is transferred.     (o) *Accumulated Other Comprehensive Earnings (Loss):*Other comprehensive earnings (loss) is a term used to definerevenues, expenses, gains and losses that under generallyaccepted accounting principles are reported as separatecomponents of Shareholders’ Equity instead of net earnings(loss). The loss depicted on the balance sheet as othercomprehensive loss is associated with unrealized losses relatedto the change in fair value of derivative instruments designatedas cash flow hedges.               **Year Ended December 31,**     **2005** **2004** **2003**           Net income $228,300,247  $109,149,795  $45,322,639               Unrealized loss on derivative instruments, net of tax  —   (2,616,767)  (2,940,357)    Effect of dilutive instruments $228,300,247  $106,533,028  $42,382,282                (p) *Impact of recently issued accountingpronouncements:* In December 2004, the FASB issued a revisedSFAS No. 123 (“SFAS 123R”).SFAS 123R requires compensation costs related toshare-based payments to be recognized in the income statementover the vesting period. The amount of the compensation costwill be measured based on the grant-date fair value of theinstrument issued. SFAS 123R is effective as ofJanuary 1, 2006, for all awards granted or modified afterthat date and for those awards granted prior to that date thathave not vested. Beginning January 1, 2006 the Company willbegin expensing share based compensation. All outstanding awardsissued prior to this date have fully vested. Stock compensationexpensed in 2005, 2004 and 2003 has been included within thegeneral and administrative line item of the Company’sincome statement. For the years ended December 31, 2005,2004 and 2003, stock compensation expense was $2,858,515,$923,623 and $1,018,220, respectively.     As of January 1, 2006, the Company will be required toadopt SFAS No. 154, “Accounting Changes and ErrorCorrections, a replacement of APB Opinion No. 20 and SFASNo. 3” (“SFAS No. 154”). SFASNo. 154 requires retrospective application of voluntarychanges in accounting principles, unless it is impracticable.The Company does not expect this standard to have a materialimpact on its financial statements.**2.****ASSET RETIREMENT OBLIGATIONS:**     In June 2001, the FASB issued SFAS No. 143,“Accounting for Asset Retirement Obligations”(“SFAS No. 143”). SFAS No. 143 requires theCompany to record the fair value of an asset retirementobligation as a liability in the period in which it incurs alegal obligation associated with the retirement of tangiblelong-lived assets that result from the acquisition,construction, development and/or normal use of the assets. As ofDecember 31, 2005, the Company has recorded a liability of$3,601,348 ($2,845,724 U.S. and $755,624 China) to account forfuture obligations associated with its assets in both the UnitedStates and China. As of December 31, 2004, the liabilitywas $744,512 ($321,505 U.S. and $423,007 China).
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**     The following table summarizes the activities for theCompany’s asset retirement obligations for the year endedDecember 31, 2005:       **December 31,**  **2005**       Asset retirement obligations at beginning of period $744,512     Accretion expense  47,519     Liabilities incurred  844,977     Liabilities settled  (53,705)    Revisions of estimated liabilities  2,018,045         Asset retirement obligations at end of period  3,601,348     Less: current asset retirement obligations  —         Long-term asset retirement obligations $3,601,348     **3.****OIL AND GAS PROPERTIES:**            **December 31,** **December 31,**  **2005** **2004**         Developed Properties:             Acquisition, equipment, exploration, drilling and environmental    costs — Domestic $700,425,880  $435,095,908      Acquisition, equipment, exploration, drilling and environmental    costs — China  43,890,413   24,552,316      Less accumulated depletion, depreciation and    amortization — Domestic  (118,172,467)  (70,597,411)     Less accumulated depletion, depreciation and    amortization — China  (13,183,036)  (3,255,887)          612,960,790   385,794,926     Unproven Properties:             Acquisition and exploration costs — Domestic  17,647,300   16,910,010      Acquisition and exploration costs — China  72,055,165   71,929,450          $702,663,255  $474,634,386             The Company holds interests in projects located in both theUnited States and in China. Costs related to these interests of$89.7 million ($17.6 million in the U.S. and$72.1 million in China) are not being depleted pendingdetermination of existence of estimated proved reserves. TheCompany’s share of exploration on its China propertiesaccounts for the majority of this balance. The properties inChina began producing in July 2004 and development of additionalfields continues along with exploration of future fields. TheCompany will
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**continue to assess and allocate the unproven properties over thenext several years as proved reserves are established and asexploration dictates whether or not future areas will bedeveloped.                        **Total** **2005** **2004** **2003** **Prior**               United States:                         Acquisition costs $18,606,405  $1,818,954  $222,685  $418,064  $16,146,702      Exploration costs  7,477,887   545,602   1,082,804   995,612   4,853,869      Less transfers to proved  (8,436,992)  (1,627,266)  —   (128,139)  (6,681,587)                   17,647,300   737,290   1,305,489   1,285,537   14,318,984      China:                         Acquisition costs  44,857,346   —   —   —   44,857,346      Exploration costs  67,911,028   19,167,259   29,390,964   8,862,000   10,490,805      Less transfers to proved  (40,713,209)  (19,041,544)  (21,671,665)  —   —                    72,055,165   125,715   7,719,299   8,862,000   55,348,151     Total $89,702,465  $863,005  $9,024,788  $10,147,537  $69,667,135                 **4.****CAPITAL ASSETS:**                     **December 31,**      **December 31,** **2005** **December 31,** **December 31,**  **2005** **Accumulated** **2005** **2004**  **Cost** **Depreciation** **Net Book Value** **Net Book Value**             Computer equipment $1,000,516  $688,632  $311,884  $221,261     Office equipment  277,142   188,757   88,385   88,339     Field equipment  1,534,442   508,527   1,025,915   329,264     Other  2,482,917   1,761,573   721,344   785,503                $5,295,017  $3,147,489  $2,147,528  $1,424,367              **5.****LONG-TERM LIABILITIES:**           **December 31,** **December 31,**  **2005** **2004**         Bank indebtedness $—  $102,000,000     Other long-term obligations  20,576,574   9,734,904          $20,576,574  $111,734,904             *Bank indebtedness:* The Company (through its subsidiary)participates in a revolving credit facility with a group ofbanks led by JP Morgan Chase Bank, N.A. The agreement specifiesa maximum loan amount of $500 million and an aggregateborrowing base of $800 million and a commitment amount of$200 million at November 14, 2005. The commitmentamount may be increased up to the lesser of the borrowing baseamount or $500 million at any time at the request of theCompany. Each bank shall have the right, but not the obligation,to increase the amount of their commitment as requested by theCompany. In the event that the existing banks increase theircommitment to an amount less than the requested commitmentamount, then it would be necessary to bring additional banksinto the facility. At December 31, 2005, the Company had noamounts outstanding and $200 million unused and availableunder the current committed amount.
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**     The credit facility matures on May 1, 2010. The note bearsinterest at either (A) the bank’s prime rate plus amargin of zero percent (0.00%) to three-quarters of one percent(0.75%) based on the percentage of available credit drawn or at(B) LIBOR plus a margin of one percent (1.00%) to one andthree-quarters of one percent (1.75%) based on the percentage ofavailable credit drawn. For the purposes of calculatinginterest, the available credit is equal to the borrowing base.An average annual commitment fee of 0.25% to 0.375%, dependingon the percentage of available credit drawn, is chargedquarterly for any unused portion of the commitment amount. TheCompany’s total commitment fees were $354,017, $374,096 and$249,788 for the years ended December 31, 2005, 2004 and2003, respectively.     The borrowing base is subject to periodic (at least semi-annual)review and re-determination by the banks and may be decreased orincreased depending on a number of factors, including theCompany’s proved reserves and the bank’s forecast offuture oil and gas prices. If the borrowing base is reduced toan amount less than the balance outstanding, the Company hassixty days from the date of written notice of the reduction inthe borrowing base to pay the difference. Additionally, theCompany is subject to quarterly reviews of compliance with thecovenants under the bank facility including minimum coverageratios relating to interest, working capital and advances toSino-American Energy Corporation. In the event of a defaultunder the covenants, the Company may not be able to access fundsotherwise available under the facility. As of December 31,2005, the Company was in compliance with required ratios of thebank facility.     The debt outstanding, if any, under the credit facility issecured by a majority of the Company’s proved domestic oiland gas properties.     *Other long-term obligations:* These costs relate to thelong-term portion of production taxes payable, a liabilityassociated with imbalanced production, our asset retirementobligations mentioned in Note 2 and the long-term portionof the Company’s incentive compensation plan.**6.****STOCK BASED COMPENSATION:**     The Company’s Stock Incentive Plans are administered by theBoard of Directors (the “Plan Administrator”). ThePlan Administrator may make awards of stock options toemployees, directors, officers and consultants of the Company aslong as the aggregate number of common shares issuable to anyone person pursuant to incentives does not exceed 5% of thenumber of common shares outstanding at the time of the award. Inaddition, no participant may receive during any fiscal year ofthe Company’s awards of incentives covering an aggregate ofmore than 500,000 common shares. The Plan Administratordetermines the vesting requirements and any vesting restrictionsor forfeitures in certain circumstances. Incentives may not havean exercise period longer than 10 years. The exercise priceof the stock may not be less than the fair market value of thecommon shares at the time of award, where “fair marketvalue” means the weighted average trading price of thecommon shares for the five trading days preceding the date ofthe award.     On April 29, 2005, the shareholders approved the adoptionof the 2005 Stock Incentive Plan (“2005 Stock IncentivePlan”). The 2005 Stock Incentive Plan authorizes the PlanAdministrator to award Incentives from the effective date of the2005 Stock Incentive Plan. The 2005 Stock Incentive Plan is inaddition to the Company’s existing stock option plans (the“2000 Option Plan” and the “1998 StockPlan”). The 2000 Option Plan and the 1998 Stock Plan remaineffective and the Company will make grants under each of theexisting plans.     The purpose of the 2005 Stock Incentive Plan is to foster andpromote the long-term financial success of the Company and toincrease shareholder value by attracting, motivating andretaining key employees, consultants and directors and providingsuch participants in the 2005 Stock Incentive Plan with aprogram for obtaining an ownership interest in the Company thatlinks and aligns their personal interests with those of theCompany’s shareholders, thus enabling such participants toshare in the long-term growth and success of the Company. Toaccomplish these goals, the 2005 Stock Incentive Plan permitsthe granting of incentive stock
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**options, non-statutory stock options, stock appreciation rights,restricted stock, and other stock-based awards, some of whichmay require the satisfaction of performance-based criteria inorder to be payable to participants. The 2005 Stock IncentivePlan is an important component of the total compensation packageoffered to employees and directors, reflecting the importancethat the Company places on motivating and rewarding superiorresults with long-term, performance-based incentives.     The following table summarizes the changes in stock options forthe three-year period ended December 31, 2005:           **Number of** **Weighted Average**  **Options** **Exercise Price (US$)**         Balance, December 31, 2002  11,123,500  $0.26 to $4.43     Granted  1,595,000  $4.83 to $7.10     Exercised  (886,000) $0.32 to $4.43     Cancelled  (27,500) $4.43 to $4.83            Balance, December 31, 2003  11,805,000  $0.26 to $7.10            Granted  2,005,000  $11.69 to $24.31     Exercised  (1,106,600) $0.38 to $7.10            Balance, December 31, 2004  12,703,400  $0.26 to $24.31            Granted  1,529,000  $23.90 to $58.71     Exercised  (4,793,700) $0.32 to $25.68     Cancelled  (50,000) $25.68 to $25.68            Balance, December 31, 2005  9,388,700  $0.26 to $58.71             No compensation resulted from the granting of these options asall were granted at or above the market value of the commonshares at the date of grant. Stock options granted toconsultants have been assessed at fair value and capitalized tothe full cost pool based on the nature of the services providedby the consultants. At December 31, 2005, all stock optionsgranted to date were fully vested.     The following table summarizes information about the stockoptions outstanding at December 31, 2005.                           **Options Outstanding** **Options Exercisable**         **Weighted Average** **Weighted Average**   **Weighted Average** **Weighted Average**  **Number** **Remaining** **Exercise Price** **Number** **Remaining** **Exercise Price****Range of Exercise Price ($US)** **Outstanding** **Contractual Life** **($US)** **Exercisable** **Contractual Life** **($US)**                 $ 0.38 -  0.46  2,627,500   3.08  $0.46   2,627,500   3.08  $0.46     $ 0.25 -  0.57  823,000   4.30  $0.36   823,000   4.30  $0.36     $ 1.49 -  2.61  1,405,000   5.21  $1.91   1,405,000   5.21  $1.91     $ 3.91 -  4.43  722,000   6.36  $4.39   722,500   6.36  $4.39     $ 4.83 -  7.10  941,200   7.35  $5.04   941,200   7.35  $5.04     $11.68 - 24.21  1,484,000   8.31  $16.06   1,484,000   8.31  $16.06     $23.90 - 58.71  1,386,000   9.48  $35.28   1,386,000   9.48  $35.28      In December 2004, the FASB issued SFAS No. 123R,“Share-Based Payments”(“SFAS No. 123R”). SFAS No. 123Ris a revision of SFAS No. 123, “Accounting forStock Based Compensation”, and supersedes APB Opinion 25.Among other items, SFAS No. 123R eliminates the use of APBOpinion 25 and the intrinsic value method of accounting, andrequires companies to recognize the cost of employee servicesreceived in exchange for awards of equity instruments, based onthe grant date fair value of those awards, in
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**the financial statements. Pro forma disclosure is no longer analternative under the new standard. The Company will adopt SFASNo. 123R as of the required effective date for calendaryear companies, which is January 1, 2006.     SFAS No. 123R permits companies to adopt itsrequirements using either a “modified prospective”method, or a “modified retrospective” method. Underthe “modified prospective” method, compensation costis recognized in the financial statements beginning with theeffective date, based on the requirements ofSFAS No. 123R for all share-based payments grantedafter that date, and based on the requirements ofSFAS No. 123 for all unvested awards granted prior tothe effective date of SFAS No. 123R. Under the“modified retrospective” method, the requirements arethe same as under the “modified prospective” method,but also permit entities to restate financial statements ofprevious periods based on proforma disclosures made inaccordance with SFAS No. 123. At December 31, 2005,all stock options granted to date were fully vested.     The Company currently utilizes a standard option pricing model(i.e., Black-Scholes) to measure the fair value of stock optionsgranted to Employees. While SFAS No. 123R permitsentities to continue to use such a model, the standard alsopermits the use of a more complex binomial, or“lattice” model. Based upon research done by theCompany on the alternative models available to value optiongrants, and in conjunction with the type and number of stockoptions expected to be issued in the future, the Company hasdetermined that it will continue to use the Black-Scholes modelfor option valuation as of the current time.     SFAS No. 123R includes several modifications to theway that income taxes are recorded in the financial statements.The expense for certain types of option grants is onlydeductible for tax purposes at the time that the taxable eventtakes place, which could cause variability in the Company’seffective tax rates recorded throughout the year.SFAS No. 123R does not allow companies to“predict” when these taxable events will take place.Furthermore, it requires that the benefits associated with thetax deductions in excess of recognized compensation cost bereported as a financing cash flow, rather than as an operatingcash flow as required under current literature. This requirementwill reduce net operating cash flows and increase net financingcash flows in periods after the effective date. These futureamounts cannot be estimated, because they depend on, among otherthings, when employees exercise stock options.**7.****DERIVATIVE FINANCIAL INSTRUMENTS:**     The Company has, in the past, used derivative instruments as oneway to manage its exposure to commodity prices. The Company hasperiodically entered into fixed-price to index-price swapagreements in order to hedge a portion of its production. Thepurpose of the swaps is to provide a measure of stability to theCompany’s cash flows in an environment of volatile oil andgas prices. The derivatives reduce the Company’s exposureon the hedged volumes to decreases in commodity prices and limitthe benefit the Company might otherwise have received from anyincreases in commodity prices on the hedged volumes. The Companyrecognizes all derivative instruments as assets or liabilitiesin the balance sheet at fair value. The accounting treatment forthe changes in fair value as specified in SFAS No. 133is dependent upon whether or not a derivative instrument isdesignated as a hedge. For derivatives designated as cash flowhedges, changes in fair value, to the extent the hedge iseffective, are recognized in Other Comprehensive Income (Loss)on the balance sheet until the hedged item is recognized inearnings as oil and gas revenue. For all other derivatives,changes in fair value are recognized in earnings as income orexpense.     During 2005, the Company recognized costs associated withfinancially settled swaps to counter-parties totaling $9,286,000as its net realization from hedging activities. This totalincludes $999,900 for the first quarter of 2005, $1,440,800 forthe second quarter of 2005, $2,090,600 for the third quarter of2005, and $4,754,700 for the fourth quarter of 2005.     At December 31, 2005, the Company had no open derivativecontracts to manage price risk on its natural gas production.
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**     The Company also utilizes fixed price forward natural gas salesat southwest Wyoming delivery points to hedge its commodityexposure. The Company had the following physical deliverycontracts in place at December 31, 2005.           **Volume** **Average****Contract Period** **MMBTU/Day** **Price/MMbtu**         Calendar 2006  70,000  $5.86      As of February 28, 2006, the Company’s fixed priceforward natural gas sales contracts represented net volumesequal to approximately 24% of the Company’s currentlyforecasted natural gas production for Calendar 2006.**8.****INCOME TAXES:**     Income before income taxes is as follows:               **Year Ended December 31,**     **2005** **2004** **2003**           United States $304,943,491  $153,553,816  $70,970,170     Foreign  46,828,841   13,606,257   (393,860)              Total $351,772,332  $167,160,073  $70,576,310                The consolidated income tax provision is comprised of thefollowing:                **Year Ended December 31,**     **2005** **2004** **2003**           Current:                 U.S. federal & state $50,636,118  $261,826   —      Foreign  3,564,990   —   —     Deferred:                 U.S. federal & state  57,228,294   53,144,257   25,253,671      Foreign  12,042,683   4,604,195   —               Total income tax provision $123,472,085  $58,010,278  $25,253,671                During 2005, the Company realized tax benefits of$50.6 million attributable to tax deductions associatedwith the exercise of stock options. These benefits are recordedas a reduction of current taxes payable and as an increase inshareholders’ equity.     The income tax provision differs from the amount that would becomputed by applying the U.S. federal income tax rate of35% to pretax income as a result of the following:               **Year Ended December 31,**     **2005** **2004** **2003**           Income tax provision computed at the U.S. statutory rate $123,120,316  $58,506,026  $24,701,708     State income tax provision net of federal benefit  297,319   159,628   455,557     Other, net  54,450   (655,376)  96,406             $123,472,085  $58,010,278  $25,253,671           
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**     The tax effects of temporary differences that give rise tosignificant components of the Company’s deferred tax assetsand liabilities are as follows:              **Year Ended December 31,**     **2005** **2004**         Deferred tax assets:              Unrecognized loss on derivative instruments (current) $—  $1,327,489       U.S. federal net operating loss carryforwards  —   5,845,351       Foreign net operating loss carryforwards  1,976,930   2,554,106       Unrecognized loss on derivative instruments (noncurrent)  —   112,747       Other, net  4,469   1,009,305           1,981,399   10,848,998        Valuation allowance  (1,976,930)  (2,554,106)            Net deferred tax assets  4,469   8,294,892            Deferred tax liabilities:              Property and equipment  (155,750,934)  (93,330,144)            Net deferred tax asset (liability) $(155,746,465) $(85,035,252)            In assessing the realizability of the deferred tax assets,management considers whether it is more likely than not thatsome or all of the deferred tax assets will not be realized. Theultimate realization of the deferred tax assets is dependentupon the generation of future taxable income during the periodsin which the temporary differences become deductible. Amongother items, management considers the scheduled reversal ofdeferred tax liabilities, projected future taxable income andavailable tax planning strategies.     As of December 31, 2004, the Company had U.S. federalregular tax net operating loss carryforwards(“NOL’s”) of approximately $16.7 millionwhich were available to offset future U.S. taxable income.The Company did not record any valuation allowance attributableto its U.S. NOL’s as management estimated that it wasmore likely than not that the U.S. NOL’s would befully utilized before they expire. These U.S. NOL’swere fully utilized to offset U.S. taxable income in 2005.     The Company has Canadian non-capital tax loss carryforwards ofapproximately $5.6 million and $7.3 million as ofDecember 31, 2005 and December 31, 2004, respectively.The benefit of the Canadian loss carryforwards can only beutilized to the extent the Company generates future taxableincome in Canada. If not utilized, the $5.6 millionCanadian loss carryforward will expire between 2006 and 2015.     Since the Company currently has no income producing operationsin Canada, management estimates that it is more likely than notthat the Canadian loss carryforwards will not be utilized. Avaluation allowance has been recorded at December 31, 2005and December 31, 2004 attributable to this deferred taxasset.     The Company periodically uses derivative instruments designatedas cash flow hedges as a method of managing its exposure tocommodity price fluctuations. To the extent these hedges areeffective, changes in the fair value of these derivativeinstruments are recorded in Other Comprehensive Income, net ofincome tax. At December 31, 2005, the Company had no openderivative contracts; and, therefore, no recorded tax benefitattributable to unrecognized loss on derivative instruments. Atax benefit attributable to unrecognized loss on
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**derivative instruments of $1,440,236 was allocated directly toOther Comprehensive Income as of December 31, 2004.**9.****EMPLOYEE BENEFITS:**     The Company sponsors a qualified, tax-deferred savings plan inaccordance with provisions of Section 401(k) of theInternal Revenue Code for its employees. Employees may defer upto 15% of their compensation, subject to certain limitations.The Company matches the employee contributions up to 5% ofemployee compensation along with a profit sharing contributionof 8%. The plan operates on a calendar year basis and began inFebruary 1998. The expense associated with the Company’scontribution was $507,306, $396,684 and $299,832 for the yearsended December 31, 2005, 2004 and 2003, respectively.**10.****SEGMENT INFORMATION:**     The Company has two reportable operating segments, one domesticand one foreign, which are in the business of natural gas andcrude oil exploration and production. The accounting policies ofthe segments are the same as those described in the summary ofsignificant accounting policies. The Company evaluatesperformance based on profit or loss from oil and gas operationsbefore price-risk management and other, general andadministrative expenses and interest expense. The Company’sreportable operating segments are managed separately based ontheir geographic locations. Financial information by operatingsegment is presented below:                **United States** **China** **Total**       **Year-ended December 31, 2005**                Oil and gas sales $448,730,965  $67,762,036  $516,493,001     Costs and Expenses:                 Depletion, depreciation and amortization  48,455,070   9,647,801   58,102,871      Lease operating expenses  9,047,390   7,352,000   16,399,390      Production taxes  52,689,060   3,388,089   56,077,149      Gathering  17,125,147   —   17,125,147               Operating income $321,414,298  $47,374,146  $368,788,444                General and administrative          14,342,178      Other expense, net          2,673,934               Income before income taxes         $351,772,332               Capital expenditures $263,486,693  $19,181,362  $282,668,055               Net oil and gas properties $599,900,713  $102,762,542  $702,663,255           
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**                **United States** **China** **Total**       **Year-ended December 31, 2004**                Oil and gas sales $238,866,913  $20,179,534  $259,046,447     Costs and Expenses:                 Depletion, depreciation and amortization  27,346,061   2,903,000   30,249,061      Lease operating expenses  6,286,715   2,286,000   8,572,715      Production taxes  28,151,661   1,009,098   29,160,759      Gathering  13,135,809   —   13,135,809               Operating income $163,946,667  $13,981,436  $177,928,103                General and administrative          7,075,720      Other expense, net          3,692,310               Income before income taxes         $167,160,073               Capital expenditures $179,592,969  $16,005,515  $195,598,484               Net oil and gas properties $381,408,507  $93,225,879  $474,634,386                           **United States** **China** **Total**       **Year-ended December 31, 2003**                Oil and gas sales $121,581,097   —  $121,581,097     Costs and Expenses:                 Depletion, depreciation and amortization  16,215,714   —   16,215,714      Lease operating expenses  3,627,639   —   3,627,639      Production taxes  13,767,668   —   13,767,668      Gathering  7,828,372   —   7,828,372               Operating income $80,141,704  $—  $80,141,704                General and administrative          6,751,367      Other expense, net          2,814,027               Income before income taxes         $70,576,310               Capital expenditures $100,677,192  $15,160,058  $115,837,250               Net oil and gas properties $226,893,478  $80,970,244  $307,863,722           **11.****COMMITMENTS AND CONTINGENCIES:**     On October 16, 2003 the operator of the Company’sproperties in China, Kerr-McGee, signed a 15 year contract,which provides for up to an additional 10 years, to lease afloating production storage offloading unit (“FPSO”).The Company ratified the contract for its net share which is8.91%. The FPSO service agreement calls for a day rate leasepayment and a sliding scale per barrel processing fee thatdecreases based on cumulative barrels processed. The leasecontains a cancellation fee based on a sliding time-scale(cancellation fee decreases with time), which as ofDecember 31, 2005 was $3.3 million net to theCompany’s 8.91% interest. The Company considers it veryunlikely that a lease cancellation situation will occur. Due tothe terms of the lease, the Company cannot estimate with anydegree of accuracy the costs it may incur during the life of thelease. The Company’s net share for the costs of the FPSO in2005 was approximately $1.8 million.
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**     In May 2003, the Company amended its prior office lease inEnglewood, Colorado, which it has committed to through June2008. The Company’s total remaining commitment atDecember 31, 2005 on this lease is $677,791 atDecember 31, 2005 ($265,485 in 2006, $273,530 in 2007 and$138,776 in 2008). In December 2003, the Company signed a leasefor office space in Houston, Texas, which it has committed tothrough April 2007 for a total remaining commitment of $135,792($101,844 in 2006 and $33,948 in 2007) at December 31,2005. The total remaining commitment for both offices is$813,583.     As of December 31, 2005, the Company had committed todrilling obligations with certain rig contractors totalling$108,410,500 with $104,610,500 due in one to three years and thebalance of $3,800,000 due in three to five years. Thecommitments expire in 2009 and were entered into to fulfill theCompany’s 2006-2008 drilling program initiatives in Wyoming.     During 2005, the Company took a major step toward assuring thatthe pipeline infrastructure to move the Company’s naturalgas supplies away from southwest Wyoming will be expanded toprovide sufficient capacity to transport its natural gasproduction and to provide for reasonable basis differentials forits natural gas in the future. The Company agreed to become ananchor shipper on the proposed Rockies Express Pipeline project,sponsored by subsidiaries of Kinder Morgan and Sempra Energy.The Rockies Express Pipeline, if built as proposed, would be thelargest natural gas transmission pipeline project of its typebuilt in the United States in more than 20 years. Asproposed, the Rockies Express Pipeline would begin at the OpalProcessing Plant in southwest Wyoming, and traverse Wyoming andseveral other states to an ultimate terminus in eastern Ohio.This project is projected to cover more than 1,800 milesand is contemplated to be a large-diameter (42”),high-pressure natural gas pipeline. The Rockies ExpressPipeline, if built, will be an interstate pipeline and wouldtherefore be subject to the jurisdiction of the United StatesFederal Energy Regulatory Commission.     On December 19, 2005, the Company signed, subject to Boardof Director approval, a Precedent Agreement with Rockies ExpressPipeline, LLC committing to take firm transportation capacity inthe proposed Rockies Express interstate pipeline. TheCompany’s commitment involves capacity of200,000 MMBtu per day of natural gas for a term of10 years, and the Company will be obligated to pay toRockies Express certain demand charges related to its rights tohold this firm transportation capacity as an anchor shipper. TheCompany’s Board of Directors approved the PrecedentAgreement on February 6, 2006 and Kinder Morgan, as theManaging Member of the Rockies Express Pipeline LLC advised theCompany of their final approval of the Precedent Agreement, andtheir intent to proceed with the construction of the RockiesExpress Pipeline on February 28, 2006. Although the Companyis optimistic that the Rockies Express Pipeline project willreceive the necessary regulatory approvals and be constructed ina timely manner, there can be no assurances that the RockiesExpress Pipeline will be built, nor will there be any assurancesthat, if built, it will prevent large basis differentials fromoccurring in the future.     The Company is currently involved in various routine disputesand allegations incidental to its business operations. While itis not possible to determine the ultimate disposition of thesematters, management, after consultation with legal counsel, isof the opinion that the final resolution of all such currentlypending or threatened litigation is not likely to have amaterial adverse effect on the consolidated financial position,results of operations or cash flows of the Company.**12.****FAIR VALUE OF FINANCIAL INSTRUMENTS:**     For certain of the Company’s financial instruments,including accounts receivable, notes receivable, accountspayable and accrued liabilities, the carrying amountsapproximate fair value due to the immediate or short-termmaturity of these financial instruments.     The Company’s revenues are derived principally fromuncollateralized sales to customers in the natural gas and oilindustry. The concentration of credit risk in a single industryaffects the Company’s overall exposure to credit riskbecause customers may be similarly affected by changes ineconomic and other
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**conditions. In 2005, the Company had three significantcustomers, CNOOC, Occidental Energy Marketing, Inc. and SempraEnergy Trading, that individually accounted for 10% or more ofthe Company’s total natural gas and oil sales during 2005.**13.****SUMMARIZED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):**                                   **Income Before** **Income**   **Basic** **Diluted**      **Income Tax** **Tax** **Net** **Earnings** **Earnings**  **Revenues** **Expenses** **Provision** **Provision** **Income** **per Share** **per Share**                 **(In thousands, except for per share data)****2005**                                First Quarter $89,364  $31,857  $57,507  $20,185  $37,322  $0.25  $0.23     Second Quarter $110,635  $36,848  $73,787  $25,899  $47,888  $0.31  $0.30     Third Quarter $134,378  $40,618  $93,760  $32,910  $60,850  $0.40  $0.38     Fourth Quarter $182,116  $55,398  $126,718  $44,478  $82,240  $0.53  $0.50                         $516,493  $164,721  $351,772  $123,472  $228,300                               **2004**                                First Quarter $48,619  $17,947  $30,672  $10,888  $19,784  $0.13  $0.12     Second Quarter $46,110  $17,393  $28,717  $10,195  $18,522  $0.12  $0.12     Third Quarter $66,849  $23,261  $43,588  $15,713  $27,875  $0.19  $0.17     Fourth Quarter $97,468  $33,285  $64,183  $21,214  $42,969  $0.29  $0.26                         $259,046  $91,886  $167,160  $58,010  $109,150                               **14.****DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES    (UNAUDITED):**     The following information about the Company’s oil and gasproducing activities is presented in accordance with FinancialAccounting Standards Board Statement No. 69, DisclosureAbout Oil and Gas Producing Activities:**     A.*****OIL AND GAS RESERVES:***     The determination of oil and gas reserves is complex and highlyinterpretive. Assumptions used to estimate reserve informationmay significantly increase or decrease such reserves in futureperiods. The estimates of reserves are subject to continuingchanges and, therefore, an accurate determination of reservesmay not be possible for many years because of the time neededfor development, drilling, testing, and studies of reservoirs.The following unaudited tables as of December 31, 2005,2004 and 2003 are based upon estimates prepared by Netherland,Sewell & Associates, Inc. dated January 27, 2006,January 24, 2005 and January 23, 2004, respectively.The estimates for properties in China were prepared by RyderScott Company in a report dated January 31, 2006 andFebruary 11, 2005. These are estimated quantities of provedoil and gas reserves for the Company and the changes in totalproved reserves as of December 31, 2005, 2004 and 2003. Allsuch reserves are located in the Green River Basin, Wyoming andBohai Bay, China.
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****     B.*****ANALYSES OF CHANGES IN PROVEN RESERVES:***                           **United States** **China** **Total**           **Natural Gas**   **Natural**   **Natural Gas**  **Oil (Bbls)** **(Mcf)** **Oil (Bbls)** **Gas (Mcf)** **Oil (Bbls)** **(Mcf)**                 Reserves, December 31, 2002  5,559,000   667,121,000   —   —   5,559,000   667,121,000                        Extensions, discoveries and additions  2,894,700   361,298,700   —   —   2,894,700   361,298,700     Production  (211,600)  (27,621,800)  —   —   (211,600)  (27,621,800)    Revisions  100,400   22,569,400   —   —   100,400   22,569,400                        Reserves, December 31, 2003  8,342,500   1,023,367,300   —   —   8,342,500   1,023,367,300                        Extensions, discoveries and additions  4,520,000   562,548,000   8,180,900   —   12,700,900   562,548,000     Production  (349,700)  (43,667,400)  (624,560)  —   (943,000)  (43,667,400)    Revisions  (1,123,700)(1)  (128,247,300)(2)  31,228   —   (1,123,700)  (128,247,300)                       Reserves, December 31, 2004  11,389,100   1,414,000,600   7,587,600   —   18,976,700   1,414,000,600                        Extensions, discoveries and additions  5,516,300   680,671,500   370,600   —   5,886,900   680,671,500     Production  (464,300)  (61,722,300)  (1,556,300)  —   (2,020,600)  (61,722,300)    Revisions  (1,236,400)(3)  (132,727,000)(4)  (1,341,000)  —   (2,577,400)  (132,727,000)                       Reserves, December 31, 2005  15,204,700   1,900,222,800   5,060,900   —   20,265,600   1,900,222,800                        Proved developed reserves:                            December 31, 2002  2,003,000   222,608,000   —   —   —   222,608,000                        December 31, 2003  3,028,000   359,072,000   —   —   —   359,072,000                        December 31, 2004  4,195,000   514,686,000   4,356,000   —   8,551,000   514,686,000                        December 31, 2005  5,087,000   635,591,000   2,484,000   —   7,571,000   635,591,000                     (1)     Revision amount of 936,500 attributable to 40 wells dropped    from PUD category replaced by more attractive wells. (2)     Revision amount of 117,064,000 associated with above 40    mentioned wells. (3)     Revision amount of 412,500 attributable to 26 wells dropped    from PUD category replaced by more attractive wells. (4)     Revision amount of 51,560,000 associated with above mentioned    26 wells.
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)****C.            *STANDARDIZED    MEASURE (US$000):***     The following table sets forth a standardized measure of theestimated discounted future net cash flows attributable to theCompany’s proved natural gas reserves. Natural gas priceshave fluctuated widely in recent years. The calculated weightedaverage sales prices utilized for the purposes of estimating theCompany’s proved reserves and future net revenues were$8.00, $5.46, and $5.59 per Mcf of natural gas atDecember 31, 2005, 2004 and 2003, respectively. Thecalculated weighted average oil price at December 31, 2005,2004, and 2003 for Wyoming was $60.81, $42.80 and 31.87respectively. The calculated weighted average crude oil price atDecember 31, 2005 and 2004 for China was a Duri price of$48.74 and $29.46, respectively. The future production anddevelopment costs represent the estimated future expenditures tobe incurred in developing and producing the proved reserves,assuming continuation of existing economic conditions. Futureincome tax expense was computed by applying statutory income taxrates to the difference between pretax net cash flows relatingto the Company’s proved reserves and the tax basis ofproved properties and available operating loss carryovers .               **United States** **China** **Total**           As of December 31, 2003                Future cash inflows $5,986,603  $—  $5,986,603     Future production costs  (1,171,314)  —   (1,171,314)    Future development costs  (358,811)  —   (358,811)    Future income taxes  (1,620,437)  —   (1,620,437)              Future net cash flows  2,836,041   —   2,836,041     Discounted at 10%  (1,700,528)  —   (1,700,528)              Standardized measure of discounted future net cash flows $1,135,513  $—  $1,135,513               As of December 31, 2004 Future cash inflows $8,213,061  $223,531  $8,436,592     Future production costs  (1,699,891)  (67,387)  (1,767,278)    Future development costs  (623,539)  (18,382)  (641,921)    Future income taxes  (1,988,387)  (21,436)  (2,009,823)              Future net cash flows  3,901,244   116,326   4,017,570     Discounted at 10%  (2,285,779)  (62,455)  (2,348,234)              Standardized measure of discounted future net cash flows $1,615,465  $53,871  $1,669,336               As of December 31, 2005 Future cash inflows $16,124,248  $246,666  $16,370,914     Future production costs  (2,943,364)  (72,920)  (3,016,284)    Future development costs  (1,113,618)  (6,815)  (1,120,433)    Future income taxes  (4,110,554)  (30,235)  (4,140,789)              Future net cash flows  7,956,712   136,696   8,093,408     Discounted at 10%  (4,454,628)  (62,286)  (4,516,914)              Standardized measure of discounted future net cash flows $3,502,084  $74,410  $3,576,494           
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)**     The estimate of future income taxes is based on the future netcash flows from proved reserves adjusted for the tax basis ofthe oil and gas properties but without consideration of generaland administrative and interest expenses.**     D.*****SUMMARY OF CHANGES IN THE STANDARDIZED MEASURE OF    DISCOUNTED FUTURE NET CASH FLOWS (US$000):***               **December 31,** **December 31,** **December 31,**  **2005** **2004** **2003**           Standardized measure, beginning $1,669,336  $1,135,513  $316,965     Net revisions  (436,425)  (245,950)  41,715     Extensions, discoveries and other changes  2,306,982   1,062,236   680,136     Changes in future development costs  (130,727)  (123,051)  (10,603)    Sales of oil and gas, net of production costs  (426,891)  (216,670)  (96,357)    Net change in prices and production costs  1,992,707   2,645   605,892     Development costs incurred during the period that reduce future    development costs  172,962   96,220   8,886     Accretion of discount  254,236   178,431   47,353     Net change in income taxes  (1,825,686)  (220,038)  (458,474)              Standardized measure, ending $3,576,494  $1,669,336  $1,135,513                There are numerous uncertainties inherent in estimatingquantities of proved reserves and projected future rates ofproduction and timing of development expenditures, includingmany factors beyond the control of the Company. The reserve dataand standardized measures set forth herein represent onlyestimates. Reserve engineering is a subjective process ofestimating underground accumulations of oil and gas that cannotbe measured in an exact way and the accuracy of any reserveestimate is a function of the quality of available data and ofengineering and geological interpretation and judgment. As aresult, estimates of different engineers often vary. Inaddition, results of drilling, testing and production subsequentto the date of an estimate may justify revision of suchestimates. Accordingly, reserve estimates are often differentfrom the quantities of oil and gas that are ultimatelyrecovered. Further, the estimated future net revenues fromproved reserves and the present value thereof are based uponcertain assumptions, including geologic success, prices, futureproduction levels and costs that may not prove correct overtime. Predictions of future production levels are subject togreat uncertainty, and the meaningfulness of such estimates ishighly dependent upon the accuracy of the assumptions upon whichthey are based. Historically, oil and gas prices have fluctuatedwidely.**     E.*****COSTS INCURRED IN OIL AND GAS EXPLORATION AND DEVELOPMENT    ACTIVITIES (US$000):****UNITED STATES*               **Years Ended**     **December 31,** **December 31,** **December 31,**  **2005** **2004** **2003**           Acquisition costs — unproved properties $775  $1,268  $1,603     Exploration  56,894   97,068   55,095     Development  208,173   82,646   43,111               Total $265,842  $180,982  $99,809           
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)***CHINA*               **Years Ended**     **December 31,** **December 31,** **December 31,**  **2005** **2004** **2003**           Acquisition costs — unproved properties $2,876  $2,351  $16,027     Exploration  —   —   —     Development  16,465   12,657   —               Total $19,341  $15,008  $16,027           *TOTAL*               **Years Ended**     **December 31,** **December 31,** **December 31,**  **2005** **2004** **2003**           Acquisition costs — unproved properties $3,651  $3,619  $17,630     Exploration  56,894   97,068   55,095     Development  224,638   95,303   43,111               Total $285,183  $195,990  $115,836           **     F.*****RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES    (US$000):****UNITED STATES*               **Years Ended**     **December 31,** **December 31,** **December 31,**  **2005** **2004** **2003**           Oil and gas revenue $448,731  $238,867  $121,581     Production expenses and taxes  (78,861)  (47,574)  (25,224)    Depletion and depreciation  (48,456)  (27,346)  (16,216)    Deferred income taxes  (107,916)  (53,406)  (25,254)              Total $213,498  $110,541  $54,887           *CHINA*               **Years Ended**     **December 31,** **December 31,** **December 31,**  **2005** **2004** **2003**           Oil and gas revenue $67,762  $20,180  $—     Production expenses and taxes  (10,740)  (3,295)  —     Depletion and depreciation  (9,648)  (2,903)  —     Deferred income taxes  (15,556)  (4,604)  —               Total $31,818  $9,378  $—           
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**ULTRA PETROLEUM CORP****NOTES TO CONSOLIDATED FINANCIALSTATEMENTS — (Continued)***TOTAL*               **Years Ended**     **December 31,** **December 31,** **December 31,**  **2005** **2004** **2003**           Oil and gas revenue $516,493  $259,047  $121,581     Production expenses and taxes  (89,601)  (50,869)  (25,224)    Depletion and depreciation  (58,104)  (30,249)  (16,216)    Deferred income taxes  (123,472)  (58,010)  (25,254)              Total $245,316  $119,919  $54,887           **     G.*****CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING    ACTIVITIES:***            **December 31,** **December 31,**  **2005** **2004**         Developed Properties:             Acquisition, equipment, exploration, drilling and environmental    costs — Domestic $700,425,880  $435,095,908      Acquisition, equipment, exploration, drilling and environmental    costs — China  43,890,413   24,552,316      Less accumulated depletion, depreciation and    amortization — Domestic  (118,172,467)  (70,597,411)     Less accumulated depletion, depreciation and    amortization — China  (13,183,036)  (3,255,887)          612,960,790   385,794,926     Unproven Properties:             Acquisition and exploration costs — Domestic  17,647,300   16,910,010      Acquisition and exploration costs — China  72,055,165   71,929,450          $702,663,255  $474,634,386        
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**Item 9.*****Change in and Disagreements with Accountants on Accounting    and Financial Disclosures.***     None.**Item 9A.*****Controls and Procedures.*****(a)****Evaluation of Disclosure Controls and Procedures**     The Company maintains disclosure controls and procedures (asdefined inRules 13a-15(e)and 15d-15(e) under theSecurities Exchange Act of 1934) designed to ensure thatinformation required to be disclosed in the Company’sreports under the Securities Exchange Act of 1934, as amended(“Exchange Act”), is recorded, processed, summarizedand reported within the time periods specified in the SEC’srules and forms and that such information is accumulated andcommunicated to management, including the Company’s ChiefExecutive Officer and Chief Financial Officer, as appropriate,to allow timely decisions regarding required disclosure. Indesigning and evaluating the disclosure controls and procedures,management recognizes that any controls and procedures, nomatter how well designed and operated, can provide onlyreasonable assurance of achieving the desired control objectives.     In connection with the preparation of this Annual Report onForm 10-K, an evaluation was performed under thesupervision and with the participation of the Company’smanagement, including the CEO and CFO, of the effectiveness ofthe design and operation of the Company’s disclosurecontrols and procedures. Based on that evaluation, theCompany’s CEO and CFO concluded that the Company’sdisclosure controls and procedures were not effective as ofDecember 31, 2005, because of the material weaknessesdescribed below.**(b)****Management’s Report on Internal Control Over Financial    Reporting**     Management is responsible for establishing and maintainingadequate control over financial reporting for the Company assuch term is defined in Rules 13a-15(f) and 15d-15(f)promulgated under the Securities Exchange Act of 1934. In orderto evaluate the effectiveness of internal control over financialreporting, as required by Section 404 of the Sarbanes-OxleyAct, management has conducted an assessment using the criteriain *Internal Control — Integrated Framework,*issued by the Committee of Sponsoring Organizations of theTreadway Commission (COSO). Because of its inherent limitations,internal control over financial reporting may not prevent ordetect misstatements.     A material weakness is a control deficiency or combination ofcontrol deficiencies that results in a more than a remotelikelihood that a material misstatement of the annual or interimfinancial statements will not be prevented or detected. As ofDecember 31, 2005, the Company identified the followingmaterial weaknesses: •     The Company did not maintain effective company level controls.    Specifically, (i) certain of its accounting personnel in    key roles did not possess an appropriate level of technical    expertise, and (ii) the Company’s monitoring of the    internal audit function was not sufficient to provide management    a basis to assess the quality of the Company’s internal    control performance over time. These deficiencies resulted in    more than a remote likelihood that a material misstatement of    the Company’s annual or interim financial statements would    not be prevented or detected.  •     The Company did not have adequate policies and procedures    regarding supervisory review of account reconciliations and    account and transaction analyses. This deficiency resulted in    the following material errors in the Company’s preliminary    2005 consolidated financial statements: •     misclassification of costs between proved and unproved oil and    gas properties and understatement of depletion expense;  •     improper reporting of value added taxes;  •     understatement of asset retirement obligations;  •     overstatement in tubular inventory;  •     understatement of capitalized well cost accrued liabilities; and
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 •     overstatement of accounts receivable.     These errors have been corrected by management prior to the    issuance of the Company’s 2005 consolidated financial    statements. •     The Company did not have adequate policies and procedures to    ensure that accurate and reliable interim and annual    consolidated financial statements were prepared and reviewed on    a timely basis. Specifically, the Company did not have: •     sufficient personnel with the skills and experience in the    application of U.S. generally accepted accounting principles; and  •     policies and procedures regarding the preparation and management    review of footnote disclosures accompanying the Company’s    financial statements.     As a result of these deficiencies, material errors were    identified in the footnotes to the Company’s preliminary    2005 consolidated financial statements. These errors have been    corrected by management prior to the issuance of the    Company’s 2005 consolidated financial statements.     As a result of the aforementioned material weaknesses,management has concluded that the Company did not maintaineffective internal control over financial reporting as ofDecember 31, 2005, based on the criteria in *InternalControl — Integrated Framework*issued by the COSO.     The Company’s independent registered public accountants,KPMG LLP, have audited and issued a report on management’sassessment of the Company’s internal control over financialreporting, which report appears herein.**(c)****Changes in Internal Control Over Financial Reporting**     Management has evaluated, with the participation of our ChiefExecutive Officer and Chief Financial Officer, whether anychanges in our internal control over financial reporting thatoccurred during our last fiscal quarter have materiallyaffected, or are reasonably likely to materially affect, ourinternal control over financial reporting. Based on theevaluation we conducted, management has concluded that no suchchanges have occurred.     The Company’s management has identified what it believesare the steps necessary to address the material weaknessdescribed above, as follows:          (1) Increasing training for the Company’s current    accounting personnel, hiring additional accounting personnel and    engaging outside consultants with technical accounting    expertise, as needed, and reorganizing the accounting department    to ensure that accounting personnel have adequate experience,    skills and knowledge relating to the accounting and internal    audit functions assigned to them.           (2) Establishing additional and refining current policies    and procedures to more effectively reconcile its accounting    entries along with better documentation procedures to meet the    standards established by COSO.     The Company expects to complete these remedial actions by theend of the second quarter of 2006.**(d)****Report of Independent Registered Public Accounting Firm**The Board of Directors and ShareholdersUltra Petroleum Corp.:     We have audited management’s assessment, included in theaccompanying Management’s Report on Internal Control OverFinancial Reporting (Item 9A(b)), that Ultra PetroleumCorp. and subsidiaries (the Company) did not maintain effectiveinternal control over financial reporting as ofDecember 31, 2005, because of the effect of materialweaknesses identified in management’s assessment, based oncriteria established in *Internal Control —Integrated Framework*issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO). Ultra PetroleumCorp.’s management is responsible for
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maintaining effective internal control over financial reportingand for its assessment of the effectiveness of internal controlover financial reporting. Our responsibility is to express anopinion on management’s assessment and an opinion on theeffectiveness of the Company’s internal control overfinancial reporting based on our audit.     We conducted our audit in accordance with the standards of thePublic Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtainreasonable assurance about whether effective internal controlover financial reporting was maintained in all materialrespects. Our audit included obtaining an understanding ofinternal control over financial reporting, evaluatingmanagement’s assessment, testing and evaluating the designand operating effectiveness of internal control, and performingsuch other procedures as we considered necessary in thecircumstances. We believe that our audit provides a reasonablebasis for our opinion.     A company’s internal control over financial reporting is aprocess designed to provide reasonable assurance regarding thereliability of financial reporting and the preparation offinancial statements for external purposes in accordance withgenerally accepted accounting principles. A company’sinternal control over financial reporting includes thosepolicies and procedures that (1) pertain to the maintenanceof records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of thecompany; (2) provide reasonable assurance that transactionsare recorded as necessary to permit preparation of financialstatements in accordance with generally accepted accountingprinciples, and that receipts and expenditures of the companyare being made only in accordance with authorizations ofmanagement and directors of the company; and (3) providereasonable assurance regarding prevention or timely detection ofunauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on thefinancial statements.     Because of its inherent limitations, internal control overfinancial reporting may not prevent or detect misstatements.Also, projections of any evaluation of effectiveness to futureperiods are subject to the risk that controls may becomeinadequate because of changes in conditions, or that the degreeof compliance with the policies or procedures may deteriorate.     A material weakness is a control deficiency, or combination ofcontrol deficiencies, that results in more than a remotelikelihood that a material misstatement of the annual or interimfinancial statements will not be prevented or detected. Thefollowing material weaknesses have been identified and includedin management’s assessment as of December 31, 2005: •     The Company did not maintain effective company level controls.    Specifically, (i) certain of its accounting personnel in    key roles did not possess an appropriate level of technical    expertise, and (ii) the Company’s monitoring of the    internal audit function was not sufficient to provide management    a basis to assess the quality of the Company’s internal    control performance over time. These deficiencies resulted in    more than a remote likelihood that a material misstatement of    the Company’s annual or interim financial statements would    not be prevented or detected.  •     The Company did not have adequate policies and procedures    regarding supervisory review of account reconciliations and    account and transaction analyses. This deficiency resulted in    the following material errors in the Company’s preliminary    2005 consolidated financial statements: •     misclassification of costs between proved and unproved oil and    gas properties and understatement of depletion expense;  •     improper reporting of value added taxes;  •     understatement of asset retirement obligations;  •     overstatement in tubular inventory;  •     understatement of capitalized well cost accrued liabilities; and  •     overstatement of accounts receivable.
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 •     The Company did not have adequate policies and procedures to    ensure that accurate and reliable interim and annual    consolidated financial statements were prepared and reviewed on    a timely basis. Specifically, the Company did not have: •     sufficient personnel with the skills and experience in the    application of U.S. generally accepted accounting principles; and  •     policies and procedures regarding the preparation and management    review of footnote disclosures accompanying the Company’s    financial statements.     As a result of these deficiencies, material errors wereidentified in the footnotes to the Company’s preliminary2005 consolidated financial statements.     We also have audited, in accordance with the standards of thePublic Company Accounting Oversight Board (United States), theconsolidated balance sheets of Ultra Petroleum Corp. andsubsidiaries as of December 31, 2005 and 2004, and therelated consolidated statements of operations and retainedearnings, shareholders’ equity and cash flows for each ofthe years in the three-year period ended December 31, 2005.The aforementioned material weaknesses were considered indetermining the nature, timing, and extent of audit testsapplied in our audit of the December 31, 2005 consolidatedfinancial statements, and this report does not affect our reportdated March 30, 2006, which expressed an unqualifiedopinion on those consolidated financial statements.     In our opinion, management’s assessment that UltraPetroleum Corp. and subsidiaries did not maintain effectiveinternal control over financial reporting as ofDecember 31, 2005, is fairly stated, in all materialrespects, based on criteria established in *InternalControl — Integrated Framework*issued by theCommittee of Sponsoring Organizations of the Treadway Commission(COSO). Also, in our opinion, because of the effect of thematerial weaknesses described above on the achievement of theobjectives of the control criteria, Ultra Petroleum Corp. andsubsidiaries have not maintained effective internal control overfinancial reporting as of December 31, 2005, based oncriteria established in *Internal Control —Integrated Framework*issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO)./s/ KPMG LLPDenver, ColoradoMarch 30, 2006**Item 9B.*****Other Information.***     None.**Part III****Item 10.*****Directors and Executive Officers of the Registrant.***     The information required by this item will be included in theCompany’s definitive proxy statement, which will be filednot later than 120 days after December 31, 2005 and isincorporated herein by reference.     The Company has adopted a code of ethics that applies to theCompany’s Chief Executive Officer, Chief FinancialOfficer and Chief Accounting Officer. The full text of such codeof ethics has been posted on the Company’s website atwww.ultrapetroleum.com, and is available free of charge in printto any shareholder who requests it. Requests for copies shouldbe addressed to the Secretary at 363 North Sam HoustonParkway East, Suite 1200, Houston, Texas 77060.
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**Item 11.*****Executive Compensation.***     The information required by this item will be included in theCompany’s definitive proxy statement, which will be filednot later than 120 days after December 31, 2005 and isincorporated herein by reference.**Item 12.*****Security Ownership of Certain Beneficial Owners and    Management and Related Stockholder Matters.***     The information required by Item 403 ofRegulation S-Kwill be included in the Company’s definitive proxystatement, which will be filed not later than 120 daysafter December 31, 2005 and is incorporated herein byreference.**Item 13.*****Certain Relationships and Related Transactions.***     The information required by this item will be included in theCompany’s definitive proxy statement, which will be filednot later than 120 days after December 31, 2005, andis incorporated herein by reference.**Item 14.*****Principal Accountants Fees and Services.***     The information required by this item will be included in theCompany’s definitive proxy statement, which will be filednot later than 120 days after December 31, 2005, andis incorporated herein by reference.**Part IV****Item 15.*****Exhibits, Financial Statement Schedules, and Reports on    Form 8-K.***     The following documents are filed as part of this report:          1. *Financial Statements:* See 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.     **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     Fourth Amendment to Second Amended and Restated Credit    Agreement, dated as of November 14, 2005 and effective as    of November 18, 2005, by and among Ultra Resources, Inc.,    JPMorgan Chase Bank N.A., Union Bank of California N.A.,    Hibernia National Bank, Guaranty Bank FSB, Compass Bank, Bank of    Scotland and Bank of America, N.A. (incorporated by reference    from Exhibit 10.1 of the Company’s Report on    Form 8-K filed on November 23, 2005)  10.2     Third Amendment to Second Amended and Restated Credit Agreement    dated May 5, 2005 among Ultra Resources, Inc., JPMorgan    Chase Bank N.A., Union Bank of California N.A., Hibernia    National Bank, Guaranty Bank FSB, Compass Bank, Bank of Scotland    and Bank of America, N.A. (incorporated by reference from    Exhibit 10.1 of the Company’s Quarterly Report on    Form 10-Q for the period ended June 30, 2005)
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     **Exhibit**  **Number** **Description**    10.3     Second Amendment to Second Amended and Restated Credit Agreement    dated November 1, 2004 among Ultra Resources, Inc., Bank    One, NA, Union Bank of California, N.A., Hibernia National Bank,    Guaranty Bank, FSB, Compass Bank, Bank of Scotland and Fleet    National Bank. (incorporated by reference from Exhibit 10.1    of the Company’s Report on Form 10-K for the year    ended December 31, 2004)  10.4     First Amendment to Second Amended and Restated Credit Agreement    dated August 10, 2004 among Ultra Resources, Inc., Bank    One, NA, Union Bank of California, N.A., Hibernia National Bank,    Guaranty Bank, FSB, Compass Bank, Bank of Scotland and Fleet    National Bank. (incorporated by reference from Exhibit 10.2    of the Company’s Report on Form 10-K for the year    ended December 31, 2004)  10.5     Second Amended and Restated Credit Agreement dated June 9,    2004 among Ultra Resources, Inc., Bank One, NA, Union Bank of    California, N.A., Hibernia National Bank, Guaranty Bank, FSB,    Compass Bank, Bank of Scotland and Fleet National Bank    (incorporated by reference from Exhibit 10.1 of the    Company’s Quarterly Report on Form 10-Q for the period    ended June 30, 2004).  10.6     Precedent Agreement between Rockies Express Pipeline LLC and    Ultra Resources, Inc. dated December 19, 2005 (incorporated    by reference from Exhibit 10.1 of the Company’s Report    of Form 8-K filed on February 9, 2006)  10.7     Precedent Agreement between Rockies Express Pipeline LLC,    Entrega Gas Pipeline LLC and Ultra Resources, Inc. dated    December 19, 2005 (incorporated by reference from    Exhibit 10.2 of the Company’s Report on Form 8-K    filed on February 9, 2006)  10.8     Ultra Petroleum Corp. 2005 Stock Incentive Plan (incorporated by    reference from Exhibit 99.1 of the Company’s    Registration Statement on Form S-8 (Reg.    No. 333-132443), filed with the SEC on March 15, 2006)  10.9     Ultra Petroleum Corp. 2000 Stock Incentive Plan (incorporated by    reference from Exhibit 99.1 of the Company’s    Registration Statement on Form S-8 (Reg.    No. 333-13278), filed with the SEC on March 15, 2001)  10.10     Ultra Petroleum Corp. 1998 Stock Option Plan (incorporated by    reference from Exhibit 99.1 of the Company’s    Registration Statement on Form S-8 (Reg.    No. 333-13342) filed with the SEC on April 2, 2001) *10.11     Employment Agreement between Ultra Petroleum Corp. and Michael    D. Watford dated February 1, 2004.  14.1     Code of Ethics for Chief Executive Officer and Senior Financial    Officers of Ultra Petroleum Corp. (Incorporated by reference to    Exhibit 3.3 of the Company’s Annual Report on    Form 10-K for the year ended December 31, 2003)  21.1     Subsidiaries of the Company (incorporated by reference to    Exhibit 21.1 to the Company’s Annual Report on    Form 10-K for the period ended December 31, 2001)  *23.1     Consent of Netherland, Sewell & Associates, Inc.  *23.2     Consent of Ryder Scott Company  *23.3     Consent of KPMG LLP  *31.1     Certification of Chief Executive Officer and Chief Financial    Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002  *32.1     Certification of Chief Executive Officer and Chief Financial    Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 *     Filed herewith
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**SIGNATURES**     Pursuant to the requirements of Section 13 or 15(d) of theSecurities Exchange Act of 1934, the Registrant has duly causedthis report to be signed on its behalf by the undersigned,thereunto duly authorized.     ULTRA PETROLEUM CORP. By:     /s/ Michael D. Watford       Name: Michael D. Watford Title:    Chairman of the Board,     Chief Executive Officer, and PresidentDate: March 31, 2006     Pursuant to the requirements of the Securities Exchange Act of1934, this report has been signed below by the following personson behalf of the Registrant and in the capacities and on thedates indicated.       **Signature** **Title** **Date**                 /s/ Michael D.    Watford