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  **U.S. Securities And Exchange Commission****Washington, D.C. 20549****FORM 10-KSB**   þ **ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934****For the fiscal year ended August 31, 2005**   o **TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934****For the transition period from                     to                     ****Commission File No. 0-20879****PYR ENERGY CORPORATION**(Name of small business issuer in its charter)   Maryland 95-4580642   (State or jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)   1675 Broadway, Suite 2450, Denver, CO 80202   (Address of principal executive offices) (Zip Code)Registrant’s telephone number, including area code: (303) 825-3748Securities registered pursuant to Section 12(b) of the Act:   Title of each class Name of each exchange on which registered$.001 Par Value Common Stock American Stock ExchangeSecurities registered pursuant to Section 12(g) of the Act:None (Title of Class)     Indicate by check mark whether the registrant (1) has filed all reports required to be filedby Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (orfor such shorter period that the registrant was required to file such report), and (2) has beensubject to such filing requirements for the past 90 days. Yes þ No o     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of RegulationS-B (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best ofregistrant’s knowledge, in definitive proxy or information statements incorporated by reference inPart III of this Form 10-KSB or any amendment to this Form 10-KSB.     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12-b-2 ofthe Exchange Act). Yes o No þ     The registrant’s revenues for the fiscal year ended August 31, 2005 were $6.1 million. As ofNovember 15, 2005, the registrant had 37,968,259 common shares outstanding, and the aggregatemarket value of the common shares held by non-affiliates was approximately $32,972,306*. Thiscalculation is based upon the closing sale price of $1.22 per share on November 15, 2005. * Without asserting that any of the issuer’s directors or executive officers, or the entities thatown 10% or greater of the registrant’s shares of common stock are affiliates, the shares of whichthey are beneficial owners have been deemed to be owned by affiliates solely for this calculation.  
 

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**TABLE OF CONTENTS**       Page PART I  1      ITEM 1 and ITEM 2. DESCRIPTION OF BUSINESS AND PROPERTIES  1      ITEM 3. LEGAL PROCEEDINGS  19      ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS  20      PART II  20      ITEM 5. MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND SMALL BUSINESS ISSUER PURCHASES OF EQUITY SECURITIES  20      ITEM 6. MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS  21      ITEM 7. FINANCIAL STATEMENTS  27      ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.  28      ITEM 8A. CONTROLS AND PROCEDURES  28      ITEM 8B. OTHER INFORMATION  28      PART III  29      ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION 16(I) OF THE EXCHANGE ACT  29      ITEM 10. EXECUTIVE COMPENSATION  31      ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS  33      ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS  35      ITEM 13. EXHIBITS  36      ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES  36      SIGNATURES  38      CONSOLIDATED FINANCIAL STATEMENTS  F-1  Consent of HEIN & Associates LLP Consent of Ryder Scott Company Rule 13a-14(a) Certifications of CEO and CFO Certification Pursuant to 18 U.S.C. Section 1350
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**PART I****ITEM 1 and ITEM 2. DESCRIPTION OF BUSINESS AND PROPERTIES****General**     PYR Energy Corporation (referred to as “PYR,” the “Company,” “we,” “us” and “our”) is anindependent oil and gas exploration and production company, engaged in the exploration, developmentand acquisition of crude oil and natural gas reserves. The Company was incorporated in March 1996in the state of Delaware under the name Mar Ventures Inc. Effective as of August 6, 1997, theCompany purchased all the ownership interests of PYR Energy, LLC, an oil and gas explorationcompany. On November 12, 1997, the name of the Company was changed to PYR Energy Corporation.Effective July 2, 2001, the Company was re-incorporated in Maryland through the merger of theCompany into a wholly owned subsidiary, PYR Energy Corporation, a Maryland corporation. OnFebruary 18, 2004, PYR Cumberland LLC, PYR Mallard LLC, and PYR Pintail LLC were formed as whollyowned subsidiaries of PYR Energy Corporation. The purpose of these entities is to own and developcertain assets related to designated individual exploration projects.     Our current focus is on the Rocky Mountain, Texas and Gulf Coast regions as described below.During the fiscal years ended August 31, 2005 and 2004, we focused our exploration efforts on thedrilling phase of our high potential exploration projects in the Rocky Mountain and Gulf Coastregions.     The Company’s offices are located at 1675 Broadway, Suite 2450, Denver, Colorado 80202. Thetelephone number is (303) 825-3748, the facsimile number is (303) 825-3768 and the Company’s website is www.pyrenergy.com. The Company’s periodic and current reports filed with the Securities andExchange Commission (the “SEC”) can be found on the Company’s website at www.pyrenergy.com and onthe SEC’s website at www.sec.gov.PROPERTIES AND BUSINESS ACTIVITIES*Oil and Gas Exploration and Development Activities*     Our exploration and development activities are focused primarily in select areas of theRocky Mountains, Texas and the Gulf Coast. Advanced seismic imaging of the structural andstratigraphic complexities common to these regions provides us with the enhanced ability toidentify significant oil and gas reserve potential. A number of these projects offer multipledrilling opportunities with individual wells having the potential of encountering multiplereservoirs. We are currently producing over 3 million cubic feet of gas equivalent per day and are100% unhedged.     The following is a summary of our exploration and development areas and significant projects.While actively pursuing specific exploration activities in each of the following areas, wecontinually review additional opportunities in these core areas and in other areas that meet ourexploration criteria.     Texas and Gulf Coast Exploration:     In May 2004, we acquired interests from Venus Exploration, Inc. (“Venus”) in certainproducing properties with estimated proved reserves of 4.78 Bcfe for approximately $3.3 million(excluding acquisition expenses and subject to retention, by the Venus Exploration Trust (“Trust”),of a net profits interest covering specific exploration projects). This equated to $0.67 per Mcf,with a PV-10 value of $6.94 million. The net profits interest that we are required to pay to theTrust, which applies only to the exploration and exploitation projects on the Venus acreageacquired, varies from 25% to 50% with respect to different Venus exploration and exploitationproject areas, and decreases by one-half of its original amount after a total of $3.3 million innet profits proceeds has been paid to the Trust. Venus was in Chapter 11 Bankruptcy, and weacquired the properties through public auction as approved by the United States Bankruptcy Court.To finance the purchase, we primarily used existing cash reserves and a portion of the proceedsfrom a private placement of common stock.     Oil and gas interests acquired from Venus include producing oil and gas properties,exploitation drilling projects, and exploration acreage. The assets acquired include interests in80 non-operated wells in Utah, Oklahoma and Texas.
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     In Texas, we have interests in three wells that were drilled and completed during the summerof 2004. Two of the three wells, located in the Nome and Madison Prospects, were completed asproducers and are currently flowing to sales lines. Both wells reached payout resulting in ourworking interest being put into pay status. These two successful wells are subject to a netprofits interest agreement with the Venus Exploration Trust. The third well was not commerciallyproductive. This well is currently being re-evaluated.     *Nome Field* was discovered in 1994, and our interpretation of subsequently acquired 3Dseismic over the field indicates the presence of numerous undeveloped fault blocks. Multiplestructural closures and associated bright spot locations have been identified at Nome based on the3D seismic. Production in the Sun Fee GU #1-ST well (the “Sun Fee Well”), from the upper Yegua,was initiated in late May 2004, and beginning in early June 2005, averaged approximately 19MMcfeper day. Cumulative production since inception is in excess of 6.4 Bcfe through end of August,2005. When the well reached payout on October 13, 2004, PYR was placed in pay status as a workinginterest participant in the well. Based on pooling of lands into the Sun Fee Gas Unit by theoperator, our current working interest in the well and associated lands is 5.19% with a 1.5%overriding royalty interest. We and our partners control approximately 4,200 acres of grossleasehold acres in the project. A drilling AFE has been circulated and approved for the drillingof a well (Tindall #1) offsetting by approximately 1600 feet, the Sun Fee GU #1-ST. It isanticipated that this development well will be drilled in early 2006. Our working interest in theTindall #1 is currently 77.08%.     We are currently in litigation with the operator of the Sun Fee Well, Samson Lone Star L.P.(“Samson”), concerning, among other matters, Samson’s pooling of certain lands into the productionunit and corresponding reduction in PYR’s working interest. The outcome of the litigation willdetermine whether PYR owns a 5.19% working interest and 1.5% overriding royalty interest, as arisesfrom Samson’s unit pooling, or an 8.33% working interest and an overriding royalty interest inexcess of 1.5%, in the Sun Fee well, as PYR believes it is entitled to. Even if we are notsuccessful in the litigation, the outcome will not result in a negative adjustment to our revenuesor production volumes because we have reported production and revenue only on the lower workinginterest and the lower royalty interest in our financial and operating statements to date.Additionally, this lower working interest and lower overriding royalty interest are undisputed, andit is only the difference between the 5.19% and 8.33% working interests and associated overridingroyalty interests that are the subject of the ongoing litigation.     Both our revenues and costs associated with the production from the Sun Fee Well, as well asour costs incurred on the Nome Project, are subject to the net profits interest agreement we holdwith Venus Exploration Trust (“Trust”). The net profits interest agreement arose out of ouracquisition of properties from Venus Exploration Inc. (“Venus”) in May 2004. The net profitinterest under the agreement varies from 25% to 50% with respect to different Venus exploration andexploitation project areas, and decreases by one-half of its original amount after a total of $3.3million in net profits proceeds has been paid to the Trust. The amount of net profits interestliability recognized over time is subject to fluctuation, because both revenues and costsassociated with production from any wells and other costs incurred on the designated explorationand exploitation project areas will increase or decrease over a given period of time.     *Madison prospect*, located in the northern part of the Constitution Field,Jefferson County, Texas, is an exploitation project to test multiple sand intervals within theexpanded Yegua section, downthrown to a major growth fault. The Maness GU #1 well startedproduction in mid-August 2004, and since inception, the well has cumulative production in excess of1.7 Bcfe, through end of August, 2005. Payout has been reached in the Maness GU #1 well, and PYRhas been placed in pay status with a 12.5% working interest. The well is currently producing at arate of approximately 5.60 MMcfe per day The operator has converted an existing well bore withinthe project area into a water disposal well, and is planning to drill an offset development well(Wall#1) in late 2005 or early 2006 depending on rig availability. We will participate for 12.5%working interest in the drilling of this development well. Wells drilled in this prospect aresubject to a net profits interest agreement with the Venus Exploration Trust.     *Tortuga Grande prospect*, located in Smith County, Texas, is a project to test theproductivity of the Cotton Valley Sand section. The Chisum #1 well, operated by Carrizo Oil andGas Inc, is projected to a target depth of approximately 15,500 feet, and is designed to test apotentially thicker section of Cotton Valley Sand in a more favorable structural position to theBrady #1 well. As a result of certain parties in the well electing not to participate in thedrilling of the well, PYR exercised its rights to increase its working interest in the well to28.57% working interest. The Chisum #1 well reached total drilling depth of approximately 15,850feet. Log and core analysis of the Cotton Valley section revealed abundant sand
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thickness in the expanded ‘turtle’ section, but did not indicate commercial reservoirproperties. As a result, the operator recommended abandonment of the Cotton Valley section andcompletion of multiple horizons in the Travis Peak and Rodessa formations. The Company isparticipating in the completion of the Travis Peak and Rodessa with its 28.57% working interest.PYR and its partners control approximately 9,800 acres of leasehold in the project. Pendingfavorable results from the Chisum #1 completion, the Company anticipates drilling additional wellsto fully exploit the Travis Peak and Rodessa potential in the project area. Wells drilled in thisprospect are subject to a net profits interest agreement with the Venus Exploration Trust.     *Cotton Creek prospect*, located in Jefferson County, Texas, is adjacent to the Nomeproject. The prospect is located approximately one mile west of the productive Sun Fee #1 well inthe same structural fault block. PYR owns a 50% working interest in the project and controls withits partner approximately 500 acres of leasehold. It is anticipated that an initial test well willbe drilled in 2006. PYR will retain approximately 25% working interest in the well and intends tofarmout the remainder of its interest to an industry partner.     *Merganser prospect*, located in Leon County, Texas, targets Cotton Valley and Bossiersandstone reservoirs in an undrilled structural feature defined by 3D seismic data. The prospectoccupies a fault-bounded salt-withdrawal trough resulting in potential significant thickening ofthe Bossier and Cotton Valley sand sections. The prospect location is structurally andstratigraphically downdip from Cotton Valley production as well as updip from recent Bossierproductive discoveries. PYR owns 100% of approximately 300 acres in the prospect.     *Bayou Duralde Project*, located in Evangeline Parish, LA, is an exploration program toidentify and drill potential gas reservoirs in Yegua/Cockfield channel complexes. PYR owns a 25%working interest in the project and controls, along with its partner, in excess of 3,000 net acresof leasehold. PYR intends to participate with a 15% cost bearing interest and farmout theremainder of its working interest. It is anticipated that the initial test well at Bayou Duraldewill begin drilling operations in late 2005 or early 2006 depending on rig availability.     Atthe *Wilburton Field* in Latimer County, Oklahoma, theScharff #4-1 well was recently drilledand completed in the Lower Atoka (Cecil) formation, which resulted in initialproduction rates of up to 38 MMcf per day and is currently producing at an average rate ofapproximately 19 MMcfe per day. The Scharff #5-1 well, an offset of the Scharff #4-1, commenceddrilling activity on September 13, 2005, and reached total drilling depth in early November 2005.The Scharff #5-1 is currently undergoing completion activities, and is expected to be on-line bythe end of the calendar year. The operator has proposed drilling of an additional PUD location(Scharff #6-1) which the Company has approved and will participate in the drilling of. PYR has a2.42% working interest in these wells.     *Hansford Project,* located in Hansford County of the Texas panhandle, is a developmentproject at the southern end of the Houghton Embayment. Main producing horizons within the Hansfordarea include the upper and lower Morrow as well as the Chester. Purchased originally as part ofthe Venus Exploration acquisition, the Company has recently purchased additional working interestin two wells and associated undeveloped acreage at Hansford. Approximately 47% working interest inthe Lackey #152-1 well and acreage, as well as 15% working interest in the Archer Trust well andacreage, were purchased for approximately $440,000. The Company believes that several provedundeveloped drilling opportunities targeting gas are available on the acreage that was purchased atHansford. Drilling was commenced on the Lackey Gas Unit #2, a provedundeveloped location, on October 23, 2005.The well has been drilled to total depth and is currently undergoing completion operations. TheCompany has a 47.16% working interest in this well. The Company continues to attempt to acquireadditional working interest, acreage and operational control in the project area.     Rocky Mountain Exploration     *Mallard Project**.*The 1-30 Duck Federal Sidetrack well commenced drilling inmid-July 2004 and was temporarily suspended, due to winter drilling restrictions, in December 2004.The wellbore was re-entered in early August 2005, and reached a total measured depth of 15,110’on October 18, 2005 within the Lodgepole Formation. Based on analysis of drilling shows, open-holelogs, and reservoir pressure measurements, the working interest partners decided to attempt acompletion of the well within the objective Mission Canyon Formation.Casing has been run to total depth,and the well has been perforate over the prospective zones, covering a gross interval ofapproximately 900 feet. Following perforation, it is anticipated that we will employ an acidstimulation treatment to clean up the formation and enhance productivity. The acid stimulationwill be similar to
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that commonly employed in other field wells within the Whitney Canyon-Carter Creek Field. Weexpect to commence testing in late November, pending scheduling of necessary equipment andpersonnel. The Mission Canyon is the primary producing zone within the nearby WhitneyCanyon-Carter Creek Field, which has produced over 2.1 Tcfe to date. It is believed that the 1-30Duck Federal well has encountered the Whitney Canyon-Carter Creek accumulation, and likelyrepresents a development step out well. It is anticipated that PYR and the working interestpartners will acquire approximately 20 square miles of 3-D seismic data during the summer of 2006in order to better delineate additional drilling opportunities in the area. PYR is participatingin the project with a 28.75% working interest.     *Ryckman Creek Project**.*We have leased approximately 1,820 net acres, covering themajority of the abandoned Ryckman Creek field, in the Overthrust region of southwestern Wyoming.Ryckman Creek, located 5 miles southwest of our Cumberland prospect, was discovered in 1975 andproduced approximately 250 Bcfe prior to abandonment. We believe that significant remainingrecoverable gas reserves were stranded in Ryckman Creek upon abandonment. We are currentlyanalyzing production and geologic data to determine potential reserves in multiple zones, includingthe Twin Creek, Nugget, and Thaynes Formations, in the field. Due to rig availability timing, itis anticipated that re-development activity of the Ryckman Creek project will not occur untilsometime in 2006.     *Montana Foothills Project**.*Following the plugging and abandonment of the 14063-12Flesher Pass exploratory well in August 2005, Suncor Energy Natural Gas America, Inc. (SENGAI), theproject operator, has informed the Company that they do not intend to exercise their option todrill an additional earning well on the acreage block. The Company is re-evaluating explorationprospects associated with its undeveloped acreage in the project.     OTHER      *San Joaquin Basin, California*          *Blizzard Prospect.* This project is a 3D seismic derived exploration andexploitation program offsetting the Rio Viejo field at the south end of the San Joaquin Basin. Alinear sand body, stratigraphically higher than any of the productive Rio Viejo sands, has beenidentified, north of the field, on the seismic data and represents an exploration opportunity fornew reserves. Additionally, analysis of the seismic data over the field suggests that up to twoadditional undrilled field exploitation locations may exist. PYR owns 100% of the prospect.          *Bulldog Prospect*. This project is a 2D seismically identified natural gas andcondensate prospect located adjacent to the giant Kettleman North Dome field in the San JoaquinBasin. This prospect can be best characterized as a classic footwall fault trap, similar to themany known footwall fault trap accumulations that have produced significant quantities ofhydrocarbons throughout the San Joaquin basin. We intend to sell down our working interest in thisproject and retain a 25% to 50% working interest in the prospect acreage.          *Wedge Prospect*. This is a seismically identified Temblor prospect located northwestof and adjacent to the East Lost Hills deep gas discovery. During the first fiscal quarter of2001, we acquired approximately 17 miles of proprietary, high effort 2D seismic data and combinedthis data with existing 2D seismic data in order to refine what we interpret as the up-dipextension of the East Lost Hills structure. Our seismic interpretation shows that the same trendat East Lost Hills extends approximately ten miles farther northwest of the East Lost Hills Area ofMutual Interest and can be encountered as much as 3,000 feet higher. Our approach is to sell downour working interest to industry partners, and retain a 25% to 50% working interest in thisprospect.     *Canada*          The Company’s Canadian oil and gas property investment is comprised principally ofnon-producing acreage. During 2005, the Company decided to limit future expenditures in Canada.The net book value of the Company’s investment in its Canadian properties was greater than theestimated fair market value. In accordance with the full cost method of accounting, the Companyrecorded a non-cash impairment of $580,000, an amount equal to the Company’s initial investment inits Canadian oil and gas properties.
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**Markets and Major Customers**     Sales from our ownership interests in producing properties to major unaffiliated customers(customers accounting for 10 percent or more of gross revenue), all representing purchasers of oiland gas, for the years ended August 31, 2005 and 2004 are as follows:           2005 2004Customer A  38%    Customer B  22%    Customer C  10%    Customer D      22%Customer E      20%Customer F      16%Customer G      13%     The May 2004 acquisition of interests in certain producing properties from Venus Exploration,Inc. resulted in the increase of oil and gas purchasers. We are not confined to, nordependent upon, any one purchaser or small group of purchasers. Accordingly, the loss of a singlepurchaser would not materially affect the Company’s business because we believe we would be able tofind another purchaser.**Employees and Office Space**     At August 31, 2005, we had nine full time employees. We believe that our relationship withour employees is satisfactory. None of our employees is covered by a collective bargainingagreement. We lease approximately 3,800 square feet of office space in Denver, Colorado for ourexecutive and administrative offices. We have an additional office in San Antonio, Texas, in whichwe lease approximately 4,300 square feet.**Business Strategy**     Our objective is to increase stockholder value per share by adding reserves, production, cashflow, earnings and net asset value. To accomplish this objective, we intend to develop our provedundeveloped locations and to capitalize on our technical expertise in identifying, evaluating andparticipating in the exploratory drilling and development of deep, structurally complex formations.We also intend to build on our experience and our competitive strengths, which include: **•** our inventory of Texas and Rocky Mountain development and exploration projects,  **•** our control of pre-drill exploration phases,  **•** our expertise in advanced seismic imaging, and  **•** our ability to identify suitable development and exploitation drilling opportunities.To implement our strategy, we seek to: **•** *Execute Exploration and Development Drilling on Our UndrilledProjects**.*We control interests in several exploration projects in the Texas GulfCoast, select areas of the Rocky Mountains, and the San Joaquin Basin of California.In the Rocky Mountains, our most notable projects are Mallard and Ryckman Creek locatedin southwestern Wyoming. We are currently attempting completion of our Mallardproject. In the Texas Gulf Coast, we have interests in several exploration projectsand PUD (“Proved Undeveloped”) locations related to recent discoveries to be drilled inthe future. We are currently attempting completion of recently drilled wells at TortugaGrande and Hansford.
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 **•** *Continue to Internally Generate Exploration Prospects**.*We believethat by continuing to generate exploitation and exploration prospects with a specialemphasis on applying our seismic expertise to deep,structurally complex formations, we can identify prospects with significant oil andgas reserve potential. We then assemble acreage positions on these prospects. Thisenables us to control costs during the pre-drill phases of exploration and to sell aportion of our interests to industry participants, while potentially retaining acarried interest in the initial drilling.  **•** *Evaluate Low Risk, Shallow Exploitation and Development DrillingOpportunities**.*As part of our ongoing strategy, we are evaluating lower riskdrilling opportunities relative to our higher risk, internally generated, explorationprojects. If found to be appropriate, these opportunities can provide the Company withsuitable internal rates of return on investment, geographic and risk diversification,and exposure to reserves and potential cash flow. We continue to review and evaluateadditional development and exploitation opportunities as they arise.  **•** *Continue A Disciplined Acquisition Process.* As part of ourongoing strategy, we diligently look for properties or opportunities with significantupside in our core areas. Through our personal contacts, industry knowledge andexpertise, we look to find under-worked properties or missed structures, that withlittle cost, but strong operatorship, may be productive.**Certain Definitions**Unless otherwise indicated in this document, oil equivalents are determined using the ratio ofsix Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids so that sixMcf of natural gas are referred to as one barrel of oil equivalent.*AMI.*Area of Mutual Interest*Bbl.*One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oilor other liquid hydrocarbons.*Bbl/d*. One Bbl per day*Bc/d.*Barrels of condensate daily*Bcf*. One Billion cubic feet of natural gas at standard atmospheric conditions.*Bcfe*. One billion cubic feet equivalent of natural gas, calculated by converting oil toequivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.*Boe.*Barrels of oil equivalent, with six thousand cubic feet of natural gas beingequivalent to one barrel of oil.*Btu or British thermal unit*. The quantity of heat required to raise the temperature ofone pound of water by one degree Fahrenheit.*Capital Expenditures.*Costs associated with exploratory and development drilling (includingexploratory dry holes); leasehold acquisitions; seismic data acquisitions; geological,geophysical and land related overhead expenditures; delay rentals; producing propertyacquisitions; other miscellaneous capital expenditures; compression equipment and pipelinecosts.*Carried through the tanks.*The owner of this type of interest in the drilling of a wellincurs no liability for costs associated with the well until the well is drilled, completedand connected to commercial production/processing facilities.*Completion.*The installation of permanent equipment for the production of oil or naturalgas.*Condensate.*Liquid hydrocarbons associated with the production of a primarily naturalgas reserve.
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*Developed Acreage.*The number of acres that are allocated or assignable to producing wellsor wells capable of production.*Development Well.*A well drilled within the proved area of an oil or natural gas reservoirto the depth of a stratigraphic horizon known to be productive.*Exploitation.*The continuing development of a known producing formation in a previouslydiscovered field. To make complete or maximize the ultimate recovery of oil or natural gasfrom the field by work including development wells, secondary recovery equipment or othersuitable processes and technology.*Exploration.*The search for natural accumulations of oil and natural gas by anygeological, geophysical or other suitable means.*Exploratory Well.*A well drilled to find and produce oil or natural gas in an unprovedarea, to find a new reservoir in a field previously found to be productive of oil or naturalgas in another reservoir, or to extend a known reservoir.*Field.*An area consisting of either a single reservoir or multiple reservoirs, allgrouped on or related to the same individual geological structural feature and/orstratigraphic condition.*Finding and Development Costs.*The total capital expenditures, including acquisition costs,and exploration and abandonment costs, for oil and gas activities divided by the amount ofproved reserves added in the specified period.*Gross Acres or Gross Wells.*The total acres or wells, as the case may be, in which wehave a working interest.*Lease.*An instrument which grants to another (the lessee) the exclusive right to enter toexplore for, drill for, produce, store and remove oil and natural gas on the mineralinterest, in consideration for which the lessor is entitled to certain rents and royaltiespayable under the terms of the lease. Typically, the duration of the lessee’s authorizationis for a stated term of years and “for so long thereafter” as minerals are producing.*Mcf.*One thousand cubic feet of natural gas at standard atmospheric conditions.*Mcf/d.*One Mcf per day.*Mcfe.*One thousand cubic feet equivalent of natural gas, calculated by converting oil toequivalent Mcf at a ratio of 6 Mcf to 1 Bbl of oil.*MMcf.*One million cubic feet of natural gas.*Net Acres or Net Wells.*A net acre or well is deemed to exist when the sum of ourfractional ownership working interests in gross acres or wells, as the case may be, equalsone. The number of net acres or wells is the sum of the fractional working interests ownedin gross acres or wells, as the case may be, expressed as whole numbers and fractionsthereof.*Operator.*The individual or company responsible to the working interest owners for theexploration, development and production of an oil or natural gas well or lease.*Participant Group.*The individuals and/or companies that, together, comprise the ownershipof 100% of the working interest in a specific well or project.*PV-10 value.*The present value of estimated future revenues to be generated from theproduction of proved reserves calculated in accordance with SEC guidelines, net ofestimated lease operating expense, production taxes and future development costs, usingprices and costs as of the date of estimation without future escalation, without givingeffect to non-property related expenses such as general and administrative expenses, debtservice and depreciation, depletion and amortization or federal income taxes and discountedusing an annual discount rate of 10%.
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*Productive well.*A well that is found to be capable of producing hydrocarbons insufficient quantities such that proceeds from the sale of the production exceed productionexpenses and taxes.*Prospect.*A specific geographic area which, based on supporting geological, geophysicalor other data and also preliminary economic analysis using reasonably anticipated prices andcosts, is deemed to have potential for the discovery of commercial hydrocarbons.*Proved developed reserves.*Reserves that can be expected to be recovered through existingwells with existing equipment and operating methods.*Proved reserves*. The estimated quantities of oil, natural gas and natural gas liquidswhich geological and engineering data demonstrate with reasonable certainty to becommercially recoverable in future years from known reservoirs under existing economic andoperating conditions.*Proved undeveloped reserves (PUD).*Proved reserves that are expected to be recoveredfrom new wells on undrilled acreage or from existing wells where a relatively majorexpenditure is required for recompletion.*Re-entry.*Entering an existing well bore to redrill or repair.*Reserves.*Natural gas and crude oil, condensate and natural gas liquids on a net revenueinterest basis, found to be commercially recoverable.*Reservoir.*A porous and permeable underground formation containing a naturalaccumulation of producible natural gas and/ or oil that is confined by impermeable rock orwater barriers and is separate from other reservoirs.*Royalty.*An interest in an oil and natural gas lease that gives the owner of theinterest the right to receive a portion of the production from the leased acreage, or of theproceeds of the sale thereof, but generally does not require the owner to pay any portion ofthe costs of drilling or operating the wells on the leased acreage. Royalties may be eitherlandowner’s royalties, which are reserved by the owner of the leased acreage at the time thelease is granted, or overriding royalties, which are usually reserved by an owner of theleasehold in connection with a transfer to a subsequent owner.*Sidetrack.*An operation involving the use of a portion of an existing well to drilla second hole at some desired angle into previously undrilled areas. From this directionalstart, a new hole is drilled to the desired formation depth and casing is set in the newhole and tied back to the casing from the existing well.*3-D Seismic.*The method by which a three dimensional image of the earth’s subsurface iscreated through the interpretation of reflection seismic data collected over a surface grid.3-D seismic surveys allow for a more detailed understanding of the subsurface than doconventional surveys and contribute significantly to field appraisal, exploitation andproduction.*Undeveloped Acreage.*Lease acres on which wells have not been drilled or completed to apoint that would permit the production of commercial quantities of oil and gas regardless ofwhether or not such acreage contains proved reserves.*Working Interest.*An interest in an oil and gas lease that gives the owner of theinterest the right to drill and produce oil and gas on the leased acreage and requires theowner to pay a share of the costs of drilling and production operations. The share ofproduction to which a working interest owner is entitled will always be smaller than theshare of costs that the working interest owner is required to bear, with the balance of theproduction accruing to the owners of royalties.
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**Production and Productive Wells**     The following table summarizes the Company’s productive wells as of August 31, 2005.Productive wells are producing wells and wells capable of production. Gross wells are the totalnumber of wells in which the Company has an interest. Net wells are the sum of the Company’srespective fractional interests owned in the gross wells.**Productive Gas wells as of August 31, 2005**                           **Gross**         **Net**    **Location** **Oil** **Gas** **Total** **Oil** **Gas** **Total**Canada  —   1   1   —   0.05   0.05  California  3   —   3   0.24   —   0.24  Oklahoma  17   23   40   2.86   0.75   3.61  Texas  20   13   33   4.42   3.65   8.07  Utah  5   —   5   1.68   —   1.68                             **TOTAL**  **45**   **37**   **82**   **9.20**   **4.45**   **13.65** **Drilling Activities**     During the past two fiscal years, we participated in the drilling of the following explorationand development wells: **•** During the fiscal year ended August 31, 2005, we participated in the drilling oftwo exploration wells in the Wyoming Overthrust, one exploration well in East Texas,and two development wells in Oklahoma. As of November 2005, one of the explorationwells in Wyoming was plugged and abandoned (10% WI), while the other well (28.75%WI), located in the Mallard Prospect, is currently being completed. The explorationwell in East Texas (28.75% WI) is currently undergoing completion activities, andthe two development wells in Oklahoma (28.98% WI and 2.42% WI) were drilled andcompleted as producers. Additionally in fiscal year 2005, the Company participatedin several well workovers in Texas and Oklahoma.  **•** During the fiscal year ended August 31 2004, we participated in the drilling oftwo exploration wells in the expanded Yegua trend of South Texas (carried), oneexploration well in the Cotton Valley section of East Texas, one exploration well inthe Wyoming Overthrust (5% WI with carry), and one exploration well in SE Alberta.As of November 2004, the two exploration wells in South Texas have been classifiedas discoveries and are producing into sales lines. The BLM suspended drillingoperations of the well in Wyoming (Mallard Prospect) in December, 2004 for a periodof five and half months, and the well in Southeast Alberta was tested and determinedto be non-productive. Additionally in fiscal year 2004, the Company participated inseveral well workovers in Texas, Oklahoma, and Utah.     Although there is no assurance that any additional wells will be drilled, we anticipate we maydrill additional exploration and development wells during fiscal 2006 on our projects in the TexasGulf Coast and Rocky Mountains. The actual number of wells drilled will be dependent on severalfactors, including the results of our ongoing exploration efforts and the availability of capital.**Reserves**     For fiscal years 2005 and 2004, our proved reserve estimates for our United States oil and gasproperties were prepared by Ryder Scott Company, an independent petroleum engineering firm, and, inaccordance with SEC guidelines, are the estimated quantities of oil, natural gas and plant productswhich geological and engineering data demonstrate with reasonablecertainty to be recoverable in future years from known reservoirs under existing economic andoperating conditions, i.e. prices and costs as of the date the estimate is made.
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     At August 31, 2005, our total proved reserves were 7.064 Bcfe, which represents a 28% increaseover August 31, 2004 estimated total proved reserves of 5.502 Bcfe. Increased estimates for totalproved reserves result from revisions on multiple propertiesincluding new proved developed producing and proved undeveloped additionsrelated to exploration drilling in the expanded Yegua trend of south Texas. As of August 31, 2005,proved developed producing reserves are estimated at 3.908 Bcfe, while proved developednon-producing reserves are estimated at .459 Bcfe. Proved undeveloped reserves are estimated at2.697 Bcfe. At August 31, 2003, the Company had no proved reserves. The Company’s Canadian oiland gas properties do not have proved reserves.     Using current market product prices in effect at the end of the fiscal year and a discountrate of 10% as prescribed by SEC regulation, our total discounted future after-tax net cash flowswere estimated to be approximately $28.7 million for total proved reserves, as of August 31, 2005as compared to approximately $11.0 million for total proved reserves as of August 31, 2004. Thisincrease in present value is a reflection of higher prices at fiscal year end plus reserveadditions and revisions. The present value of future net cash flows does not purport to be anestimate of the fair market value of our proved reserves. An estimate of the future value wouldalso take into consideration, among other things, anticipated changes in future prices and costs,the expected recovery of reserves in excess of proved reserves and a discount factor morerepresentative of the time value of money and the risks inherent in producing oil, natural gas andplant products.     Reserve engineering is a subjective process of estimating underground accumulations of oil andgas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a functionof the quality of available data and of engineering and geological interpretation and judgment andthe existence of development plans. In addition, results of drilling, testing and productionsubsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserveestimates are often different from the quantities of oil and gas that are ultimately recovered.Further, the estimated future net revenues from proved reserves and the present value thereof arebased upon certain assumptions, including geologic success, prices, future production levels andcost that may not prove correct over time. Predictions about prices and future production levelsare subject to great uncertainty, and the meaningfulness of such estimates is highly dependent uponthe accuracy of the assumptions upon which they are based.**Full Cost Method of Accounting for Oil and Gas Properties**     The Company utilizes the full cost method of accounting for oil and gas activities and inaccordance with the full cost method of accounting, the Company maintained separate cost centersfor its oil and gas activities in the United States and Canada for fiscal years 2005 and 2004.Under this method, all costs associated with acquisition, exploration and development activitiesare capitalized by cost center. Capitalized costs, excluding costs of investments in unprovedproperties and major development projects, are subject to a “ceiling test limitation” computedseparately for each cost center. Under this method, we are required to record a permanentimpairment provision if the net book value of our oil and gas properties (net of related deferredtaxes) exceeds a ceiling value equal to the sum of (i) the present value of the future cash inflowsfrom proved reserves, tax effected and discounted at 10% per annum, and (ii) the cost ofunevaluated properties. The ceiling test is computed by country and at the end of each quarter.The oil and gas prices used in calculating future cash inflows in the United States are based uponthe market price on the last day of the accounting period. Oil and gas prices are generallyvolatile; and if the market prices at a period end date have decreased, we may have to record animpairment. A loss may also be generated by the transfer of significant early stage exploratorycosts to the oil and gas property cost pool that is subject to the ceiling test. These lossestypically occur when significant costs are transferred to the oil and gas property full cost poolas a result of an unsuccessful project without commercial oil and gas production. Forthe years ended August 31, 2005 and 2004, no property impairment charges were recorded for theCompany’s United States properties.     In accordance with the full cost method of accounting, the Company’s Canadian oil and gasinvestment, comprised principally of non-producing acreage (used for exploration and developmentactivities), is recorded in a separate full cost pool. During 2005, the Company recorded a non-cashimpairment of $580,000 of its initial oil and gas investment in Canada as the book value of theproperties exceeded the estimated fair market value of such properties. The Company decided tolimit future expenditures in Canada. For the year ended August 31, 2004, no property impairmentcharges were recorded for the Company’s Canadian properties.
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**Acreage**We currently control through lease, farmout, and option, the following approximate acreage positionas detailed below:**Developed And Undeveloped Acreage****As of August 31, 2005**                   **Gross Acres**  **Net Acres** State Developed  Undeveloped  Developed  Undeveloped  California  400   13,000   33   13,000  Canada  640   5,000   32   250  Louisiana  —   2,665   —   2,615  Montana(1)  —   241,800   —   226,300  Oklahoma  5,659   —   197   —  Texas  25,633   6,391   9,610   5,305  Utah  4,943   —   1,504   —  Wyoming  —   8,353   —   8,353                   **TOTAL**  **37,275**   **277,209**   **11,376**   **255,823**  (1) The Company is re-evaluating exploration prospects associated with itsundeveloped acreage in the Montana Foothills Project and subsequent to August 31,2005, has elected to release some of the undeveloped acreage reflected in the tableabove.**Competition**     We compete with numerous companies in virtually all facets of our business, including manycompanies that have significantly greater resources. These competitors may be able to pay more fordesirable leases and to evaluate, bid for and purchase a greater number of properties than ourfinancial or personnel resources permit. Our ability to establish and increase reserves in thefuture will be dependent on our ability to select and acquire suitable producing properties andprospects for future exploration and development. The availability of a market for oil and gasproduction depends upon numerous factors beyond the control of producers, including but not limitedto the availability of other domestic or imported production, the locations and capacity ofpipelines, and the effect of federal and state regulation on that production.**Government Regulation of the Oil and Gas Industry**     *General.*Our business is affected by numerous laws and regulations, including energy,environmental, conservation, tax and other laws and regulations relating to the energy industry.Failure to comply with these laws and regulations may result in the assessment of administrative,civil and criminal penalties, the imposition of injunctive relief or both. Moreover, changes inany of these laws and regulations could have a material adverse effect on our business. In view ofthe many uncertainties with respect to current and future laws and regulations, including theirapplicability to us, we cannot predict the overall effect of such laws and regulations on ourfuture operations.     We do not currently operate any properties. We believe that operations where we own interestscomply in all material respects with applicable laws and regulations and that the existence andenforcement of these laws and regulations have no more restrictive an effect on our operations thanon other similar companies in the energy industry.     The following discussion contains summaries of certain laws and regulations and is qualifiedin its entirety by the foregoing and by reference to the full text of the laws and regulationsdescribed.     *Federal Regulation of the Sale and Transportation of Oil and Gas.*Various aspects of our oiland gas operations are or will be regulated by agencies of the federal government. The FederalEnergy Regulatory Commission, or FERC, regulates the transportation and sale for resale of naturalgas in interstate commerce pursuant to the Natural Gas Act of 1938, or NGA, and the
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Natural Gas Policy Act of 1978, or NGPA. In the past, the federal government has regulatedthe prices at which oil and gas could be sold. While ''first sales’’ by producers of natural gas,and all sales of crude oil, condensate and natural gas liquids can currently be made atuncontrolled market prices, Congress could reenact price controls in the future. Deregulation ofwellhead sales in the natural gas industry began with the enactment of the NGPA in 1978. In 1989,Congress enacted the Natural Gas Wellhead Decontrol Act.     The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellheadsales of natural gas effective January 1, 1993, and resulted in a series of Orders being issued byFERC requiring interstate pipelines to provide transportation services separately, or''unbundled,’’ from the pipelines’ sales of gas and to provide open access transportation on anondiscriminatory basis that is equal for all natural gas shippers.     We do not believe that we will be affected by these or any other FERC rules or ordersmaterially differently than other natural gas producers and marketers with which we compete.     The FERC also has issued numerous orders confirming the sale and abandonment of natural gasgathering facilities previously owned by interstate pipelines and acknowledging that if the FERCdoes not have jurisdiction over services provided on those facilities, then those facilities andservices may be subject to regulation by state authorities in accordance with state law. A numberof states have either enacted new laws or are considering the adequacy of existing laws affectinggathering rates and/or services. Other state regulation of gathering facilities generally includesvarious safety, environmental, and in some circumstances, nondiscriminatory take requirements, butdoes not generally entail rate regulation. Thus, natural gas gathering may receive greaterregulatory scrutiny of state agencies in the future. Our anticipated gathering operations could beadversely affected should they be subject in the future to increased state regulation of rates orservices, although we do not believe that we would be affected by such regulation any differentlythan other natural gas producers or gatherers. In addition, the FERC’s approval of transfers ofpreviously-regulated gathering systems to independent or pipeline affiliated gathering companiesthat are not subject to FERC regulation may affect competition for gathering or natural gasmarketing services in areas served by those systems and thus may affect both the costs and thenature of gathering services that will be available to interested producers or shippers in thefuture.     We conduct certain operations on federal oil and gas leases, which are administered by theMinerals Management Service, or MMS. Federal leases contain relatively standard terms and requirecompliance with detailed MMS regulations and orders, which are subject to change. Among otherrestrictions, the MMS has regulations restricting the flaring or venting of natural gas, and hasproposed to amend those regulations to prohibit the flaring of liquid hydrocarbons and oil withoutprior authorization. Under certain circumstances, the MMS may require any of our operations onfederal leases to be suspended or terminated. Any such suspension or termination could materiallyand adversely affect our financial condition, cash flows and operations. The MMS issued a finalrule that amended its regulations governing the valuation of crude oil produced from federalleases. This rule, which became effective June 1, 2000, provides that the MMS will collectroyalties based on the market value of oil produced from federal leases, and was further modifiedby amendments to the June 2000 MMS rules, effective July 1, 2004. Also, there is currently pendingnew proposed MMS Federal Gas Valuation rules concerning calculation of transportation costs,including the allowed rate of return in the calculation of actual transportation costs in non-arm’slength arrangements. We cannot predict whether this new gas rule will become effective, nor canwe predict whether the MMS will take further action on oil and gas valuation matters. However, wedo not believe that any such rules will affect us any differently than other producers andmarketers of crude oil with which we will compete.     Additional proposals and proceedings that might affect the oil and gas industry are pendingbefore Congress, the FERC, the MMS, state commissions and the courts. We cannot predict when orwhether any such proposals may become effective. In the past, the natural gas industry has beenheavily regulated. There is no assurance that the regulatory approach currently pursued by variousagencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate thatcompliance with existing federal, state and local laws, rules and regulations will have a materialor significantly adverse effect upon our capital expenditures, earnings or competitive position.No material portion of our business is subject to re-negotiation of profits or termination ofcontracts or subcontracts at the election of the federal government.     *State Regulation.*Our operations also are subject to regulation at the state and, in somecases, county, municipal and local governmental levels. This regulation includes requiring permitsfor the drilling of wells, maintaining bonding requirements in order to drill or operate wells andregulating the location of wells, the method of drilling and casing wells, the surface use andrestoration of properties upon which wells are drilled, the plugging and abandonment of wells andthe disposal of fluids used and produced in connection with operations. Our operations also are orwill be subject to various conservation laws and regulations.
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These include (1) the size of drilling and spacing units or proration units, (2) the densityof wells that may be drilled, and (3) the unitization or pooling of oil and gas properties. Inaddition, state conservation laws, which frequently establish maximum rates of production from oiland gas wells, generally prohibit the venting or flaring of gas and impose certain requirementsregarding the ratability of production. State regulation of gathering facilities generallyincludes various safety, environmental and, in some circumstances, nondiscriminatory takerequirements, but (except as noted above) does not generally entail rate regulation. Theseregulatory burdens may affect profitability, but we are unable to predict the future cost or impactof complying with such regulations.     *Environmental Matters.*Operations on properties in which we have an interest are subject toextensive federal, state and local environmental laws that regulate the discharge or disposal ofmaterials or substances into the environment and otherwise are intended to protect the environment.Numerous governmental agencies issue rules and regulations to implement and enforce such laws,which are often difficult and costly to comply with and which carry substantial administrative,civil and criminal penalties and in some cases injunctive relief for failure to comply. Some laws,rules and regulations relating to the protection of the environment may, in certain circumstances,impose ''strict liability’’ for environmental contamination. These laws render a person or companyliable for environmental and natural resource damages, cleanup costs and, in the case of oil spillsin certain states, consequential damages without regard to negligence or fault. Other laws, rulesand regulations may require the rate of oil and gas production to be below the economically optimalrate or may even prohibit exploration or production activities in environmentally sensitive areas.In addition, state laws often require some form of remedial action, such as closure of inactivepits and plugging of abandoned wells, to prevent pollution from former or suspended operations.Legislation has been proposed in the past and continues to be evaluated in Congress from time totime that would reclassify certain oil and gas exploration and production wastes as ''hazardouswastes.’’ This reclassification would make these wastes subject to much more stringent storage,treatment, disposal and clean-up requirements, which could have a significant adverse impact onoperating costs. Initiatives to further regulate the disposal of oil and gas wastes are alsoproposed in certain states from time to time and may include initiatives at the county, municipaland local government levels. These various initiatives could have a similar adverse impact onoperating costs. The regulatory burden of environmental laws and regulations increases our costand risk of doing business and consequently affects our profitability.     The federal Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA,also known as the ''Superfund’’ law, imposes liability, without regard to fault, on certain classesof persons with respect to the release of a ''hazardous substance’’ into the environment. Thesepersons include the current or prior owner or operator of the disposal site or sites where therelease occurred and companies that transported, disposed or arranged for the transport or disposalof the hazardous substances found at the site. Persons who are or were responsible for releases ofhazardous substances under CERCLA may be subject to joint and several liability for the costs ofcleaning up the hazardous substances that have been released into the environment and for damagesto natural resources, and it is not uncommon for the federal or state government to pursue suchclaims. It is also not uncommon for neighboring landowners and other third parties to file claimsfor personal injury or property or natural resource damages allegedly caused by the hazardoussubstances released into the environment. Under CERCLA, certain oil and gas materials and productsare, by definition, excluded from the term ''hazardous substances.’’ At least two federal courtshave held that certain wastes associated with the production of crude oil may be classified ashazardous substances under CERCLA. Similarly, under the federal Resource, Conservation andRecovery Act, or RCRA, which governs the generation, treatment, storage and disposal of ''solidwastes’’ and ''hazardous wastes,’’ certain oil and gas materials and wastes are exempt from thedefinition of ''hazardous wastes.’’ This exemption continues to be subject to judicialinterpretation and increasingly stringent state interpretation. During the normal course ofoperations on properties in which we have an interest, exempt and non-exempt wastes, includinghazardous wastes, that are subject to RCRA and comparable state statutes and implementingregulations are generated or have been generated in the past. The federal Environmental ProtectionAgency and various state agencies continue to promulgate regulations that limit the disposal andpermitting options for certain hazardous and non-hazardous wastes.     Our operations will involve the use of gas fired compressors to transport collected gas.These compressors are subject to federal and state regulations for the control of air emissions.Title V status for a facility results in significant increased testing, monitoring andadministrative and compliance costs. To date, other compressor facilities have not triggered TitleV requirements due to the design of the facility and the use of state-of-the-art engines andpollution control equipment that serve to reduce air emissions. However, in the future, additionalfacilities could become subject to Title V requirements as compressor facilities are expanded or ifregulatory interpretations of Title V applicability change. Stack testing and emissions monitoringcosts will grow as these facilities are expanded and if they trigger Title V. We believe that theoperator of the properties in which we have an interest is in substantial compliance withapplicable laws, rules and regulations relating to the control of air emissions at all facilitieson those properties.
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     Although we maintain insurance against some, but not all, of the risks described above,including insuring the costs of clean-up operations, public liability and physical damage, there isno assurance that our insurance will be adequate to cover all such costs, that the insurance willcontinue to be available in the future or that the insurance will be available at premium levelsthat justify our purchase. The occurrence of a significant event not fully insured or indemnifiedagainst could have a material adverse effect on our financial condition and operations.     Compliance with environmental requirements, including financial assurance requirements and thecosts associated with the cleanup of any spill, could have a material adverse effect on our capitalexpenditures, earnings or competitive position. We do believe, however, that our operators are insubstantial compliance with current applicable environmental laws and regulations. Nevertheless,changes in environmental laws have the potential to adversely affect operations. At this time, wehave no plans to make any material capital expenditures for environmental control facilities.**Title to Properties**     As is customary in the oil and gas industry, only a preliminary title examination is conductedat the time we acquire leases or enter into other agreements to obtain control over interests inacreage believed to be suitable for drilling operations. In many instances, our partners haveacquired rights to the prospective acreage and we have a contractual right to have our interests inthat acreage assigned to us. In some cases, we are in the process of having those interests soassigned. Prior to the commencement of drilling operations, a thorough title examination of thedrill site tract is conducted by independent attorneys. Once production from a given well isestablished, the operator will prepare a division order title report indicating the proper partiesand percentages for payment of production proceeds, including royalties. We believe that titles toour leasehold properties are good and defensible in accordance with standards generally acceptablein the oil and gas industry.**Risk Factors**     In evaluating the Company, careful consideration should be given to the following riskfactors, in addition to the other information included or incorporated by reference in this annualreport. In addition, the ''Forward-Looking Statements’’ located herein, describe additionaluncertainties associated with our business and the forward-looking statements included orincorporated by reference. Each of these risk factors could adversely affect our business,operating results and financial condition, as well as adversely affect the value of an investmentin our common stock.     *We have a limited operating history in the oil and gas business.*Our operations to date haveconsisted solely of evaluating geological and geophysical information, acquiring acreage positions,generating exploration prospects, and drilling a limited number of wells on deep oil and gasprospects. We currently have nine full-time employees. Our future financial results dependprimarily on (1) our ability to discover commercial quantities of oil and gas; (2) the market pricefor oil and gas; (3) our ability to continue to generate potential exploration prospects; and (4)our ability to fully implement our exploration and development program. We cannot predict that ourfuture operations will be profitable. In addition, our operating results may vary significantlyduring any financial period. These variations may be caused by significant periods of time betweendiscovery and development of oil or gas reserves, if any, in commercial quantities.     *Our cash resources are not unlimited.*We need to increase our sources of revenue and/orfunding in order to sustain operations for the long run. There is no assurance that this willoccur.     *We may not discover commercially productive reserves.*Our future success depends on ourability to economically locate oil and gas reserves in commercial quantities. Except to the extentthat we acquire properties containing proved reserves or that we conduct successful exploration anddevelopment activities, or both, our proved reserves, if any, will decline as reserves areproduced. Our ability to locate reserves is dependent upon a number of factors, including ourparticipation in multiple exploration projects and our technological capability to locate oil andgas in commercial quantities. We cannot predict that we will have the opportunity to participatein projects that economically produce commercial quantities of oil and gas in amounts necessary tomeet our business plan or that the projects in which we elect to participate will be successful.There can be no assurance that our planned projects will result in significant reserves or that wewill have future success in drilling productive wells at economical reserve replacement costs.
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     *Exploratory drilling is an uncertain process with many risks.*Exploratory drilling involvesnumerous risks, including the risk that we will not find any commercially productive oil or gasreservoirs. The cost of drilling, completing and operating wells is often uncertain, and a numberof factors can delay or prevent drilling operations, including: **•** unexpected drilling conditions,  **•** pressure or irregularities in formations,  **•** equipment failures or accidents,  **•** adverse weather conditions,  **•** compliance with governmental requirements,  **•** shortages or delays in the availability of drilling rigs and the delivery of equipment, and  **•** shortages of trained oilfield service personnel.     Our future drilling activities may not be successful, nor can we be sure that our overalldrilling success rate or our drilling success rate for activities within a particular area will notdecline. Unsuccessful drilling activities could have a material adverse effect on our results ofoperations and financial condition. Also, we may not be able to obtain any options or lease rightsin potential drilling locations that we identify. Although we have identified a number ofpotential exploration projects, we cannot be sure that we will ever drill them or that we willproduce oil or gas from them or any other potential exploration projects.     *Our exploration and development activities are subject to reservoir and operational risks.*Even when oil and gas is found in what is believed to be commercial quantities, reservoir risks,which may be heightened in new discoveries, may lead to increased costs and decreased production.These risks include the inability to sustain deliverability at commercially productive levels as aresult of decreased reservoir pressures, large amounts of water, or other factors that might beencountered. As a result of these types of risks, most lenders will not loan funds secured byreserves from newly discovered reservoirs, which would have a negative impact on our futureliquidity. Operational risks include hazards such as fires, explosions, craterings, blowouts (suchas the blowout experienced at our initial exploratory well), uncontrollable flows of oil, gas orwell fluids, pollution, releases of toxic gas and encountering formations with abnormal pressures.In addition, we may be liable for environmental damage caused by previous owners of property we ownor lease. As a result, we may face substantial liabilities to third parties or governmentalentities, which could reduce or eliminate funds available for exploration, development oracquisitions or cause us to incur substantial losses.     We expect to maintain insurance against some, but not all, of the risks associated withdrilling and production in amounts that we believe to be reasonable in accordance with customaryindustry practices. The occurrence of a significant event, however, that is not fully insuredcould have a material adverse effect on our financial condition and results of operations.     *Our operations require large amounts of capital.*Our current development plans will requireus to make large capital expenditures for the exploration and development of our oil and gasprojects. Under our current capital expenditure budget, we expect to spend between $7.5 and $10.0million on exploration and development activities during our fiscal year ending August 31, 2006.Also, we must secure substantial capital to explore and develop our other potential projects.Historically, we have funded our capital expenditures through the issuance of equity. Volatilityin the price of our common stock, which may be significantly influenced by our drilling andproduction activity, may impede our ability to raise money quickly, if at all, through the issuanceof equity at acceptable prices. Future cash flows and the availability of financing will besubject to a number of variables, such as: **•** our success in locating and producing reserves in other projects,  **•** the level of production from existing wells, and  **•** prices of oil and gas.     Issuing equity securities to satisfy our financing requirements could cause substantialdilution to our existing stockholders. Debt financing, if obtained, could lead to: **•** a substantial portion of our operating cash flow being dedicated to the payment of principal and interest,  **•** our being more vulnerable to competitive pressures and economic downturns, and  **•** restrictions on our operations.
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     If our revenues were to decrease due to lower oil and gas prices, decreased production orother reasons, and if we could not obtain capital through a credit facility or otherwise, ourability to execute our development plans, obtain and replace reserves, or maintain productionlevels could be greatly limited.     *We depend heavily on exploration success and subsequent success in developing our explorationprojects.*Our future growth plans rely heavily on discovering reserves and initiating productionin the San Joaquin Basin, Texas, Gulf Coast and in the Rocky Mountains. Our development planincludes the need to discover reserves and establish commercial production through exploratorydrilling and development of our existing properties. We cannot be sure, though, that our plannedprojects will lead to significant reserves that can be economically extracted or that we will beable to drill productive wells at anticipated finding and development costs. If we are able torecord reserves, our reserves will decline as they are depleted, except to the extent that weconduct successful exploration or development activities or acquire other properties containingproved reserves.     *We depend on industry alliances.*We attempt to limit financial exposure on aproject-by-project basis by forming industry alliances where our technical expertise can becomplemented with the financial resources and operating expertise of more established companies.While entering into these alliances limits our financial exposure, it also limits our potentialrevenue from successful projects. Industry alliances also have the potential to expose us touncertainty if our industry partners are acquired or have priorities in areas other than ourprojects. Despite these risks, we believe that if we are not able to form industry alliances, ourability to fully implement our business plan could be limited, which could have a material adverseeffect on our business.     *Our non-operator status limits our control over our oil and gas projects.*We focus primarilyon creating exploration opportunities and forming industry alliances to develop thoseopportunities. As a result, we have only a limited ability to exercise control over a significantportion of a project’s operations or the associated costs of those operations. The success of aproject is dependent upon a number of factors that are outside our areas of expertise and control.These factors include: **•** the availability of leases with favorable terms and the availability ofrequired permitting for projects,  **•** the availability of future capital resources to us and the otherparticipants to be used for purchasing leases and drilling wells,  **•** the approval of other participants for the purchasing of leases and thedrilling of wells on the projects, and  **•** the economic conditions at the time of drilling, including the prevailingand anticipated prices for oil and gas.     Our reliance on other project participants and our limited ability to directly control projectcosts could have a material adverse effect on our expected rates of return.     *Oil and gas prices are volatile and an extended decline in prices could hurt our businessprospects.*Our future profitability and rate of growth and the anticipated carrying value of ouroil and gas properties will depend heavily on then prevailing market prices for oil and gas. Weexpect the markets for oil and gas to continue to be volatile. If we are successful in continuingto establish production, any substantial or extended decline in the price of oil or gas could: **•** have a material adverse effect on our results of operations,  **•** limit our ability to attract capital,  **•** make the formations we are targeting significantly less economically attractive,  **•** reduce our cash flow and borrowing capacity, and  **•** reduce the value and the amount of any future reserves.Various factors beyond our control will affect prices of oil and gas, including: **•** worldwide and domestic supplies of oil and gas,  **•** the ability of the members of the Organization of Petroleum ExportingCountries to agree to and maintain oil price and production controls,  **•** political instability or armed conflict in oil or gas producing regions,  **•** the price and level of foreign imports,  **•** worldwide economic conditions,  **•** marketability of production,
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 **•** the level of consumer demand,  **•** the price, availability and acceptance of alternative fuels,  **•** the availability of processing and pipeline capacity,  **•** weather conditions, and  **•** actions of federal, state, local and foreign authorities.     These external factors and the volatile nature of the energy markets make it difficult toestimate future prices of oil and gas. In addition, sales of oil and gas are seasonal in nature,leading to substantial differences in cash flow at various times throughout the year.     *Accounting rules may require write-downs.*Under full cost accounting rules, capitalized costsof proved oil and gas properties may not exceed the present value of estimated future net revenuesfrom proved reserves, discounted at 10%. Application of the ceiling test generally requirespricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter andrequires a write-down for accounting purposes if the ceiling is exceeded. If a write-down isrequired, it would result in a charge to earnings, but would not impact cash flow from operatingactivities. Once incurred, a write-down of oil and gas properties is not reversible at a laterdate.     We face risks related to title to the leases we enter into that may result in additional costsand affect our operating results. It is customary in the oil and gas industry to acquire aleasehold interest in a property based upon a preliminary title investigation. In many instances,our partners have acquired rights to the prospective acreage and we have a contractual right tohave our interests in that acreage assigned to us. In some cases, we are in the process of havingthose interests so assigned. If the title to the leases acquired is defective, or title to theleases one of our partners acquires for our benefit is defective, we could lose the money alreadyspent on acquisition and development, or incur substantial costs to cure the title defect,including any necessary litigation. If a title defect cannot be cured or if one of our partnersdoes not assign to us our interest in a lease acquired for our benefit, we will not have the rightto participate in the development of or production from the leased properties. In addition, it ispossible that the terms of our oil and gas leases may be interpreted differently depending on thestate in which the property is located. For instance, royalty calculations can be substantiallydifferent from state to state, depending on each state’s interpretation of lease languageconcerning the costs of production. We cannot guarantee that there will be no litigationconcerning the proper interpretation of the terms of our leases. Adverse decisions in anylitigation of this kind could result in material costs or the loss of one or more leases.     *Limitations on the Effectiveness of Controls.*Our management, including our Chief ExecutiveOfficer and Chief Financial Officer, does not expect that our disclosure controls or our internalcontrols will prevent all possible error or fraud. A control system, no matter how well conceivedand operated, can provide only reasonable, not absolute, assurance that the objectives of thecontrol system are met. Further the design of a control system must reflect the fact that thereare resource constraints, and the benefits of controls must be considered relative to their costs.Because of the inherent limitations in all control systems, no evaluation of controls can provideabsolute assurance that all control issues and instances of fraud, if any, within our company havebeen detected. These inherent limitations include the realities that judgments in decision makingcan be faulty, and that breakdowns can occur because of simple error or mistake. Additionally,controls can be circumvented by the individual acts of some persons, by collusion of two or morepeople, or by management override of the control. The design of any system of controls also isbased in part upon certain assumptions about the likelihood of future events, and there can be noassurance that any design will succeed in achieving its stated goals under all potential futureconditions; over time, controls may become inadequate because of changes in conditions, or thedegree of compliance with the policies or procedures may deteriorate. Because of the inherentlimitations in a cost-effective control system, misstatements due to error or fraud may occur andnot be detected.     *Our industry is highly competitive and many of our competitors have more resources than we do.*We compete in oil and gas exploration with a number of other companies. Many of these competitorshave financial and technological resources vastly exceeding those available to us. We cannot besure that we will be successful in acquiring and developing profitable properties in the face ofthis competition. In addition, from time to time, there may be competition for, and shortage of,exploration, drilling and production equipment. These shortages could lead to an increase in costsand delays in operations that could have a material adverse effect on our business and our abilityto develop our properties. Problems of this nature also could prevent us from producing any oiland gas we discover at the rate we desire to do so.     *Technological changes could put us at a competitive disadvantage.*The oil and gas industry ischaracterized by rapid and significant technological advancements and introductions of new productsand services using new technologies. As new
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technologies develop, we may be placed at a competitive disadvantage, and competitivepressures may force us to implement those new technologies at a substantial cost. If other oil andgas exploration and development companies implement new technologies before we do, those companiesmay be able to provide enhanced capabilities and superior quality compared with what we are able toprovide. We may not be able to respond to these competitive pressures and implement newtechnologies on a timely basis or at an acceptable cost. If we are unable to utilize the mostadvanced commercially available technologies, our business could be materially and adverselyaffected.     *Our industry is heavily regulated.*Federal, state and local authorities extensively regulatethe oil and gas industry. Legislation and regulations affecting the industry are under constantreview for amendment or expansion, raising the possibility of changes that may affect, among otherthings, the pricing or marketing of oil and gas production. State and local authorities regulatevarious aspects of oil and gas drilling and production activities, including the drilling of wells(through permit and bonding requirements), the spacing of wells, the unitization or pooling of oiland gas properties, environmental matters, safety standards, the sharing of markets, productionlimitations, plugging and abandonment, and restoration. The overall regulatory burden on theindustry increases the cost of doing business, which, in turn, decreases profitability.     *Our operations must comply with complex environmental regulations.*Our operations are subjectto complex and constantly changing environmental laws and regulations adopted by federal, state andlocal governmental authorities. New laws or regulations, or changes to current requirements, couldhave a material adverse effect on our business. We will continue to be subject to uncertaintyassociated with new regulatory interpretations and inconsistent interpretations between state andfederal agencies. We could face significant liabilities to the government and third parties fordischarges of oil, natural gas, produced water or other pollutants into the air, soil or water, andwe could have to spend substantial amounts on investigations, litigation and remediation. Wecannot be sure that existing environmental laws or regulations, as currently interpreted orenforced, or as they may be interpreted, enforced or altered in the future, will not have amaterial adverse effect on our results of operations and financial condition.     *Our business depends on transportation facilities owned by others.*The marketability of ouranticipated gas production depends in part on the availability, proximity and capacity of pipelinesystems owned or operated by third parties. Federal and state regulation of oil and gas productionand transportation, tax and energy policies, changes in supply and demand and general economicconditions could adversely affect our ability to produce, gather and transport oil and natural gas.     *Attempts to grow our business could have an adverse effect.*Because of our small size, wedesire to grow rapidly in order to achieve certain economies of scale. Although there is noassurance that this rapid growth will occur, to the extent that it does occur, it will place asignificant strain on our financial, technical, operational and administrative resources. As weincrease our services and enlarge the number of projects we are evaluating or in which we areparticipating, there will be additional demands on our financial, technical and administrativeresources. The failure to continue to upgrade our technical, administrative, operating andfinancial control systems or the occurrence of unexpected expansion difficulties, including therecruitment and retention of geoscientists and engineers, could have a material adverse effect onour business, financial condition and results of operations.     *We may not be able to retain our listing on the American Stock Exchange.*The American StockExchange has certain listing requirements in order for a company to continue to have theirsecurities traded on this exchange. A company may risk delisting if their common stock trades at alow price per share for a substantial period of time. Should our stock trade at a low share pricefor a substantial period of time, or our net tangible equity be below certain levels, we may not beable to retain our listing.     *We depend on key personnel.*We are highly dependent on the services of D. Scott Singdahlsen,our President and Chief Executive Officer, and our other geological and geophysical staff members.The loss of the services of any of these persons could hurt our business. We do not have anemployment contract with Mr. Singdahlsen or any other employee.**Disclosure Regarding Forward-Looking Statements And Cautionary Statements**     This annual report contains forward-looking statements within the meaning of Section 27A ofthe Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, includingstatements regarding, among other items, our business and growth strategies, anticipated trends inour business and our future results of operations, market conditions in the oil and gas industry,our ability to make and integrate acquisitions, the outcome of litigation, if any, and the impactof governmental regulation. These forward-looking statements are based largely on our expectationsand are subject to a number of risks and
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uncertainties, many of which are beyond our control. Actual results could differ materiallyfrom these forward-looking statements as a result of, among other things: **•** failure to obtain, or a decline in, oil or gas production, or a decline in oil or gas prices,  **•** incorrect estimates of required capital expenditures,  **•** increases in the cost of drilling, completion and gas collection or othercosts of production and operations,  **•** an inability to meet growth projections, and  **•** other risk factors set forth under ''Risk Factors’’ in this annual report.In addition, the words ''believe,’’ ''may,’’ ''could,’’ ''will,’’ ''when,’’''estimate,’’ ''continue,’’ ''anticipate,’’ ''intend,’’ ''expect’’ and similarexpressions, as they relate to PYR, our business or our management, are intended toidentify forward-looking statements.**ITEM 3. LEGAL PROCEEDINGS**     On July 29, 2005, the Company filed a lawsuit in the U.S. District Court for the EasternDistrict of Texas, Beaumont Division against Samson Lone Star Limited Partnership (“Samson”) andSamson’s parent company, Samson Resources Corp. The Company alleged in its complaint that Samson,the operator of a producing gas well in Jefferson County, Texas named the Sun Fee No. 1 SidetrackWell (the “Sun Fee Well”), has breached its obligations to the Company, which owns interests in theproperty on which the Sun Fee Well is located, by joining, without authorization, the Sun Fee Wellinto a unit with other properties in which the Company has no interest, many of which arenon-productive. Samson has a large interest in these properties that Samson has joined into theunit. Pursuant to Samson’s proposed pooling configuration, the Company’s working and overridingroyalty interests in the Sun Fee Well would be reduced substantially. The Company believes thatSamson has no legal or contractual right to reduce the Company’s interests in this manner. TheCompany is seeking monetary damages for all payments due and owing to the Company based on theproper, undiluted interests in the property. On September 13, 2005, the Court entered aPreliminary Injunction ordering Samson to return the Company to pay status for the undisputedamounts upon which Samson had been paying the Company prior to the filing of the suit.     On August 22, 2005, Samson filed a lawsuit in District Court for Jefferson County, Texas,58th Judicial District against the Company, claiming that Samson has the right to serveas operator to drill and operate on the property to the east of the Sun Fee Well, which is locatedon property in which the Company owns a majority interest. The Company holds a 100% interest inoil and gas leases that comprise 75% of the approximately 400-acre parcel on which it is planningto drill a gas well to the same reservoir from which the Sun Fee Well produces. In June 2005, theCompany notified Samson of its intention to drill a well on this property and offered Samson theopportunity to participate in the well. Samson elected to participate in the well and demanded tobe allowed to operate the well. Upon the Company’s initial preparation of the drill site, whichbegan in August 2005, Samson filed a lawsuit seeking a judicial declaration of Samson’s exclusiveright to operate the well and injunctive relief enjoining the Company from continuing its drillingoperations or serving as operator.     The Company will continue to vigorously pursue and defend its rights with respect to theforegoing litigations. The Company intends to continue to move forward with construction of thepotential drill site and to drill the well in order to protect its interests in the underlyingleases until such time as the issue is fully adjudicated.     On November 2, 2005, an adversary proceeding was filed against the Company in the on-goingbankruptcy proceeding of Venus Exploration Company (“Venus”) in the U.S. Bankruptcy Court for theEastern District of Texas. In the adversary proceeding, the Venus Exploration Trust, representingthe interests of the secured creditors (the “Trust”), seeks a full accounting, with interest andattorneys’ fees, of the net profits interest accounts established under the Net Profit Conveyanceby which the Company purchased Venus’ assets and is to account for proceeds generated from certainidentified, potential income-generating projects less costs. Presently, proceeds are generated bythe Nome and Madison projects in Jefferson County, Texas. The Trust also seeks reformation of theconveyance whereby future proceeds shall be paid by third-partpurchasers directly to the Trust,from which the Company may subsequently request reimbursement of costs. Upon reconsideration of aninitial good-faith deduction of costs for anticipated drilling operations on the two projects andprior to the filing of the adversary proceeding, the Company forwarded to the Trust a payment inexcess of $820,970, including interest, with over 35 pages of detailed accounting. The Company hasentered discussions with the Trust to withdraw and dismiss the proceeding in light of the payment,which discussions are pending the return of the Trust’s counsel from foreign travel. As a result,the lawsuit has not been served on the Company. Should the Trust refuse to dismiss and proceedwith service, the Company will vigorously defend its interests against the claims in thisproceeding.
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**ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS**     The following matters were submitted to a vote of security holders at the annual meeting ofstockholders which was held on August 8, 2005:     The stockholders voted to re-elect D. Scott Singdahlsen, David Kilpatrick, Bryce W. Rhodes andDennis Swenson to continue as directors of the Company. A total of 25,939,535 votes wererepresented with respect to this matter, with voting on each specific nominee as follows:                             BROKER  FOR AGAINST WITHHELD NON-VOTESD. Scott Singdahlsen  25,073,407   0   866,128  —David Kilpatrick  25,088,178   0   851,357  —Bryce W. Rhodes  25,103,428   0   836,107  —Dennis Swenson  25,103,728   0   835,807  —     A proposal to approve the issuance of up to an additional 1,780,702 shares of common stock tobe available for the conversion of accrued interest on previously issued convertible notes wasapproved by the stockholders. A total of 14,495,324 votes were represented with a total of13,492,288 (93%) shares voting for the proposal, 965,683 shares voting against the proposal, and37,353 shares abstaining from voting.     A proposal to ratify the selection of Hein & Associates LLP as our Certified PublicAccountants was approved by the stockholders. A total of 25,939,535 votes were represented with atotal of 25,073,454 (97%) shares voting for the proposal, 843,683 shares voting against theproposal, and 22,398 shares abstaining from voting.**PART II****ITEM5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS****Market For Common Equity**     Our common stock has been listed on the American Stock Exchange under the market symbol “PYR”since December 8, 1999. The following table sets forth the range of high and low sales prices pershare of our common stock for the periods indicated.           **High** **Low****Fiscal Year Ended August 31, 2004**        First Quarter $0.83  $0.45 Second Quarter  1.81   0.53 Third Quarter  1.70   1.04 Fourth Quarter  1.32   0.75 **Fiscal Year Ended August 31, 2005**        First Quarter $1.31  $0.90 Second Quarter  1.79   0.95 Third Quarter  1.99   1.20 Fourth Quarter  1.64   1.30      On November 15, 2005, the last reported sales price of our common stock on the American StockExchange was $1.22 per share.**Stockholders Of Record**     As of November 15, 2005, the number of record holders of our common stock was approximately520.
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**Dividends**     We have not declared or paid, and do not anticipate declaring or paying in the near future,any dividends on our common stock.**Recent Sales Of Unregistered Securities; Use Of Proceeds From Registered Securities**     In mid-October 2005, the Company completed a Private Equity Placement consisting of the saleof 6.328 million shares of common stock, priced at $1.30 per share, to a group of institutional andaccredited individual investors. Proceeds from the Placement of approximately $8.2 million will beused for general corporate purposes and costs associated with the Company’s development drillingportfolio. Shares purchased in the Private Placement were issued in reliance on exemptions fromregistration contained in Section 4(2) of the Securities Act of 1933, and as amended, and Rule 506of Regulation D promulgated thereunder. Pursuant to the terms of the Private Placement, theCompany has agreed to file a registration statement covering the resale of these shares.**Equity Compensation Plan Information**             Equity Compensation Plan Information          Number of Securities          Remaining Available for          Future Issuance under  Number of Securities to be     Equity Compensation  Issued Upon Exercise of Weighted-Average Exercise Plans (Excluding  Outstanding Options, Price of Outstanding Options, Securities Reflected inPlan Category Warrants and Rights Warrants and Rights Column (a))*  (a) (b) (c)Equity compensationplans approved bysecurity holders  2,234,750  $1.41   604,250              Equity compensationplans not approvedby security holders  —   —   —              Total  2,234,750  $1.41   604,250  * At August 31, 2005**ITEM 6. MANAGEMENT’S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS**     The following discussion should be read in conjunction with the Consolidated FinancialStatements and Notes thereto referred to in “Item 8. Financial Statements and Supplemental Data,”and “Items 1. and 2. Business and Properties — Disclosures Regarding Forward-Looking Statements”of this Form 10-KSB.**Overview**     We are an independent oil and gas exploration and production company engaged in theexploration, development and acquisition of crude oil and natural gas reserves. We intend toincrease stockholder value by profitably growing reserves and production, primarily throughdrilling operations and strategic acquisitions. Our strategic focus is the application of advancedseismic imaging and computer aided exploration technologies in the systematic search for commercialhydrocarbon reserves, primarily in the onshore western United States. We attempt to leverage ourtechnical experience and expertise with seismic data to identify exploration and exploitationprojects with significant potential economic return. We intend to participate in selectedexploration projects as a working interest owner, currently as a non-operator, sharing both riskand rewards with our partners. Our financial results depend on our ability to sell prospectinterests to outside industry participants. We will not be able to commence additional exploratorydrilling operations without outside industry participation. We have pursued, and will continue
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to pursue, exploration opportunities in regions where we believe significant opportunity fordiscovery of oil and gas exists. By attempting to reduce drilling risk through seismic technology,we seek to improve the expected return on investment in our oil and gas exploration projects.     Our future financial results continue to depend primarily on (1) our ability to discovercommercial quantities of hydrocarbons; (2) the market price for oil and gas; (3) our ability tocontinue to source and screen potential projects; and (4) our ability to fully implement ourexploration and development program with respect to these and other matters. There can be noassurance that we will be successful in any of these respects or that the prices of oil and gasprevailing at the time of production will be at a level allowing for profitable production.     In fiscal year 2004, we acquired various oil and gas interests from Venus Exploration, Inc.(“Venus”) in certain producing properties with estimated proved reserves of 4.784 Bcfe forapproximately $3.2 million (excluding acquisition expenses and subject to retention, by the VenusExploration Trust, of a net profits interest covering the non-productive exploration projects), andmade a private placement of our common stock, which raised approximately $8.2 million in grossproceeds. The revenue generated from production from these acquired properties comprises theprincipal source of the Company’ oil and gas revenues for fiscal year 2005.     In mid-October 2005, we completed a Private Equity Placement consisting of the sale of 6.328million shares of common stock, priced at $1.30 per share, to a group of institutional andaccredited individual investors. Proceeds from this Placement of approximately $8.2 million willbe used for general corporate purposes and costs associated with the Company’s development drillingportfolio located principally in the Rocky Mountains and Texas.**Liquidity and Capital Resources**     Our primary sources of liquidity historically have been from placements of common stock andconvertible notes, and to a much lesser extent, cash provided by operating activities. Our primaryuse of capital has been for the acquisition, development, and exploration of oil and natural gasproperties. As we pursue growth, we continually monitor the capital resources available to us tomeet our future financial obligations, planned capital expenditure activities and liquidity. Ourfuture success in growing proved reserves and production is highly dependent on capital resourcesavailable to us and our success in finding or acquiring additional reserves. At August 31, 2005,we had approximately $2.1 million in working capital and cash of $2.9 million.Cash Flow from Operating Activities     Net cash provided by operating activities was $1.9 million in 2005 compared with net cash usedby operating activities of $1.1 million in 2004. The increase in net cash provided by operatingactivities was substantially due to the increase in production revenues, net of increases inexpenses, attributed to the producing properties acquired from Venus in May 2004. See “Results ofOperations” for discussion of changes in expenses. Non-cash charges increased due to higherdepreciation, depletion and amortization associated with increased production and a non-cash chargefor the impairment of the Company’s investment in its Canadian properties. Changes in currentassets and liabilities increased cash flow from operations by $91,000 in 2005 compared with adecrease in cash flows from operations of $323,000 in 2004.     Operating cash flows are impacted by many variables, the most significant of which is thevolatility of prices for natural gas and oil produced. Prices for these commodities are determinedprimarily by prevailing market conditions. Regional and worldwide economic activity, weather andother substantially variable factors influence market conditions for these products. These factorsare beyond our control and are difficult to predict.Capital Expenditures     Our capital expenditures were approximately $5.9 million and $5.1 million in 2005 and 2004,respectively. The total for 2005 includes $4.2 million for drilling, development, exploration andexploitation, $1.6 million for leasehold acquisition costs and delay rentals, $98,000 for geologicand geophysical costs and $10,000 for office furniture, fixtures and equipment. In 2004 weincurred approximately $3.8 million of capital costs related to the properties we acquired fromVenus. This amount includes capitalized acquisition costs, costs associated with undevelopedleasehold, drilling, workover, and geological and geophysical costs. We incurred approximately$1.6 million for costs related to our other exploration projects including continued acreage leaseobligations and associated geological and geophysical costs, as well as drilling costs for theMallardwell.
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     In May 2004, we acquired interests in certain producing properties for approximately$3.3 million (excluding acquisition expenses and subject to retention, by the Venus ExplorationTrust, of a net profits interest covering the non-productive exploration projects) from Venus.Venus was in Chapter 11 Bankruptcy, and the properties were acquired through public auction asapproved by the United States Bankruptcy Court. To finance the purchase, we primarily usedexisting cash reserves and also a portion of the proceeds from the Placement. The purchase alsoprovides for a net profits interest payable to the Venus Exploration Trust. The net profitsinterest, which applies only to the exploration and exploitation projects on the Venus acreagebeing acquired, varies from 25% to 50% with respect to different Venus exploration and exploitationproject areas, and decreases by one-half of its original amount aftera total of $3.3 million in netprofits proceeds has been paid to the Trust.     During 2005 and 2004, we received $750,000 and $500,000, respectively, for non-refundableoption fees received from Suncor Energy Natural Gas America, Inc. (“SENGAI”) pursuant to anExploration Option Agreement between the Company and SENGAI covering our Rogers Pass explorationproject in the foothills of west-central Montana. In 2005, we received proceeds of approximately$49,000 from the sale of a portion of our interests in prospects in Louisiana and Texas. In 2004,we received approximately $632,000 in prospect fees and pro-rata development costs from two privateoil and gas exploration companies pursuant to an agreement covering two of our exploration projectsin the Overthrust of southwestern Wyoming.     We currently anticipate our capital budget will be approximately between $7.5 and $10.0million for fiscal year 2006 which will be used for a diverse portfolio of development andexploration wells in our core areas of operation. We may consider selling down a portion of ourinterests in some of our exploration and development projects to industry partners to generateadditional funds to finance our 2006 capital budget. We are projecting that cash on hand, cashavailable from operating activities, capital of $8.2 million received in an October 2005 privateplacement, and funds from the partial sale of our interest in some prospects will be sufficient tofund our 2006 capital budget.Financing Activities     Inearly May 2004, we received subscriptions for an aggregate ofapproximately $8.2 million in gross proceedsfrom a private placement of our common stock. The private placement (the “Placement”) consisted ofthe sale of 7.5 million shares of common stock, priced at $1.09 per share, to a group of twelveinstitutional and accredited individual investors pursuant to exemptions from registration underSections 3(b) and 4(2) of the Securities Act of 1933, as amended. The first tranche of thePlacement, consisting of 4.5 million shares and approximately$4.9 million in gross proceeds, was received andaccepted in early May 2004. The second tranche of the Placement, consisting of 3.0 million sharesand approximately $3.3 million in gross proceeds, was approved by our stockholders at our AnnualMeeting of Stockholders on June 11, 2004. We received the funds from the second tranche in lateJune 2004. Proceeds from the Placement will be used for general corporate purposes, partialfunding of the acquisition of assets from Venus Exploration, Inc., and project development anddrilling costs associated with our exploration and exploitation portfolio. The resale of theseshares acquired in the Placement has subsequently been registered through a Registration Statementthat has become effective with the SEC.     In mid-October 2005, the Company completed a Private Equity Placement consisting of the saleof 6.328 million shares of common stock, priced at $1.30 per share, to a group of institutional andaccredited individual investors. Proceeds from this Placement of approximately $8.2 million willbe used for general corporate purposes and costs associated with the Company’s development drillingportfolio located principally in the Rocky Mountains and Texas.     It is anticipated that the continuation and future development of our business will requireadditional, and possibly substantial, capital expenditures. We have no reliable source foradditional funds for administration and operations to the extent our existing funds have beenutilized. In addition, our capital expenditure budget for the fiscal year ending August 31, 2006will depend on our success in selling additional prospects for cash, the level of industryparticipation in our exploration projects, the availability of debt or equity financing, and theresults of our activities. We anticipate spending a minimum of approximately between $7.5 and$10.0 million on exploration and development activities during our fiscal year ending August 31,2006. To limit capital expenditures, we intend to form industry alliances and exchange anappropriate portion of our interest for cash and/or a carried interest in our exploration projects.We may need to raise additional funds to cover capital expenditures. These funds may come fromcash flow, equity or debt financings, a credit facility, or sales of interests in our properties,although there is no assurance additional funding will be available or that it will be available onsatisfactory terms.
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     Our future financial results continue to depend primarily on (1) our ability to discovercommercial quantities of hydrocarbons; (2) the market price for oil and gas; (3) our ability tocontinue to source and screen potential projects; and (4) our ability to fully implement ourexploration and development program with respect to these and other matters. There can be noassurance that we will be successful in any of these respects or that the prices of oil and gasprevailing at the time of production will be at a level allowing for profitable production.Contractual Obligations     The following table summarizes the Company’s obligations and commitments, as of August 31,2005 to make future payments under its convertible notes payable and office lease for the periodsspecified (in thousands):Payments Due By Period                         Contractual                  Obligations Total  2006  2007  2008  2009  Thereafter Convertible Notes $8,474  $—  $—  $—  $8,474  $—                          Office Leases  163   70   70   23   —   —                Total ContractualCash Obligations $8,637  $70  $70  $23  $8,474  $—                    The above schedule assumes convertible note interest payments will be added to the principal amount(which is at the discretion of the Company), and the entire balance will be paid in full onmaturity of May 24, 2009, and there will be no conversion of debt to common stock. In addition tothe above obligations, if we elect to continue holding all our existing leases on a delayed rentalbasis, we would have to pay approximately $129,000 during the year ending August 31, 2006. TheCompany considers on a quarterly basis whether to continue holding all or part of each acreageblock by making delay rental payments on existing leases.**Results of Operations*****The twelve months ended August 31, 2005 (“2005”) compared with the twelve months ended August 31,2004 (“2004”)***     Operations during the fiscal year ended August 31, 2005 resulted in net income ofapproximately $12,000 compared to a net loss of approximately $1.4 million for the fiscal yearended August 31, 2004. The increase in net income is primarily attributed to the purchase ofproducing properties from Venus Exploration Inc. (“Venus”) in May 2004.     *Oil and Gas Revenues.*During the year ended August 31, 2005, we recorded approximately $6.1million in total oil and gas revenues compared with approximately $863,000 for the same period in2004. Natural gas revenues increased to $3.0 million from the sale of 392,065 mcf of natural gasat an average price of $7.54 per mcf in 2005 compared with revenues of $334,000 from the sale of60,285 mcf of natural gas at an average price of $5.54 per mcf in 2004. Average natural gas pricesfor 2005 increased 36% over 2004 average prices. Oil and hydrocarbon liquids revenues for 2005 and2004 were $3.1 million and $529,000, respectively, from the saleof 62,289 and 13,971 bbls of oiland hydrocarbon liquids, respectively. Average oil prices increased 33% from $37.88 in 2004 to$50.49 in 2005. The increase in oil and gas revenues and production is principally attributed tonew revenues and production from two wells that reached payout during 2005, increased prices and afull year of revenue and production from properties acquired from Venus in May 2004 compared withonly four months of revenue and production from the same properties in 2004. During 2005, theCompany commenced receiving its net revenue interest proceeds from the Sun Fee #1 well and theManess #1 well, located in Texas, after the wells reached payout during the fiscal year 2005. Theoil and gas revenues from these wells approximate 55% of total oil and gas revenues for 2005.Revenues from these wells are subject to a net profits expense.     *Lease Operating Expenses.*Lease operating expenses increased from $335,000 in 2004 toapproximately $1.1 million in 2005. The increase is attributed to new wells added and a full yearof lease operating expenses on properties acquired from Venus compared with only four months in2004.
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     *Net Profits Expense.*During 2005, two wells, the Sun Fee #1 and the Maness #1, reached payoutand we commenced receiving revenues and incurring operating expenses on these wells. These wellsare subject to a net profits expense of 50% of revenues net of capital and operating expensesincurred.     *Depreciation Depletion and Amortization.*Depreciation, depletion and amortization expenseincreased to $868,000 in 2005 from $173,000 in 2004. The increase was primarily attributable todepletion expense of $860,000 associated with increased production volumes from properties acquiredfrom Venus in May 2004. We recorded $8,000 and $13,000 in depreciation expense associated withcapitalized office furniture and equipment during 2005 and 2004, respectively. Depreciation ofAsset Retirement Obligation assets for the years ended August 31, 2005 and 2004 was $0 and$114,000, respectively. For further discussion of the Asset Retirement Obligation, see Note 4 tothe Financial Statements included in this Form 10-KSB.     *Accretion Expense.*We recorded $25,000 and $100,000, respectively, for the years ended August31, 2005 and August 31, 2004, of accretion of the unamortized discount of the Asset RetirementObligation liability. The accretion expense for 2004 was attributable to the properties acquiredfrom Venus in May 2004. For further discussion of the Asset Retirement Obligation, see Note 4 tothe Financial Statements included in this Form 10-KSB.     *Dry Hole, Impairment and Abandonments.*We recognized a non-cash impairment expense of$580,000 associated with the Company’s investment in its Canadian properties. We recorded noimpairment expense for the year ended August 31, 2004     *General and Administrative Expenses.*General and administrative expenses in 2005 wereapproximately $1.9 million compared to approximately $1.3 million in 2004. The 45% increase is dueprincipally to higher personnel costs, legal and auditing expenses and contract services. Theaddition of staff and related general and administrative expenses to manage the Venus propertiesacquired in May 2004 was the primary factor contributing to the increases.     *Interest Expense.*During 2005, we recorded interest expense of $343,000 compared to $327,000in 2004. The interest expense for each year is associated with the May 24, 2002 sale ofoutstanding convertible notes due on May 24, 2009. The Company elected to add $335,000 and$319,000 of accrued interest to the balance of the debt for the years ended August 31, 2005 andAugust 31, 2004, respectively. We have reflected the outstanding balance of these notes asConvertible Notes under Long Term Debt on our August 31, 2005 and 2004 balance sheets.     *Interest Income.*We recorded $93,000 and $28,000 in interest income for the years endedAugust 31, 2005 and 2004, respectively. Interest income increased in 2005 due to higher averagecash balances for the majority of 2005 due principally to funds received from a private placementof our common stock in May 2004.***The twelve months ended August 31, 2004 (“2004”) compared with the twelve months ended August 31,2003 (“2003”)***     Operations during the fiscal year ended August 31, 2004 resulted in a net loss ofapproximately $1.4 million compared to a net loss of approximately $5.3 million for the fiscal yearended August 31, 2003.     *Oil and Gas Revenues and Expenses.*During the year ended August 31, 2004, we recordedapproximately $863,000 in total oil and gas revenues. Of this amount, we recorded approximately$334,000 from the sale of 60,285 mcf of natural gas for an average price of $5.54 per mcf, andapproximately $529,000 from the sale of 13,971 bbls of oil and hydrocarbon liquids for an averageprice of $37.88 per bbl. The portion of fiscal year 2004 oil and gas revenues related to the May2004 property acquisition from Venus Exploration, Inc. (“Venus”), was approximately $694,000. Asthe acquisition from Venus was recorded as a purchase transaction, only four months of operationsrelated to these properties were recorded in 2004. During the year ended August 31, 2003, werecorded approximately $154,000 from the sale of 34,773 mcf of natural gas for an average price of$4.41 per mcf, and $42,000 for the sale of 1,583 bbls of hydrocarbon liquids for an average priceof $26.33 per bbl. 2003 revenues relate totally to the Company’s interest in East Lost Hills inCalifornia. Comparable revenues for this prospect in 2004 were $169,000. Lease operating expensesin 2004 were $336,000 compared to $95,000 in 2003.
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     *Interest Income.*We recorded $27,000 and $54,000 in interest income for the years endedAugust 31, 2004 and 2003, respectively. Lower interest income in 2004 resulted from lower averagecash balances for the majority of 2004, offset partially by interest on the funds received from theprivate placement of our common stock in May 2004.     *General and Administrative Expenses.*General and administrative expenses in 2004 wereapproximately $1.3 million compared to approximately $1.3 million in 2003. The increaseprincipally reflects additional audit and legal fees incurred in conjunction with the propertyacquisition from Venus Exploration Inc.     *Depreciation Depletion and Amortization.*We recorded $46,000 in depreciation, depletion andamortization expense from oil and gas properties for the year ended August 31, 2004. We recordedno depreciation, depletion and amortization expense from oil and gas properties for the year endedAugust 31, 2003, due to an impairment taken against our entire amortizable full cost pool at August31, 2003, and accordingly, there were no costs to amortize. The increase in depreciation,depletion and amortization expense was attributable to the properties acquired from VenusExploration, Inc. We recorded $13,000 and $11,000 in depreciation expense associated withcapitalized office furniture and equipment during 2004 and 2003, respectively. Depreciation ofAsset Retirement Obligation assets for the years ended August 31, 2004 and August 31, 2003, was$114,000 and $151,000, respectively. For further discussion of the Asset Retirement Obligation,see Note 4 to the Financial Statements included in this Form 10-KSB.     *Accretion Expense.*We recorded $100,000 and $77,000, respectively, for the years ended August31, 2004 and August 31, 2003, of accretion of the unamortized discount of the Asset RetirementObligation liability. The increase in accretion expense was attributable to the propertiesacquired from Venus Exploration, Inc. For further discussion of the Asset Retirement Obligation,see Note 4 to the Financial Statements included in this Form 10-KSB.     *Dry Hole, Impairment and Abandonments.*We recorded no impairment expense for the year endedAugust 31, 2004. For the year ended August 31, 2004, we recorded an impairment expense of $3.2million, of which $451,000 related to costs incurred in the East Lost Hills prospect, and theremainder, $2.8 million, related to other undeveloped prospects in California and the RockyMountain region, which were determined by management to be impaired as of August 31, 2003.     *Interest Expense.*During 2004, we recorded interest expense of $327,000 compared to $315,000in 2003. The interest expense for each year is associated with the May 24, 2002 sale ofoutstanding convertible notes due on May 24, 2009. The Company elected to add $319,000 and$304,000 of accrued interest to the balance of the debt for the years ended August 31, 2004 andAugust 31, 2003, respectively. We have reflected the outstanding balance of these notes asConvertible Notes under Long Term Debt on our August 31, 2004 and 2003 balance sheets. The twelvemonths ended August 31, 2004 (“2004”) compared with the twelve months ended August 31, 2003.**Critical Accounting Policies And Estimates**     We believe the following critical accounting policies affect our more significant judgmentsand estimates used in the preparation of our Financial Statements.     *Reserve Estimates:*     Our estimates of oil and natural gas reserves, by necessity, are projections based ongeological and engineering data, and there are uncertainties inherent in the interpretation of suchdata as well as the projection of future rates of production and the timing of developmentexpenditures. Reserve engineering is a subjective process of estimating underground accumulationsof oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is afunction of the quality of available data, engineering and geological interpretation and judgment.Estimates of economically recoverable oil and natural gas reserves and future net cash flowsnecessarily depend upon a number of variable factors and assumptions, such as historical productionfrom the area compared with production from other producing areas, the assumed effects ofregulations by governmental agencies and assumptions governing future oil and natural gas prices,future operating costs, severance and excise taxes, development costs and workover and remedialcosts, all of which may in fact vary considerably from actual results. For these reasons, estimatesof the economically recoverable quantities of oil and natural gas attributable to any particulargroup of properties, classifications of such reserves based on risk of recovery, and estimates ofthe future net cash flows expected from there may vary substantially. Any significant variance inthe assumptions could materially affect the estimated quantity and value of the reserves, whichcould affect the carrying value of our oil and gas properties and/or the
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rate of depletion of the oil and gas properties. Actual production, revenues and expenditureswith respect to our reserves will likely vary from estimates, and such variances may be material.     Many factors will affect actual net cash flows, including the following: the amount and timingof actual production; supply and demand for natural gas; curtailments or increases in consumptionby natural gas purchasers; and changes in governmental regulations or taxation.     *Property, Equipment and Depreciation:*     We follow the full cost method to account for our oil and gas exploration and developmentactivities. Under the full cost method, all costs incurred which are directly related to oil andgas exploration and development are capitalized and subjected to depreciation and depletion.Depletable costs also include estimates of future development costs of proved reserves. Costsrelated to undeveloped oil and gas properties may be excluded from depletable costs until thoseproperties are evaluated as either proved or unproved. The net capitalized costs are subject to aceiling limitation based on the estimated present value of discounted future net cash flows fromproved reserves. As a result, we are required to estimate our proved reserves at the end of eachquarter, which is subject to the uncertainties described in the previous section. Gains or lossesupon disposition of oil and gas properties are treated as adjustments to capitalized costs, unlessthe disposition represents a significant portion of the Company’s proved reserves.     *Revenue Recognition:*     The Company recognizes oil and gas revenues from its interests in producing wells as oil andgas is produced and sold from these wells. The Company uses the sales method to account for gasimbalances. Oil and gas sold is not significantly different from the Company’s productentitlement. Gas imbalances at August 31, 2005 and 2004 were not significant.**Recent Accounting Pronouncements**     InMay 2005, the Financial Accounting Standards Board (FASB) issuedStatement of Financial Accounting Standards No. 154, *Accounting Changes and Error Corrections — areplacement of APB Opinion No. 20 and FASB StatementNo. 3* (SFAS 154). SFAS 154 requiresretrospective application to prior periods’ financial statements for changes in accountingprinciple, unless it is impracticable application to prior periods’ financial statements forchanges in accounting principle, unless it is impracticable to determine either the period-specificeffects or the cumulative effect of the change. SFAS 154 also requires that a change indepreciation, amortization, or depletion method for long-lived, non-financial assets be accountedfor as a change in accounting estimate affected by a change in accounting principle. SFAS 154 iseffective for accounting changes and corrections of errors made in fiscal years beginning afterDecember 15, 2005. The implementation of SFAS 154 is not expected to have a material impact on ourcondensed consolidated results of operations, financial position or cash flows.     In December 2004, the FASB issued its final standard on accounting for employee stock options,SFAS No. 123 (Revised 2004), *Share-Based Payment* (SFAS123 (R)). SFAS 123 (R) replaces SFAS No.123, *Accounting for Stock-Based Compensation* (SFAS 123), and supersedes Accounting PrinciplesBoard Opinion No.25, *Accounting for Stock Issued to Employees.* SFAS 123 (R) requires companiesto measure compensation costs for all share-based payments, including grants of employee stockoptions, based on the fair value of the awards on the grant date and to recognize such expense overthe period during which an employee is required to provide services in exchange for the award. Thepro forma disclosures previously permitted under SFAS 123 will no longer be an alternative tofinancial statement recognition. SFAS 123 (R) is effective for all awards granted, modified,repurchased or cancelled after, and to unvested portions of previously issued and outstandingawards vesting after, interim or annual periods, beginning after June 15, 2005, which for us willbe the first quarter of fiscal 2006. We are currently evaluating the effect of adopting SFAS 123(R) on our financial position and results of operations. We currently estimate the adoption of SFAS123 (R) will result in expenses in amounts that are similar to the current pro forma disclosuresunder SFAS 123.**ITEM 7. FINANCIAL STATEMENTS**     The Consolidated Financial Statements and schedules that constitute Item 7 are attached at theend of Annual Report on Form 10-KSB. An index to these Financial Statements and schedules is alsoincluded in Item 14(a) of this Annual Report on Form 10-KSB.
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**ITEM 8.** **CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING ANDFINANCIAL DISCLOSURE**     None.**ITEM 8A. CONTROLS AND PROCEDURES**     As of the end of the period covered by this report, the Company conducted an evaluation of theCompany’s disclosure controls and procedures (as defined in Rules 13a-15(e) under the SecuritiesExchange Act of 1934 (the “Exchange Act”)). Based on this evaluation, the Company concluded that,subject to the limitations described below, the Company’s disclosure controls and procedures areeffective to ensure that information required to be disclosed by the Company in annual reports thatit files under the Exchange Act is recorded, processed, summarized, and reported within the timeperiods specified in Securities and Exchange Commission rules and forms. There was no changein the Company’s internal controls over financial reporting during the Company’s most recentlycompleted fiscal quarter that has materially affected, or is reasonably likely to materiallyaffect, the Company’s internal control over financial reporting period.**ITEM 8B. OTHER INFORMATION**     Not applicable
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**PART III****ITEM 9.** **DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION16(a) OF THE EXCHANGE ACT**     The directors and executive officers of the Company, their respective positions and ages, andthe year in which each director was first elected, are set forth in the following table. Eachdirector has been elected to hold office until the next annual meeting of stockholders andthereafter until his successor is elected and has qualified. Additional information concerningeach of these individuals follows the table.           Name Age Position with the Company Director SinceD. Scott Singdahlsen  47  Chief Executive Officer, Chief FinancialOfficer and President  1997            David Kilpatrick  55  Chairman of the Board  2002            Bryce W. Rhodes  52  Director  1999            Dennis M. Swenson  70  Director  2004            Kenneth R. Berry, Jr.  53  Vice President-Land and Corporate Secretary —     **D. Scott Singdahlsen**has served as President, Chief Executive Officer, and Chief FinancialOfficer of the Company since August 1997. From August 1997 to November 2005, Mr. Singdahlsenserved as our Chairman of the Board. Mr. Singdahlsen co-founded PYR Energy, LLC in 1996, andserved as General Manager and Exploration Coordinator. In 1992, Mr. Singdahlsen co-foundedInteractive Earth Sciences Corporation, a 3-D seismic management and interpretation consulting firmin Denver, where he served as vice president and president and lead seismic interpretationspecialist from 1992 to 1996. Prior to forming Interactive Earth Sciences Corporation, Mr.Singdahlsen was employed as a Development Geologist for Chevron USA in the Rocky Mountain region.At Chevron, Mr. Singdahlsen was involved in 3-D seismic reservoir characterization projects andgeostatistical analysis. Mr. Singdahlsen started his career at UNOCAL as an Exploration Geologistin Midland, Texas. Mr. Singdahlsen earned a B.A. in Geology from Hamilton College and a M.S. inStructural Geology from Montana State University.     **David B. Kilpatrick**has been a Director of the Company since June, 2002 and was appointed toChairman of the Board in November 2005. He is currently President of Kilpatrick Energy Group,which provides strategic management consulting services to the oil and gas industry. He currentlyserves as a Director of the publicly traded Cheniere Energy and Whittier Energy companies as wellas privately held Ensyn Petroleum International, Ltd. Prior to the 1998 merger with Texaco, he wasPresident and Chief Operating Officer of Monterey Resources, Inc., the largest independent oil andgas producer in California. Mr. Kilpatrick has served as President of the California IndependentPetroleum Association and is a member of its Board of Directors and also serves as a Director ofthe Independent Oil Producers Agency. He earned a Bachelor of Science degree in PetroleumEngineering from the University of Southern California and a Bachelor’s Degree in Geology andPhysics from Whittier College.     **Bryce W. Rhodes**has been a Director of the Company since April 1999, when he was nominated andelected to the Board in connection with the sale by the Company of convertible promissory notesissued in a private placement transaction in October and November 1998. From 1996 until September2003, Mr. Rhodes has served as President and CEO of Whittier
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Energy Company (“WEC”), an oil and gas investment company. In September 2003, WEC merged withOlympic Resources, Inc. and Mr. Rhodes was appointed as President and Chief Executive Officer. Mr.Rhodes served as Investment Manager of WEC from 1990 until 1996. Mr. Rhodes received B.A. degreesin Geology and Biology from the University of California, Santa Cruz, in 1976 and an MBA degreefrom Stanford University in 1979.     **Dennis M. Swenson**joined as a Director in October 2004, and serves as the Audit CommitteeChairman and a member of the Compensation Committee. From 1992 through 1995, Mr. Swenson was anindependent consultant. Mr. Swenson was Executive Vice President, Chief Financial Officer,Secretary and Treasurer, of StarTek, Inc., a NYSE traded company with headquarters in Denver,Colorado from 1996 through retirement in 2001. Mr. Swenson was employed at Ernst & Young in Denverfrom 1960 to 1973, and was a partner at Ernst & Young from 1973 to 1991. He has a Bachelor’sDegree in Accounting from Brigham Young University and an MBA Degree from the University of Denver.     **Kenneth R. Berry, Jr.**has served as Vice President of land since August 1999, and CorporateSecretary since November 2005. From October 1997 to August 1999, Mr. Berry served as our landmanager. Mr. Berry is responsible for the management of all land issues including leasing andpermitting. Prior to joining the Company, Mr. Berry served as the managing land consultant forSwift Energy Company in the Rocky Mountain region. Mr. Berry began his career in the landdepartment with Tenneco Oil Company after earning a B.A. degree in Petroleum Land Management at theUniversity of Texas — Austin.**Section 16(a) Beneficial Ownership Reporting Compliance**     Section 16(a) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”),requires the Company’s directors, executive officers and holders of more than 10% of the Company’scommon stock to file with the Securities and Exchange Commission initial reports of ownership andreports of changes in ownership of common stock and other equity securities of the Company. TheCompany believes that during the year ended August 31, 2005, its officers, directors and holders ofmore than 10% of the Company’s common stock complied with all Section 16(a) filing requirements.In making these statements, the Company has relied upon representations and its review of copies ofthe Section 16(a) reports filed for the fiscal year ended August 31, 2005 on behalf of theCompany’s directors, officers and holders of more than 10% of the Company’s common stock.**Employee Code of Conduct and Code of Ethics and Reporting of Accounting Concerns**     The Company adopted an Employee Code of Conduct (the “Code of Conduct”). We require allemployees to adhere to the Code of Conduct in addressing legal and ethical issues encountered inconducting their work. The Code of Conduct requires that our employees avoid conflicts ofinterest, comply with all laws and other legal requirements, conduct business in an honest andethical manner and otherwise act with integrity and in the Company’s best interest.     The Company also adopted a Code of Ethics for our Chief Executive Officer, our Chief FinancialOfficer, our Controller and all other financial officers and executives. This Code of Ethicssupplements our Code of Conduct and is intended to promote honest and ethical conduct, full andaccurate reporting, and compliance with laws as well as other matters. The Code of Conduct andCode of Ethics are filed with the SEC.     Further, the Audit Committee of the Board of Directors has established “whistle-blowerprocedures” which provides a process for the confidential and anonymous submission, receipt,retention and treatment of complaints regarding accounting, internal accounting controls orauditing matters. These procedures provide substantial protections to employees who report companymisconduct.**Audit Committee Financial Expert**     The Company’s Board of Directors has determined that Mr. Dennis M. Swenson is the Company’saudit committee financial expert.**Identification of Audit Committee**     The Board of Directors currently has an Audit Committee consisting of Messrs. Swenson(Chairman), Kilpatrick and Rhodes. The Audit Committee is responsible for the selection andretention of our independent auditors, reviews the scope of
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the audit functions of the independent auditor, and reviews audit reports rendered by ourindependent auditors. The Audit Committee oversees the Company’s financial reporting process onbehalf of the Board of Directors. Management has the primary responsibility for the financialstatements, accounting policies and procedures, and the reporting process, including the systems ofinternal controls. In fulfilling its oversight responsibilities, the Committee reviewed anddiscussed with management the audited financial statements in this Annual Report on Form 10-KSB forthe year ended August 31, 2005 and the unaudited financial statements included in the QuarterlyReports on Form 10-Q for the first three quarters of the fiscal year ended August 31, 2005.**ITEM 10. EXECUTIVE COMPENSATION****Summary Compensation Table**     The following table sets forth in summary form the compensation received during each of thelast three completed fiscal years ended August 31, 2005 by our Chief Executive Officer, President,Chief Financial Officer and Chairman of The Board and two of our most highly compensated officersserving as of August 31, 2005.                                 Summary Compensation Table  Annual Compensation Long-Term Compensation                  Awards Payouts                Other Annual Restricted Securities LTIP All OtherName and Principal Fiscal Salary Bonus Compensation Stock Underlying Payouts CompensationPosition Year ($)(1) ($)(2) ($)(3) Awards ($) Options(#) ($)(4) ($)(5)D. Scott Singdahlsen                        Chief ExecutiveOfficer,  2005  $175,000   —   —   —   200,000   —   — Chief Financial Officer,