10-K/A 1 pyr802a.txt 10-K/A U.S. Securities And Exchange Commission Washington, D.C. 20549 FORM 10-K/A1* [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended August 31, 2002 [ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [No Fee Required] For the transition period from ____________ to ____________ Commission File No. 0-20879 PYR ENERGY CORPORATION ---------------------- (Name of registrant as specified in its charter) Maryland 95-4580642 -------- ---------- (State or jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 1675 Broadway, Suite 2450, Denver, CO 80202 ------------------------------------- ----- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (303) 825-3748 Securities 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 Exchange ---------------------------- ----------------------- Securities 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 filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such report), and (2) has been subject to such filing requirements for the past 90 days. Yes X No__ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (ss. 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ] As of December 27, 2002, the registrant had 23,701,357 common shares outstanding, and the aggregate market value of the common shares held by non-affiliates was approximately $2,864,000**. This calculation is based upon the closing sale price of 31 cents per share on December 27, 2002. * This Amendment is being filed to include the information required by Part III, Items 11 and 12. For the convenience of the reader, we are filing the entire report in this amendment although the only changes from our Form 10-K filed on November 29, 2002 are to this cover page and the addition of Part III, Items 11 and 12. ** Without asserting that any of the issuer's directors or executive officers, or the entities that own 3,113,923 and 3,634,000 shares of common stock are affiliates, the shares of which they are beneficial owners have been deemed to be owned by affiliates solely for this calculation. TABLE OF CONTENTS ----------------- Page ---- Part I.........................................................................1 Item 1. and Item 2. Business And Properties..............................1 Item 3. Legal Proceedings...............................................23 Item 4. Submission Of Matters To A Vote Of Security Holders.............23 Part II.......................................................................23 Item 5. Market For Common Equity And Related Stockholder Matters........23 Item 6. Selected Financial Data.........................................24 Item 7. Management's Discussion And Analysis Of Financial Condition And Results Of Operations.............................25 Item 7A. Quantitative And Qualitative Disclosures About Market Risk......29 Item 8. Financial Statements And Supplemental Data......................30 Item 9. Changes In And Disagreements With Accountants On Accounting And Financial Disclosure.............................30 Part III......................................................................30 Item 10. Directors And Executive Officers Of Registrant..................30 Item 11. Executive Compensation..........................................32 Item 12. Security Ownership Of Certain Beneficial Owners And Management......................................................35 Item 13. Certain Relationships And Related Transactions..................37 Item 14. Controls and Procedures.........................................38 Part IV.......................................................................38 Item 15. Exhibits, Financial Schedules And Reports On Form 8-K...........38 Signatures....................................................................40 Certifications................................................................41 Index to Consolidated Financial Statements...................................F-1 PART I ITEM 1. and ITEM 2. BUSINESS AND PROPERTIES General PYR Energy Corporation (referred to as "PYR", the "Company", "we", "us" and "our") is a development stage independent oil and gas exploration company with a strategic focus on exploring for and developing significant oil and gas reserves in deep, structurally complex formations. To date, the primary focus of our drilling activity has been in the San Joaquin Basin of California and on our East Lost Hills project there. We initiated this project in 1997 and brought in industry partners and commenced initial drilling in 1998. During the fiscal year ended August 31, 2002, we have focused our exploration efforts on the pre-drill phases of our other high potential exploration projects in the San Joaquin Basin and in the Rocky Mountain region. We continue to acquire acreage positions in exploration areas we have identified as having significant oil and gas reserve potential. The Company was incorporated in March 1996 in the state of Delaware under the name Mar Ventures Inc. Effective as of August 6, 1997, the Company purchased all the ownership interests of PYR Energy, LLC, an oil and gas exploration company. 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 the Company into a wholly owned subsidiary, PYR Energy Corporation, a Maryland corporation. The Company's offices are located at 1675 Broadway, Suite 2450, Denver, Colorado 80202. The telephone number is (303) 825-3748, the facsimile number is (303) 825-3768 and the Company's web site is www.pyrenergy.com. Developments During Fiscal 2002 Property Impairment During the fiscal year ended August 31, 2002, the Company recognized property impairments totaling $11,723,000 in conjunction with its capitalized oil and gas properties. This non-cash accounting charge includes the remaining capitalized balance at the Company's East Lost Hills project of $11,669,000, which includes drilling and completion costs as well as land, geological and geophysical costs. The remaining amount of the impairment includes capital costs associated primarily with a project that the Company has in the Denver Basin of Colorado. See below, "--Drilling Activities". As a result of this write-down, the Company reported a net loss for the year of $13,129,828. For additional information, see below, "--Property Impairment" and Note 1 to the Financial Statements included in this Form 10-K. East Lost Hills, San Joaquin Basin, California During our fiscal year ended August 31, 2002, our East Lost Hills project was subject to continued setbacks and delays. Although the 1998 blow-out of the original test well, the Bellevue #1-17, evidenced high volumes and deliverability of hydrocarbons, the project has still not established meaningful commercial production. Berkley Petroleum Inc., a wholly owned subsidiary of Anadarko Petroleum Corporation, the operator at East Lost Hills, has informed the participant group that it no longer intends to participate in additional operations at East Lost Hills. We are also aware of ongoing litigation between the operator and one of 1 the participants, and feel that this litigation has had a detrimental impact on the project and may have contributed to lack of progress in moving the project forward. In addition, certain leaseholds in the project have expired or will expire in the near future. We have continued to evaluate our ongoing participation in the East Lost Hills project. Although we do not believe that we have adequately evaluated the Temblor potential at East Lost Hills, the historical cost structure of operations and the ongoing uncertainties make it very difficult to continue to participate in this project. We will seek to limit capital expenditures at East Lost Hills until such a point in time as many of the ongoing problems associated with the play are mitigated. There is no assurance that additional operations will occur at East Lost Hills. If additional operations are proposed, we will carefully evaluate to what extent, if any, we will participate in those operations. During fiscal 2002, we participated in three additional wells at East Lost Hills that were proposed and approved by the participant group in fiscal 2001. Two of these wells, the ELH #4 and the ELH #9, are operated by Berkley Petroleum Inc. We have a 12.1193% working interest in each of these wells. The ELH #4 well is approximately four miles southeast of the ELH#1 well with the ELH #9 well located approximately six miles southeast of the ELH #1 well. The ELH #4 well was drilled and completed to a depth of approximately 20,500 feet. Although the well flowed natural gas and liquid hydrocarbons upon initial production testing, we believe that mechanical difficulties related to the influx of wellbore debris has prevented an adequate and full evaluation of the reservoir potential. During initial production testing of the ELH #4, coil tubing was used to attempt to clean out debris in the wellbore. During these clean-out operations, a portion of the coil tubing separated and became stuck in the wellbore. Retrieval operations have not been initiated, and it is uncertain whether or not the coil tubing can be removed from the wellbore. The well is currently shut-in. Although the participant group has not approved or consented, the operator has formally proposed to plug and abandon the well. The ELH #9 well was drilled and completed to a depth of approximately 20,100 feet. Initially, the well was production tested in the Kreyenhagen shale underlying the Temblor formation. Non-commercial hydrocarbons were encountered and tested from this zone, and the participants agreed to move up hole and test the lower Temblor section. These zones were perforated by wireline and limited production of hydrocarbons were encountered. We believe that the perforation and testing methodology may have been inadequate to fully evaluate the reservoir potential and that the production results are inconclusive. This well is currently shut-in. Although the participant group has not approved or consented, the operator has formally proposed to plug and abandon the well. The third well, the AERA Energy LLC #1-22 NWLH, located approximately 3.5 miles northwest of the ELH #1 well, was drilled to a total depth of 20,457 feet. The well encountered hydrocarbon shows and gas flow from several zones in the Temblor and casing has been installed in preparation for production testing. We have determined to prioritize our financial resources on other prospects, and have elected to non-consent the completion and production testing operations. We participated in the drilling of this well through a pooling arrangement at a 4.04% working interest. 2 Funding and Financing On May 24, 2002, we received $6 million in gross proceeds from the sale of convertible notes due May 24, 2009. These notes call for semi-annual interest payments at an annual rate of 4.99% and are convertible into shares of common stock at a conversion price of $1.30 per share. The interest can be paid in cash or added to the principal amount at the discretion of the Company. The notes were issued to three investment funds pursuant to exemptions from registration under Section 3(b) and/or 4(2) of the Securities Act of 1933, as amended. We have reflected the outstanding balance of these notes as Convertible Notes under Long Term Debt on our August 31, 2002 balance sheet. During the fiscal year ended August 31, 2002, we entered into an agreement with Stonington Corporation regarding the retention of Stonington to provide general corporate advisory services and to act as an agent and financial advisor in connection with raising project financing for the exploration and development of certain exploration projects we have in the San Joaquin Basin of California and the Rocky Mountains. We do not intend to sell additional equity in order to finance the drilling of exploration wells, but intend to establish a separate entity that will purchase a portion of our working interests in these projects. Markets and Major Customers Sales of production from our ownership interest in the ELH #1 well at East Lost Hills to ChevronTexaco accounted for all of our revenues. These revenues currently are accruing at approximately $10,000 per month net to our interest. ChevronTexaco has gas gathering and processing capabilities and water disposal facilities in the area. Based on the general demand for gas, if for some unforeseen reason we were to lose ChevronTexaco as a customer, we believe that we would be able to find another customer. However, ChevronTexaco limits the amount of water it accepts at its water disposal facilities. If we are unable to dispose of produced water at the ChevronTexaco water disposal facility and if we are not successful in finding an alternative disposal method, we may not be able to dispose of water and, therefore could not produce and sell natural gas. Employees and Office Space At August 31, 2002, we had seven full time employees. We believe that our relationship with our employees is satisfactory. None of our employees are covered by a collective bargaining agreement. We lease approximately 3,800 square feet of office space in Denver, Colorado for our executive and administrative offices. Business Strategy Our objective is to increase stockholder value per share by adding reserves, production, cash flow, earnings and net asset value. To accomplish this objective, we intend to capitalize on our technical expertise in identifying, evaluating and participating 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: o our inventory of California and Rocky Mountain drilling and exploration projects, o our control of pre-drill exploration phases, and o our expertise in advanced seismic imaging. 3 To implement our strategy, we seek to: o Carefully evaluate to what extent, if any, we will continue to participate in operations at East Lost Hills. The East Lost Hills project has been extremely time, labor and finance intensive. Although we feel there is potential for significant gas reserves, meaningful production has not been established. Because of the current cost structure, continual cost overruns, the lack of a set direction for development and the fragmentation of the participant group, additional operations may not occur. Even in the event additional operations are proposed, we may elect not to participate in additional operations. o Initiate Exploration Drilling on Our Other Projects. We control interests in several other exploration projects in the San Joaquin Basin and in select areas of the Rocky Mountains. The most notable projects in the San Joaquin Basin are our Wedge and Bulldog prospects, which are large target reserve, deep Temblor gas prospects located to the northwest of our East Lost Hills acreage, and our Blizzard prospect which is a light oil Stevens target. In the Rocky Mountains, our most notable projects are Cumberland and Mallard, located in southwestern Wyoming, and our Montana Foothills project. In order to be able to drill initial test wells in these projects, we are in the process of establishing a drilling fund and intend to sell a portion of our working interests in these projects to the drilling fund in exchange for a carried working interest in initial test wells. By combining participation of the drilling fund with potential industry partners, we expect to commence drilling exploration wells in up to five of these projects during calendar 2003. o Continue to Internally Generate Exploration Prospects. We believe that by continuing to generate exploration prospects with a special emphasis on applying our seismic expertise to deep, structurally complex formations, we can identify prospects with significant oil and gas reserve potential. We then assemble acreage positions on these prospects. This enables us to control costs during the pre-drill phases of exploration and to sell a portion of our interests to industry participants, while potentially retaining a carried interest in the initial exploratory drilling. Significant Projects Our exploration activities are focused primarily in the San Joaquin Basin of California and in select areas of the Rocky Mountains. Advanced seismic imaging of the structural and stratigraphic complexities common to these regions provides us with the enhanced ability to identify significant oil and gas reserve potential. A number of these projects offer multiple drilling opportunities with individual wells having the potential of encountering multiple reservoirs. The following is a summary of our exploration areas and significant projects. While actively pursuing specific exploration activities in each of the following areas, we continually review additional opportunities in these core areas and in other areas that meet our exploration criteria. 4 San Joaquin Basin, California The San Joaquin Basin is one of the most productive oil and gas producing basins in the continental United States. Located about 100 miles northwest of Los Angeles, the basin contains 20 fields classified as giant, with each having produced over 100 million barrels of oil equivalent. The San Joaquin Basin contains six of the 25 largest oil fields in the United States. All six of these fields were discovered between 1890 and 1911. The basin accounts for 34% of California's actively producing fields, yet produces more than 78% of the state's total oil and gas production. Most of the production within the basin is located along the western and southern end of Kern County. The San Joaquin Basin has been dominated by major oil companies with large fee acreage holdings and has generally been under-explored by independent exploration and production companies. The large fields in the basin were discovered on surface anticlines and produce predominantly heavy oil from depths of less than 5,000 feet. As a consequence, basin operators have focused on engineering technologies related to enhanced production practices, including steam floods and, most recently, horizontal drilling. Deep basin targets, both structural and stratigraphic in nature, remain largely untested with modern seismic technology and the drill bit. Our analysis of seismic data combined with recent discoveries of hydrocarbons at depth, leads us to believe that multiple deep exploration opportunities exist in the San Joaquin Basin. East Lost Hills. During 1997, we identified and undertook technical analysis of a deep, large, untested structure in the footwall of the Lost Hills thrust. This prospect lies directly east of and structurally below the existing Lost Hills field, which has produced in excess of 350 million barrels of oil equivalent from shallow depths. In early 1998, we entered into an exploration agreement with a number of joint interest partners to participate in the drilling of an initial exploration well. We received cash for our share of acreage in this project and retained a working interest of 10.575%. Of our total working interest, 6.475% was carried in the initial well. During November 2000, we purchased an additional working interest of 1.5443% at East Lost Hills to bring our current working interest to 12.1193%. On May 15, 1998, drilling began on the Bellevue Resources et al. #1-17 East Lost Hills initial exploration well, located in Kern County, California. The well had a target depth of 19,000 feet. On November 23, 1998, the well had just penetrated the uppermost Temblor sand at 17,600 feet when it blew out and ignited. On December 18, 1998, the Bellevue #1-17R relief well began drilling. The relief well was drilled to 16,668 feet, where it intersected the Bellevue #1-17 well bore. On May 29, 1999, the Bellevue #1-17 well was controlled by pumping heavy mud and cement into the well bore. The Bellevue #1-17 well bore has been plugged and abandoned, and the Bellevue #1-17R well was sidetracked as a replacement well into the targeted Temblor formation. The Bellevue #1-17R well production tested nominal amounts of hydrocarbons and is temporarily shut-in awaiting a decision to connect to commercial production facilities. On August 26, 1999, we and other working interest owners began drilling the ELH #1 well, approximately two miles northwest of the Bellevue #1-17R well. On April 12, 2000, this well had drilled to a total depth of 19,724 feet. Production testing began on May 28, 2000. On July 6, 2000, based on the results of the production testing and other analysis, we announced a natural gas discovery at the East Lost Hills field. Onsite production facilities, 8.4 miles of natural gas pipeline and 4.2 miles of water disposal pipeline were installed 5 and, on February 6, 2001, we commenced commercial production of natural gas and liquid hydrocarbons from this well. Production from this well continued throughout fiscal 2002. Since shortly after commencing production on February 6, 2001, the production from the ELH #1 well has been constrained by the lack of adequate capacity for disposal of the produced water. Production water has been and continues to flow through a disposal pipeline connected to disposal facilities owned by ChevronTexaco. ChevronTexaco limits the amount of water accepted at its disposal facility. During the fourth fiscal quarter, the ELH #1 well produced a total of approximately 145 mmcfe, averaging approximately 1.6 mmcfe per day. Water production during this period averaged approximately 6,175 barrels per day. The ELH #4 well commenced drilling on November 26, 2000 at a location approximately four miles southeast of the ELH #1 well. This well reached a total depth of 20,500 feet on January 17, 2002. After installing final casing, the operator released the drilling rig and shut in the well. During July 2002, the Kreyenhagen and lower Temblor zones were perforated via wireline for production testing. The well did flow nominal amounts of natural gas and liquid hydrocarbons along with debris and water. Because the rig had been released and removed, the operator brought in a coil tubing unit to attempt to clean out the debris from the wellbore. During this operation, a portion of the coil tubing separated from the assembly and became lodged in the wellbore. It is uncertain whether or not the component of coil tubing can be retrieved. The well is currently shut-in and although the participant group has not consented or otherwise agreed, the operator has formally proposed plugging this well. The ELH #9 well, located approximately six miles southeast of the ELH #1 well, commenced drilling operations on July 17, 2001. On April 10, 2002, the well reached total depth of approximately 21,100 feet. Final casing was installed and the operator released the drilling rig on April 27, 2002. During July 2002, the Kreyenhagen zone was perforated via wireline for production testing. This testing resulted in delivery of non-commercial volumes of hydrocarbons and attempts to stimulate the test zones were unsuccessful. The lower Temblor was then perforated for production testing. During production testing, the well flowed nominal amounts of hydrocarbons, water and debris resulting in plugging of perforations and the wellbore. Coil tubing was used to clean out the debris and further testing resulted in deliverability of hydrocarbons in nominal amounts. Due to the perforation and testing methods used, we view these production tests as inconclusive and do not reflect full evaluation of the lower Temblor potential. Although there may be additional productive Temblor zones above the lower Temblor, additional testing has not been proposed. The operator has formally proposed the plugging of this well, however the participants have not yet consented or otherwise agreed to this proposal. During fiscal 2002, we participated in the drilling of a third well at East Lost Hills. The Aera Energy LLC NWLH 1-22 well located in Section 22, T25S-R20E commenced drilling on August 23, 2001. This well is approximately three and a half miles northwest of the ELH #1 well. We participated in the drilling of this well, operated by Aera Energy LLC, through a pooling arrangement at a 4.04% working interest. On August 18, 2002, this well reached total depth of 20,457 feet. The participants intend to complete the well for production testing, however we have been notified by the operator that certain participants do not currently have the financial ability to proceed with the completion and are attempting to raise additional funds or bring in additional participants. Since late August 2002, the drilling rig has remained on location on standby rate in anticipation of the commencement of completion operations. Because we have determined to prioritize our financial resources on other prospects, we have notified the operator of our non-consent election in the completion of this well. 6 Pyramid Power Prospect. In April 1999, we purchased a working interest in the Pyramid Power deep natural gas exploration project in the San Joaquin Basin. This project is outside the East Lost Hills joint venture area. The initial test well, located in Section 9, T25S-R18E, commenced drilling on November 22, 2001. On July 17, 2002, the well reached total depth of 20,465 feet. Upon running final casing, the rig was released. Berkley Petroleum Inc., a wholly owned subsidiary of Anadarko Petroleum Corporation was operator of the well during drilling. Upon release of the rig, Oxy Lost Hills Inc. ("Oxy") took over as operator and Oxy will operate the completion and production testing of this well. We originally owned a working interest in this project of 3.75%, but have committed to assign 25% of that interest to Oxy. The new working interest of 2.81% continues to be carried through the tanks in this initial test well. The participants at Pyramid Power jointly control approximately 16,100 gross and 14,700 net acres over the prospect. Wedge Prospect. This is a seismically identified Temblor prospect located northwest of and adjacent to the East Lost Hills deep gas discovery. During the first fiscal quarter of 2001, we acquired approximately 17 miles of proprietary, high effort 2D seismic data and combined this data with existing 2D seismic data in order to refine what we interpret as the up-dip extension of the East Lost Hills structure. Our seismic interpretation shows that the same trend at East Lost Hills extends approximately ten miles further northwest of the East Lost Hills Area of Mutual Interest and can be encountered as much as 3,000 feet higher. We currently control approximately 12,100 gross and approximately 11,600 net acres here. Our approach is to sell down our working interest and retain a 25% to 50% working interest in this prospect. Bulldog Prospect. This project is a 2D seismically identified natural gas and condensate prospect located adjacent to the giant Kettleman North Dome field in the San Joaquin Basin. This prospect can be best characterized as a classic footwall fault trap, similar to the many known footwall fault trap accumulations that have produced significant quantities of hydrocarbons throughout the San Joaquin basin. We currently control approximately 15,600 gross and approximately 15,100 net acres here. We expect to sell down our working interest in this project and retain a 25% to 50% working interest in the prospect acreage and in a 14,000 foot test well we expect to drill during calendar 2003. Rocky Mountain Exploration Montana Foothills Project. This extensive natural gas exploration project, located in northwestern Montana, is part of the southern Alberta basin, and has been classified as the southern extension of the Alberta Foothills producing province. The USGS and numerous Canadian industry sources have estimated significant recoverable reserves for the Montana portion of the Foothills trend. Based on extensive geologic and seismic analysis, we have identified numerous structural culminations of similar size, geometry, and kinematic history as prolific Canadian foothills fields, such as Waterton and Turner Valley. The geologic setting and hydrocarbon potential of this area was not recognized by industry until the early 1980s. At that time, a number of companies initiated exploration efforts, including Exxon, Arco, Chevron, Amoco, Conoco, and Unocal. This initial exploration phase culminated in a deep test by Unocal in 1989. Although this well was unsuccessful, recent improvements in seismic imaging and pre-stack processing have resulted in our belief that this test well was drilled based upon a misleading seismic image and was located significantly off-structure. 7 We currently control approximately 241,800 gross and 226,300 net acres in this project and are currently presenting this project to potential industry participants in order to sell down our working interest and generate exploratory drilling activity. We anticipate retaining a working interest in this project of between 20% and 40%. Cumberland Project. The Cumberland project, located within the Overthrust Belt of southwest Wyoming, is a gas-condensate exploration prospect in Uinta County, Wyoming. Cumberland is at the northern end of the historically productive Nugget trend on the hangingwall of the Absaroka thrust fault. The prospect lies along trend of and just north of Ryckman Creek field, which was discovered in 1975. The Cumberland prospect can be best characterized as a classic hangingwall anticlinal trap, similar to the many known Nugget sandstone accumulations that have produced significant quantities of hydrocarbons from Pineview to Ryckman Creek. The Cumberland culmination is the result of structural deformation related to back-thrusting off of the Absaroka thrust, a similar geometry to that exhibited at East Painter Reservoir field. We currently control approximately 5,400 gross and net acres in the project and expect to sell down our working interest to between 25% and 50%. We have recently received approval for our drilling permit from the State of Wyoming and we intend to commence the drilling of an initial exploration well during 2003. Mallard Project. The Mallard project, located within the Overthrust Belt of SW Wyoming, is a sour gas and condensate exploration prospect in Uinta County, Wyoming. Mallard is within the Paleozoic trend of productive fields on the Absaroka thrust. Mallard directly offsets and is adjacent to the giant sour gas field of Whitney Canyon-Carter Creek. We interpret the Mallard prospect to occupy a separate fault block, adjacent to the Whitney Canyon field, generated by a complex imbricated system of faults spaying off of the Absaroka thrust. Paleozoic targets at the Mallard prospect include the Mississippian Mission Canyon, as well as numerous secondary objectives in the Ordovician, Pennsylvanian, and Permian sections. We currently control approximately 3,900 gross and net acres in the project and expect to sell down our working interest to between 25% and 50%. We intend to commence the drilling of an initial exploration well during 2003. Certain Definitions Unless otherwise indicated in this document, oil equivalents are determined using the ratio of six Mcf of natural gas to one barrel of crude oil, condensate or natural gas liquids so that six Mcf of natural gas are referred to as one barrel of oil equivalent. As used in this document, the term "Mcf" means thousand cubic feet. Capital Expenditures. Costs associated with exploratory and development drilling (including exploratory dry holes); leasehold acquisitions; seismic data acquisitions; geological, geophysical and land related overhead expenditures; delay rentals; producing property acquisitions; other miscellaneous capital expenditures; compression equipment and pipeline costs. 8 Carried through the tanks. The owner of this type of interest in the drilling of a well incurs no liability for costs associated with the well until the well is drilled, completed and connected to commercial production/processing facilities. Developed Acreage. The number of acres that are allocated or assignable to producing wells or wells capable of production. Development Well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory Well. A well drilled to find and produce oil or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir. 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 of proved reserves added in the specified period. Gross Acres or Gross Wells. The total acres or wells, as the case may be, in which we have a working interest. Net Acres or Net Wells. A net acre or well is deemed to exist when the sum of our fractional ownership working interests in gross acres or wells, as the case may be, equals one. The number of net acres or wells is the sum of the fractional working interests owned in gross acres or wells, as the case may be, expressed as whole numbers and fractions thereof. Operator. The individual or company responsible to the working interest owners for the exploration, development and production of an oil or natural gas well or lease. Participant Group. The individuals and/or companies that, together, comprise the ownership of 100% of the working interest in a specific well or project. Reserves. Natural gas and crude oil, condensate and natural gas liquids on a net revenue interest basis, found to be commercially recoverable. Sidetrack. An operation involving the use of a portion of an existing well to drill a second hole at some desired angle into previously undrilled areas. From this directional start, a new hole is drilled to the desired formation depth and casing is set in the new hole and tied back to the casing from the existing well. Undeveloped Acreage. Lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether or not such acreage contains proved reserves. Working Interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. 9 Production and Productive Wells On February 6, 2001, we commenced our first production from the ELH #1 well at East Lost Hills and this production continued throughout fiscal 2002. At August 31, 2002, the Company had production from only the ELH #1 well. During the fiscal year ended August 31, 2002, the Company's net share of production from this well was 39,468 mcf of natural gas and 1,600 barrels of liquid hydrocarbons. Drilling Activities During the past three fiscal years, we participated in the drilling of the following exploration and development wells: o During the fiscal year ended August 31, 2002, we continued our participation in three gross (0.283 net) development wells at East Lost Hills. We also participated in one gross (0.00 net) exploration well at the Pyramid Power prospect with a carried through the tanks working interest. The ELH #4 well reached a total depth of approximately 20,500 feet on November 17, 2001. The ELH #9 well reached a total depth of approximately 21,100 feet on April 10, 2002 and the Aera Energy LLC NWLH 1-22 well reached a total depth of 20,457 feet on August 16, 2002. o During the fiscal year ended August 31, 2001, we participated in the drilling of three gross (0.283 net) development wells, all at East Lost Hills. The ELH #4 well commenced drilling on November 26, 2000. The ELH #9 well commenced drilling on July 18, 2001, and on August 23, 2001, the Aera Energy LLC NWLH 1-22 well commenced drilling. o During the fiscal year ended August 31, 2000, we participated in the drilling of one gross (0.121 net) exploration well and one gross (0.121 net) development well that commenced drilling during that fiscal year. The exploration well is the ELH #3 and the development well is the ELH #2. The ELH #2 well reached total depth in December 2000 and was completed and production tested. This well has been suspended pending potential connection to processing facilities. The ELH #3 well was found to contain hydrocarbons in non-commercial amounts. In addition, in October 2002 we participated in the drilling of an exploratory well in the DJ Basin of Colorado. This well, which was drilled to a depth of approximately 4,800 feet was found to contain non-commercial deliverability of hydrocarbons and was plugged and abandoned. Although there is no assurance that any additional wells will be drilled, we anticipate we may commence drilling up to five exploration wells during fiscal 2003 on our exploration projects other than East Lost Hills. We do not expect to participate in the drilling of any additional wells at East Lost Hills during 2003. The actual number of wells drilled will be dependent on several factors, including the results of our ongoing exploration efforts and the availability of capital. Reserves We commenced our first production from the ELH #1 well at East Lost Hills on February 6, 2001. Concurrent with the end of our fiscal year ended August 31, 2001, we engaged Netherland, Sewell & Associates, Inc., independent petroleum engineers, to prepare a reserve report for the reserves related to our ownership interest in the East Lost Hills project. Based on this historical data of 10 constrained production and drilling costs affected by significant mechanical difficulties, the reserve report concludes that it would be uneconomic to produce oil and gas reserves at East Lost Hills. Therefore, at August 31, 2001, the reserve report from our independent petroleum engineers shows no proved reserves. No additional meaningful production was established during fiscal 2002 and, accordingly, no reserve report was prepared as of the August 31, 2002 fiscal year end. Previous to August 31, 2001, all of our oil and gas properties were classified as undeveloped, and no reserve reports were warranted. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment and the existence of development plans. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. Further, the estimated future net revenues from proved reserves and the present value thereof are based upon certain assumptions, including geologic success, prices, future production levels and cost, that may not prove correct over time. Predictions about prices and future production levels are subject to great uncertainty, and the meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Property Impairment As required for oil and gas companies that utilize the full cost method of accounting for oil and gas activities, we capitalize all costs associated with acquisition, exploration and development activities. Capitalized costs, excluding costs of investments in unproved properties and major development projects, are subject to a "ceiling test limitation". Under the ceiling test, capitalized costs may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves. If capitalized costs exceed this ceiling, an impairment is recognized. As described above under "--Reserves," we had no proved reserves as of August 31, 2002. As a result, we are required to record an impairment against our entire amortizable cost pool. This charge has no impact on our cash or cash flows. At August 31, 2002, our amortizable cost pool was comprised of East Lost Hills drilling and completion costs associated with our working interests in the ELH #4, ELH #9, and the Aera NWLH 1-22 wells and allocated land, geological and geophysical costs in the aggregate amount of approximately $11,669,000, and capital costs associated primarily with a Colorado DJ Basin project in the amount of approximately $54,000. Additional discussion of the charge, including information regarding the methodology prescribed for computing the full cost ceiling, is presented in Note 1 to our Financial Statements in this Annual Report on Form 10-K. Acreage We currently control through lease, farmout, and option, the following approximate acreage position as detailed below: State Gross Acres Net Acres ----- ----------- --------- California 65,000 35,000 Montana 242,000 226,000 Wyoming 12,000 12,000 ------- ------- TOTAL 319,000 273,000 ======= ======= 11 Competition We compete with numerous companies in virtually all facets of our business, including many companies that have significantly greater resources. These competitors may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Our ability to establish and increase reserves in the future will be dependent on our ability to select and acquire suitable producing properties and prospects for future exploration and development. The availability of a market for oil and gas production depends upon numerous factors beyond the control of producers, including but not limited to the availability of other domestic or imported production, the locations and capacity of pipelines, and the effect of federal and state 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 in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations. We do not currently operate any properties. We believe that operations where we own interests comply in all material respects with applicable laws and regulations and that the existence and enforcement of these laws and regulations have no more restrictive an effect on our operations than on other similar companies in the energy industry. The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing and by reference to the full text of the laws and regulations described. Federal Regulation of the Sale and Transportation of Oil and Gas. Various aspects of our oil and gas operations are or will be regulated by agencies of the federal government. The Federal Energy Regulatory Commission, or FERC, regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938, or NGA, and the Natural Gas Policy Act of 1978, or NGPA. In the past, the federal government has regulated the 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 at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead 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 wellhead sales of natural gas effective January 1, 1993. Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B, 636-C and 636-D ("Order No. 636"), which require interstate pipelines to provide transportation services separately, or "unbundled," from the pipelines' sales of gas. Also, Order No. 636 requires pipelines to provide open access 12 transportation on a nondiscriminatory basis that is equal for all natural gas shippers. Although Order No. 636 does not directly regulate our production activities, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. It is unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on our activities. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify their open access regulations. In particular, the FERC is conducting a broad review of its transportation regulations, including how they operate in conjunction with state proposals for retail gas market restructuring, whether to eliminate cost-of-service rates for short-term transportation, whether to allocate all short-term capacity on the basis of competitive auctions, and whether changes to long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. In February 2000, the FERC issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to "fine tune" the open access regulations implemented by Order No. 636 to accommodate subsequent changes in the market. Key provisions of Order No. 637 include: (1) waiving the price ceiling for short-term capacity release transactions until September 30, 2002, subject to review and possible extension of the program at that time; (2) permitting value-oriented peak/off peak rates to better allocate revenue responsibility between short-term and long-term markets; (3) permitting term-differentiated rates, in order to better allocate risks between shippers and the pipeline; (4) revising the regulations related to scheduling procedures, capacity, segmentation, imbalance management, and penalties; (5) retaining the right of first refusal ("ROFR") and the five year matching cap for long-term shippers at maximum rates, but significantly narrowing the ROFR for customers that the FERC does not deem to be captive; and (6) adopting new website reporting requirements that include daily transactional data on all firm and interruptible contracts and daily reporting of scheduled quantities at points or segments. The new reporting requirements became effective September 1, 2000. We cannot predict what action the FERC will take on these matters in the future, nor can we accurately predict whether the FERC's actions will, over the long term, achieve the goal of increasing competition in markets in which our natural gas, once produced, is sold. However, we do not believe that we will be affected by any action taken materially differently than other natural gas producers and marketers with which we compete. Commencing in October 1993, the FERC issued a series of rules (Order Nos. 561 and 561-A) establishing an indexing system under which oil pipelines are able to change their transportation rates, subject to prescribed ceiling levels. The indexing system, which allows pipelines to make rate changes to track changes in the Producer Price Index for Finished Goods, minus one percent, became effective January 1, 1995. We do not believe that these rules affect us any differently than other oil producers and marketers with which we will compete. The FERC also has issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the FERC does not have jurisdiction over services provided on those facilities, then those facilities and services may be subject to regulation by state authorities in accordance with state law. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. Our anticipated gathering 13 operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although we do not believe that we would be affected by such regulation any differently than other natural gas producers or gatherers. In addition, the FERC's approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to FERC regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future. We conduct certain operations on federal oil and gas leases, which are administered by the Minerals Management Service, or MMS. Federal leases contain relatively standard terms and require compliance with detailed MMS regulations and orders, which are subject to change. Among other restrictions, the MMS has regulations restricting the flaring or venting of natural gas, and has proposed to amend those regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Under certain circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition, cash flows and operations. The MMS recently issued a final rule that amended its regulations governing the valuation of crude oil produced from federal leases. This new rule, which became effective June 1, 2000, provides that the MMS will collect royalties based on the market value of oil produced from federal leases. The lawfulness of the new rule has been challenged in federal court. We cannot predict whether this new rule will be upheld in federal court, nor can we predict whether the MMS will take further action on this matter. However, we do not believe that this new rule will affect us any differently than other producers and marketers of crude oil with which we will compete. Additional proposals and proceedings that might affect the oil and gas industry are pending before Congress, the FERC, the MMS, state commissions and the courts. We cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, we do not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or 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 of contracts or subcontracts at the election of the federal government. State Regulation. Our operations also are subject to regulation at the state and, in some cases, county, municipal and local governmental levels. This regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandonment of wells and the disposal of fluids used and produced in connection with operations. Our operations also are or will be subject to various conservation laws and regulations. These include (1) the size of drilling and spacing units or proration units, (2) the density of wells that may be drilled, and (3) the unitization or pooling of oil and gas properties. In addition, state conservation laws, which frequently establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but (except as noted above) does not generally entail rate regulation. These regulatory burdens may affect profitability, but we are unable to predict the future cost or impact of complying with such regulations. Further, pursuant to a 1996 law passed by the California State Assembly, certain segments of the power generation industry in the state were deregulated. Toward the end of calendar 2000, this statute, along 14 with the significantly increased demand for natural gas, the increased price of natural gas and other fuels, and the overall increase in the demand for and cost of power generation had created a major crisis in California. The crisis threatened to bankrupt many electric utilities because of state-imposed limits on the ability to pass costs through to the utilities' customers. Because of a general decline in demand for natural gas, the build up of natural gas in storage and the resulting decrease in natural gas prices, the energy crisis in California does not currently exist. However, because natural gas-driven turbines generate a substantial portion of California's electricity supply, it is possible that laws or regulations imposed at the state or federal level intended to alleviate a potential future crisis would have a material adverse impact on natural gas prices, marketing activities, operations or production. Environmental Matters. Operations on properties in which we have an interest are subject to extensive federal, state and local environmental laws that regulate the discharge or disposal of materials 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 company liable for environmental and natural resource damages, cleanup costs and, in the case of oil spills in certain states, consequential damages without regard to negligence or fault. Other laws, rules and regulations may require the rate of oil and gas production to be below the economically optimal rate 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 inactive pits 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 to time that would reclassify certain oil and gas exploration and production wastes as "hazardous wastes." 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 on operating costs. Initiatives to further regulate the disposal of oil and gas wastes are also proposed in certain states from time to time and may include initiatives at the county, municipal and local government levels. These various initiatives could have a similar adverse impact on operating costs. The regulatory burden of environmental laws and regulations increases our cost and 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 classes of persons with respect to the release of a "hazardous substance" into the environment. These persons include the current or prior owner or operator of the disposal site or sites where the release occurred and companies that transported, disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for the federal or state government to pursue such claims. It is also not uncommon for neighboring landowners and other third parties to file claims for personal injury or property or natural resource damages allegedly caused by the hazardous substances released into the environment. Under CERCLA, certain oil and gas materials and products are, by definition, excluded from the term "hazardous substances." At least two federal courts have held that certain wastes associated with the production of crude oil may be classified as hazardous substances under CERCLA. Similarly, under the federal Resource, Conservation and Recovery Act, or RCRA, which governs the generation, treatment, storage and disposal of "solid wastes" and "hazardous wastes," certain oil and gas materials 15 and wastes are exempt from the definition of "hazardous wastes." This exemption continues to be subject to judicial interpretation and increasingly stringent state interpretation. During the normal course of operations on properties in which we have an interest, exempt and non-exempt wastes, including hazardous wastes, that are subject to RCRA and comparable state statutes and implementing regulations are generated or have been generated in the past. The federal Environmental Protection Agency and various state agencies continue to promulgate regulations that limit the disposal and permitting 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 and administrative and compliance costs. To date, other compressor facilities have not triggered Title V requirements due to the design of the facility and the use of state-of-the-art engines and pollution control equipment that serve to reduce air emissions. However, in the future, additional facilities could become subject to Title V requirements as compressor facilities are expanded or if regulatory interpretations of Title V applicability change. Stack testing and emissions monitoring costs will grow as these facilities are expanded and if they trigger Title V. We believe that the operator of the properties in which we have an interest is in substantial compliance with applicable laws, rules and regulations relating to the control of air emissions at all facilities on those properties. 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 is no assurance that our insurance will be adequate to cover all such costs, that the insurance will continue to be available in the future or that the insurance will be available at premium levels that justify our purchase. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our financial condition and operations. Compliance with environmental requirements, including financial assurance requirements and the costs associated with the cleanup of any spill, could have a material adverse effect on our capital expenditures, earnings or competitive position. We do believe, however, that our operators are in substantial compliance with current applicable environmental laws and regulations. Nevertheless, changes in environmental laws have the potential to adversely affect operations. At this time, we have 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 conducted at the time we acquire leases or enter into other agreements to obtain control over interests in acreage believed to be suitable for drilling operations. In many instances, our partners have acquired rights to the prospective acreage and we have a contractual right to have our interests in that acreage assigned to us. In some cases, we are in the process of having those interests so assigned. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted by independent attorneys. Once production from a given well is established, the operator will prepare a division order title report indicating the proper parties and percentages for payment of production proceeds, including royalties. We believe that titles to our leasehold properties are good and defensible in accordance with standards generally acceptable in the oil and gas industry. 16 Risk Factors In evaluating the Company, careful consideration should be given to the following risk factors, in addition to the other information included or incorporated by reference in this annual report. In addition, the "Forward-Looking Statements" located herein, describe additional uncertainties associated with our business and the forward-looking statements included or incorporated 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 investment in our common stock. We have a limited operating history in the oil and gas business. Our operations to date have consisted solely of evaluating geological and geophysical information, acquiring acreage positions, generating exploration prospects, and drilling a limited number of wells on deep oil and gas prospects. We currently have seven full-time employees. Our future financial results depend primarily on (1) our ability to discover commercial quantities of oil and gas; (2) the market price for 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 our future operations will be profitable. In addition, our operating results may vary significantly during any financial period. These variations may be caused by significant periods of time between discovery and development of oil or gas reserves, if any, in commercial quantities. We may not discover commercially productive reserves. Our future success depends on our ability to economically locate oil and gas reserves in commercial quantities. Except to the extent that we acquire properties containing proved reserves or that we conduct successful exploration and development activities, or both, our proved reserves, if any, will decline as reserves are produced. Our ability to locate reserves is dependent upon a number of factors, including our participation in multiple exploration projects and our technological capability to locate oil and gas in commercial quantities. We cannot predict that we will have the opportunity to participate in projects that economically produce commercial quantities of oil and gas in amounts necessary to meet 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 we will have future success in drilling productive wells at economical reserve replacement costs. Exploratory drilling is an uncertain process with many risks. Exploratory drilling involves numerous risks, including the risk that we will not find any commercially productive oil or gas reservoirs. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including: o unexpected drilling conditions, o pressure or irregularities in formations, o equipment failures or accidents, o adverse weather conditions, o compliance with governmental requirements, o shortages or delays in the availability of drilling rigs and the delivery of equipment, and o shortages of trained oilfield service personnel. Our future drilling activities may not be successful, nor can we be sure that our overall drilling success rate or our drilling success rate for activities within a particular area will not decline. Unsuccessful drilling activities could have a material adverse effect on our results of operations and financial condition. Also, we may not be able to obtain any options or lease 17 rights in potential drilling locations that we identify. Although we have identified a number of potential exploration projects, we cannot be sure that we will ever drill them or that we will produce 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 a result of decreased reservoir pressures, large amounts of water, or other factors that might be encountered. As a result of these types of risks, most lenders will not loan funds secured by reserves from newly discovered reservoirs, which would have a negative impact on our future liquidity. Operational risks include hazards such as fires, explosions, craterings, blowouts (such as the blowout experienced at our initial exploratory well), uncontrollable flows of oil, gas or well 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 own or lease. As a result, we may face substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for exploration, development or acquisitions or cause us to incur substantial losses. We expect to maintain insurance against some, but not all, of the risks associated with drilling and production in amounts that we believe to be reasonable in accordance with customary industry practices. The occurrence of a significant event, however, that is not fully insured could 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 require us to make large capital expenditures for the exploration and development of our oil and gas projects. Under our current capital expenditure budget, we expect to spend a minimum of approximately $3 million on exploration and development activities during our fiscal year ending August 31, 2003. 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. Volatility in the price of our common stock, which may be significantly influenced by our drilling and production activity, may impede our ability to raise money quickly, if at all, through the issuance of equity at acceptable prices. We currently do not have any sources of additional financing. Future cash flows and the availability of financing will be subject to a number of variables, such as: o the success of our natural gas project in the San Joaquin Basin, o our success in locating and producing reserves in other projects, o the level of production from existing wells, and o prices of oil and gas. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders. Debt financing, if obtained, could lead to: o a substantial portion of our operating cash flow being dedicated to the payment of principal and interest, o our being more vulnerable to competitive pressures and economic downturns, and o restrictions on our operations. 18 If our revenues were to decrease due to lower oil and gas prices, decreased production or other reasons, and if we could not obtain capital through a credit facility or otherwise, our ability to execute our development plans, obtain and replace reserves, or maintain production levels could be greatly limited. We depend heavily on exploration success and subsequent success in developing our exploration projects. Our future growth plans rely heavily on discovering reserves and initiating production in the San Joaquin Basin and in the Rocky Mountains. This lack of diverse business operations subjects us to a high degree of risk. Our development plan includes the need to discover reserves and establish commercial production through exploratory drilling and development of our existing properties. We cannot be sure, though, that our planned projects will lead to significant reserves that can be economically extracted or that we will be able to drill productive wells at anticipated finding and development costs. If we are able to record reserves, our reserves will decline as they are depleted, except to the extent that we conduct successful exploration or development activities or acquire other properties containing proved reserves. We depend on industry alliances. We attempt to limit financial exposure on a project-by-project basis by forming industry alliances where our technical expertise can be complemented with the financial resources and operating expertise of more established companies. While entering into these alliances limits our financial exposure, it also limits our potential revenue from successful projects. Industry alliances also have the potential to expose us to uncertainty if our industry partners are acquired or have priorities in areas other than our projects. Despite these risks, we believe that if we are not able to form industry alliances, our ability to fully implement our business plan could be limited, which could have a material adverse effect on our business. Our non-operator status limits our control over our oil and gas projects. We focus primarily on creating exploration opportunities and forming industry alliances to develop those opportunities. As a result, we have only a limited ability to exercise control over a significant portion of a project's operations or the associated costs of those operations. The success of a project is dependent upon a number of factors that are outside our areas of expertise and control. These factors include: o the availability of leases with favorable terms and the availability of required permitting for projects, o the availability of future capital resources to us and the other participants to be used for purchasing leases and drilling wells, o the approval of other participants for the purchasing of leases and the drilling of wells on the projects, and o the economic conditions at the time of drilling, including the prevailing and anticipated prices for oil and gas. Our reliance on other project participants and our limited ability to directly control project costs 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 business prospects. Our future profitability and rate of growth and the anticipated carrying value of our oil and gas properties will depend heavily on then prevailing market prices for oil and gas. We expect the markets for oil and gas to continue to be volatile. If we are successful in continuing to establish production, any substantial or extended decline in the price of oil or gas could: 19 o have a material adverse effect on our results of operations, o limit our ability to attract capital, o make the formations we are targeting significantly less economically attractive, o reduce our cash flow and borrowing capacity, and o reduce the value and the amount of any future reserves. Various factors beyond our control will affect prices of oil and gas, including: o worldwide and domestic supplies of oil and gas, o the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls, o political instability or armed conflict in oil or gas producing regions, o the price and level of foreign imports, o worldwide economic conditions, o marketability of production, o the level of consumer demand, o the price, availability and acceptance of alternative fuels, o the availability of processing and pipeline capacity, o weather conditions, and o actions of federal, state, local and foreign authorities. These external factors and the volatile nature of the energy markets make it difficult to estimate 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 costs of proved oil and gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the end of each fiscal quarter and requires a write-down for accounting purposes if the ceiling is exceeded. If a write-down is required, it would result in a charge to earnings, but would not impact cash flow from operating activities. Once incurred, a write-down of oil and gas properties is not reversible at a later date. We commenced our first oil and gas production on February 6, 2001, resulting in a change of classification of a component of our capitalized oil and gas properties from undeveloped to developed. We engaged an independent engineering firm to conduct a reserve analysis and to prepare a reserve report for the East Lost Hills project. This report reflected no economic reserves at our fiscal year ended August 31, 2001. As a result, we recorded a write-down of approximately $13,340,000 to reduce the carrying value of our oil and gas properties. No additional meaningful production was established during our fiscal year ended August 31, 2002, and we recorded an additional impairment of $11,723,000 against our oil and gas properties. Additional discussion of this charge is presented in Note 1 to our Financial Statements in this Annual Report on Form 10-K. We face risks related to title to the leases we enter into that may result in additional costs and affect our operating results. It is customary in the oil and gas industry to acquire a leasehold 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 to have our interests in that acreage assigned to us. In some cases, we are in the process of having those interests so assigned. If the title to the leases acquired is defective, or title to the leases one of our partners acquires for our benefit is defective, we could lose the money already spent 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 partners does not assign to us our interest in a lease acquired for our benefit, 20 we will not have the right to participate in the development of or production from the leased properties. In addition, it is possible that the terms of our oil and gas leases may be interpreted differently depending on the state in which the property is located. For instance, royalty calculations can be substantially different from state to state, depending on each state's interpretation of lease language concerning the costs of production. We cannot guarantee that there will be no litigation concerning the proper interpretation of the terms of our leases. Adverse decisions in any litigation of this kind could result in material costs or the loss of one or more leases. 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 competitors have financial and technological resources vastly exceeding those available to us. We cannot be sure that we will be successful in acquiring and developing profitable properties in the face of this 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 costs and delays in operations that could have a material adverse effect on our business and our ability to develop our properties. Problems of this nature also could prevent us from producing any oil and 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 is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As new technologies develop, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those new technologies at a substantial cost. If other oil and gas exploration and development companies implement new technologies before we do, those companies may be able to provide enhanced capabilities and superior quality compared with what we are able to provide. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If we are unable to utilize the most advanced commercially available technologies, our business could be materially and adversely affected. Our industry is heavily regulated. Federal, state and local authorities extensively regulate the oil and gas industry. Legislation and regulations affecting the industry are under constant review for amendment or expansion, raising the possibility of changes that may affect, among other things, the pricing or marketing of oil and gas production. State and local authorities regulate various 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 oil and gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and restoration. The overall regulatory burden on the industry increases the cost of doing business, which, in turn, decreases profitability. Our operations must comply with complex environmental regulations. Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities. New laws or regulations, or changes to current requirements, could have a material adverse effect on our business. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between state and federal agencies. We could face significant liabilities to the government and third parties for discharges of oil, natural gas, produced water or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation. We cannot be sure that existing environmental laws or regulations, as currently interpreted or enforced, or as they may be interpreted, enforced or altered in the future, will not have a material adverse effect on our results of operations and financial condition. 21 Our business depends on transportation facilities owned by others. The marketability of our anticipated gas production depends in part on the availability, proximity and capacity of pipeline systems owned or operated by third parties. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions 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, we desire to grow rapidly in order to achieve certain economies of scale. Although there is no assurance that this rapid growth will occur, to the extent that it does occur, it will place a significant strain on our financial, technical, operational and administrative resources. As we increase our services and enlarge the number of projects we are evaluating or in which we are participating, there will be additional demands on our financial, technical and administrative resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the recruitment and retention of geoscientists and engineers, could have a material adverse effect on our business, financial condition and results of operations. We may not be able to retain our listing on the American Stock Exchange. The American Stock Exchange has certain listing requirements in order for a company to continue to have their securities traded on this exchange. Although the American Stock Exchange does not identify a specific minimum price per share that a company's stock must trade above, a company may risk delisting if their common stock trades at a low price per share for a substantial period of time. We have not been notified of any listing concerns by the American Stock Exchange. However, should our stock trade at a low share price for a substantial period of time, we may not be able 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 an employment 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 of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including statements regarding, among other items, our business and growth strategies, anticipated trends in our 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 impact of governmental regulation. These forward-looking statements are based largely on our expectations and are subject to a number of risks and uncertainties, many of which are beyond our control. Actual results could differ materially from these forward-looking statements as a result of, among other things: o failure to obtain, or a decline in, oil or gas production, or a decline in oil or gas prices, o incorrect estimates of required capital expenditures, o increases in the cost of drilling, completion and gas collection or other costs of production and operations, o an inability to meet growth projections, and o 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 similar expressions, as they relate to PYR, our business or our management, are intended to identify forward-looking statements. 22 ITEM 3. LEGAL PROCEEDINGS The Company is not a party to any other current or pending legal proceeding (nor are any of the Company's properties subject to a pending legal proceeding). ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of the Company's security holders during the fourth quarter of the fiscal year ended August 31, 2002. PART II ITEM 5. 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. Before then it was included for quotation on the OTC Bulletin Board under the symbol "PYRX." The following table sets forth the range of high and low sales prices per share of our common stock for the periods indicated. High Low ------------------- Fiscal Year Ended August 31, 2001 First Quarter..................... $7.625 $4.500 Second Quarter.................... 9.960 6.000 Third Quarter..................... 9.900 5.070 Fourth Quarter.................... 8.700 1.750 Fiscal Year Ended August 31, 2002 First Quarter..................... $2.830 $1.500 Second Quarter.................... 2.700 1.800 Third Quarter..................... 2.250 1.150 Fourth Quarter.................... 2.350 0.700 On December 27, 2002, the last reported sales price of our common stock on the AMEX was 31 cents. Stockholders Of Record As of December 27, 2002, the number of record holders of our common stock was approximately 600 and the number of beneficial owners of our common stock was approximately 3,300. 23 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 On May 24, 2002, we received $6 million in gross proceeds from the sale of convertible notes due May 24, 2009. These notes call for semi-annual interest payments at an annual rate of 4.99% and are convertible into shares of common stock at a conversion price of $1.30 per share. The interest can be paid in cash or added to the principal amount at the discretion of the Company. The notes were issued to three investment funds pursuant to exemptions from registration under Section 3(b) and/or 4(2) of the Securities Act of 1933, as amended. Proceeds from the notes will be used for capital expenditures related to our oil and gas activities, for administrative costs and for other related costs. On January 5, 2001, our "shelf" registration statement (SEC file number 333-51764), pertaining to the sale from time to time of up to $75 million of our securities, was declared effective by the Securities and Exchange Commission. The securities that may be offered by the Company pursuant to this registration statement may include shares of common stock, shares of preferred stock, which may be issued in the form of depositary shares evidenced by depositary receipts, warrants to purchase common stock, preferred stock or any combination of those securities, or any combination of any of these securities. On March 9, 2001, we received a total of $11.6 million in gross proceeds from the sale of 1,450,000 shares of our common stock. The common stock was sold pursuant to a prospectus supplement with respect to the shelf registration statement. We incurred offering expenses of $160,470 in this offering, so that we received net proceeds of $11,439,530 from this sale of common stock. These expenses do not include any direct or indirect payments to directors, officers, persons owning 10% or more of any class of equity securities, or affiliates of the Company. Because these securities were sold directly by the Company in an offering that did not involve an underwriter, we did not pay any underwriting discounts or commissions, finder's fees or other expenses to or for underwriters. Through August 31, 2002, approximately $11,288,000 of the proceeds from this sale of common stock have been used as described in the prospectus supplement to fund our planned exploration and development activities, primarily in the San Joaquin Basin of California. As of August 31, 2002, the balance of the net proceeds continue to be held for those purposes. ITEM 6. SELECTED FINANCIAL DATA The following table sets forth certain selected financial data of the Company for each of the last five fiscal years ended August 31:
Fiscal Year Ended August 31, ---------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ---- ---- ---- ---- ---- Operating Revenues ..................... $ 278,214 $ 1,624,096 $ 165,411 $ 116,713 $ 46,145 Net (loss) from operations ............. (13,129,828) (13,142,291) (982,547) (1,140,407) (110,807) Net income (loss( per share) ........... (.55) (.59) (.07) (.11) (.012) Total assets at the end of each period . 13,400,250 22,067,184 19,942,090 10,762,521 2,939,602 Long-term debt at the end of each period 6,000,000 -0- -0- 1,062 2,661
24 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion should be read in conjunction with the Financial Statements 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-K. Overview We are a development stage independent oil and gas exploration company whose strategic focus is the application of advanced seismic imaging and computer aided exploration technologies in the systematic search for commercial hydrocarbon reserves, primarily in the onshore western United States. We attempt to leverage our technical experience and expertise with seismic data to identify exploration and exploitation projects with significant potential economic return. We intend to participate in selected exploration projects as a working interest owner, currently as a non-operator, sharing both risk and rewards with our partners. Our financial results depend on our ability to sell prospect interests to outside industry participants. We will not be able to commence exploratory drilling operations without outside industry participation. We have pursued, and will continue to pursue, exploration opportunities in regions where we believe significant opportunity for discovery 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 discover commercial quantities of hydrocarbons; (2) the market price for oil and gas; (3) our ability to continue to source and screen potential projects; and (4) our ability to fully implement our exploration and development program with respect to these and other matters. There can be no assurance that we will be successful in any of these respects or that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production. Liquidity and Capital Resources At August 31, 2002, we had approximately $6,030,854 in working capital. During the fiscal year ended August 31, 2002, our capitalized costs for undeveloped oil and gas properties decreased by approximately $4,206,000. The decrease is the result of an impairment taken against our oil and gas properties in the amount of $11,723,000 and $250,000 in seismic sales credited to the full cost pool during the fiscal year ended August 31, 2002. The decrease was offset by approximately $7,767,000 of costs incurred for drilling and completion, geological and geophysical costs, delay rentals, and other related direct costs with respect to our exploration and development projects. During the fiscal year ended August 31, 2001, our capitalized costs for undeveloped oil and gas properties decreased by approximately $316,000. The decrease is the result of an impairment taken against our oil and gas properties in the amount of $13,340,000, offset by approximately $13,024,000 of costs incurred for drilling and completion, the cost of acquiring an additional 1.5433% working interest in our East Lost Hills project, transportation pipeline costs, production facilities costs, delay rentals, and other related direct costs with respect to our exploration and development projects. 25 During the fiscal year ended August 31, 2000, our capitalized costs for undeveloped oil and gas properties increased by approximately $6,230,000. This net increase is comprised of total costs of approximately $6,430,000 for drilling costs, costs associated with acquiring and retaining exploration acreage, seismic costs associated with undeveloped oil and gas projects, and reclassification of costs paid during the fiscal year ended August 31, 1999 for claims relating to the 1998 blowout, offset by a property impairment of $200,000 recorded against our Cal Canal project. During the quarter ended November 30, 2000, the holders of our Series A Convertible Preferred Stock converted all of the remaining outstanding shares of Series A Convertible Preferred Stock into shares of common stock at a conversion price of $.60 per share. This resulted in a cashless transaction whereby 14,263 shares of Series A Convertible Preferred Stock were converted into a total of 2,377,234 shares of common stock. At November 30, 2000, there were no remaining shares of Series A Convertible Preferred Stock outstanding. In November 2000, warrants to purchase 100,000 shares of common stock issued in connection with the private placement of the Series A Convertible Preferred Stock were exercised at the exercise price of $0.75 per share. In December 2000, warrants to purchase an additional 16,667 shares of common stock were exercised. We received $87,500 in cash as the result of these exercises. There are no additional outstanding warrants associated with this private placement. During the quarter ended November 30, 2000, warrants issued in conjunction with a private placement that was completed in May 1999 were exercised to purchase a total of 17,125 shares of our common stock at a purchase price of $2.50 per share. Total proceeds received from this warrant exercise were $42,813. Previously during the fiscal year ended August 31, 2000, warrants issued in the May 1999 private placement had been exercised to purchase a total of 164,063 shares of our common stock for total proceeds of $410,157. During December 2000, all the remaining outstanding warrants from the May 1999 private placement were exercised to purchase an aggregate of 256,312 shares of common stock, resulting in aggregate proceeds to us of $640,781. During November 2000 and January 2001, warrants issued in conjunction with the August 2000 private placement were exercised to purchase 144,286 shares of common stock at an exercise price of $4.80 per share. This resulted in proceeds to us of $692,573. During January 2001, the holders of the remaining outstanding warrants issued in connection with a private placement that was completed in May 2000 exercised their warrants to purchase an aggregate of 22,000 shares of common stock for $93,500. On March 12, 2001, we received an aggregate $11,600,000 in gross proceeds through the sale of 1,450,000 shares of our common stock. The common stock was sold pursuant to a shelf registration statement and prospectus supplement. After costs and expenses, we received a net of $11,440,000. Investors consisted of a total of ten separate funds managed by four California based institutions. In May 2002, we received $6,000,000 in gross proceeds from the sale of convertible notes which resulted in long term debt of $6,000,000 at August 31, 2002. We had no outstanding long-term debt at August 31, 2001. We have not entered into any commodity swap arrangements or hedging transactions. Although we have no current plans to do so, we may enter into commodity swap and hedging transactions in the future in conjunction with oil and gas production. 26 It is anticipated that the future development of our business will require additional, and possibly substantial, capital expenditures. Our capital expenditure budget for the fiscal year ending August 31, 2003 will depend on our success in selling additional prospects for cash, the level of industry participation in our exploration projects, the availability of debt or equity financing, and the results of our activities, including continuing results at our East Lost Hills project. We anticipate spending a minimum of approximately $3 million for capital expenditures relating to our existing drilling commitments and related development expenses, and other exploration costs. To limit capital expenditures, we intend to form industry alliances and exchange an appropriate 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 from cash 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. Capital Expenditures During fiscal 2002, we incurred approximately $5,825,000 for costs relating to drilling and completing wells at our East Lost Hills Project. We incurred approximately $1,942,000 for costs related to our other exploration projects including continued acreage lease obligations and associated geological and geophysical costs. Revenues from oil and gas production during 2002 were $132,569. During fiscal 2001, we incurred approximately $10,922,000 for costs relating to drilling and completing wells at our East Lost Hills Project, and for acquiring an additional 1.554% working interest at East Lost Hills. We incurred approximately $2,102,000 for costs related to our other exploration projects including continued leasing and optioning of acreage. We generated $1,201,979 in revenues from oil and gas production during 2001. During fiscal 2000, we incurred approximately $1,319,000 for costs related to continued leasing and optioning of acreage and approximately $4,038,000 for drilling and seismic costs associated with deep exploratory drilling at our East Lost Hills project. We had no revenues from oil and gas production during 2000. We currently anticipate that we will participate in the drilling of up to five exploration wells during our fiscal year ending August 31, 2003, although the number of wells may increase as additional projects are added to our portfolio. However, there can be no assurance that any such wells will be drilled and if drilled that any of these wells will be successful. Our future financial results continue to depend primarily on (1) our ability to discover commercial quantities of hydrocarbons; (2) the market price for oil and gas; (3) our ability to continue to source and screen potential projects; and (4) our ability to fully implement our exploration and development program with respect to these and other matters. There can be no assurance that we will be successful in any of these respects or that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production. Results of Operations The twelve months ended August 31, 2002 ("2002") compared with the twelve months ended August 31, 2001 ("2001") Operations during the fiscal year ended August 31, 2002 resulted in a net loss of $13,129,828 compared with a net loss $13,142,291 for the fiscal year ended August 31, 2001. 27 Oil and Gas Revenues and Expenses. During the year ended August 31, 2002, we recorded $102,637 from the sale of 39,468 mcf of natural gas for an average price of $2.60 per mcf and $29,932 from the sale of 1,600 bbls of hydrocarbon liquids for an average price of $18.71 per barrel. Lease operating expenses during this period were $91,384. During the year ended August 31, 2001, we recorded $1,055,382 from the sale of 99,535 mcf of natural gas for an average price of $10.60 per mcf and $146,597 from the sale of 5,804 bbls of hydrocarbon liquids for an average price of $25.26 per barrel. Lease operating expenses during this period were $102,018. Production commenced at the East Lost Hills ELH #1 well on February 6, 2001. Prior to this date, none of our oil or gas properties was producing. Interest Income. We recorded $145,645 and $422,117 in interest income for the years ended August 31, 2002 and August 31, 2001, respectively. Interest income was higher in the prior fiscal year due to interest earned on cash balances remaining from the common stock offering in March 2001 and the private placement completed in August of 2000. General and Administrative Expense. We incurred $1,496,329 and $1,306,635 in general and administrative expenses during 2002 and 2001, respectively. The increase results primarily from the value of warrants issued in conjunction with a financial advisory agreement. Depreciation, Depletion and Amortization. We recorded no depreciation, depletion and amortization expense from oil and gas properties for the years ended August 31, 2002 or August 31, 2001. Although the ELH #1 began producing during 2001, we recorded an impairment against our entire amortizable full cost pool both at August 31, 2002 and August 31, 2001, and therefore had no costs to amortize. We recorded $14,605 and $17,823 in depreciation expense associated with capitalized office furniture and equipment during the years ended August 31, 2002 and August 31, 2001, respectively. Dry Hole, Impairment and Abandonments. In 2002, we recorded an impairment expense of $11,722,830, primarily for the remaining basis in our East Lost Hills project. Additionally, approximately $54,000 of the current year impairment charge related primarily to a Colorado exploration project where an unsuccessful exploration well was drilled in October 2002. Although properties may be considered as evaluated for purposes of the ceiling test and included in the impairment calculation, until these properties are completely abandoned, we may continue to incur related costs. Until we can establish economic reserves, of which there is no assurance, additional costs associated with these properties are charged directly to impairment expense as incurred. In 2001, we recorded an impairment of $13,339,911 against our oil and gas properties as the result of the capitalized costs of a portion of our oil and gas properties exceeding the present value of estimated future net revenues of proved reserves. The costs from this impairment related primarily to our East Lost Hills project, and included costs for our Southeast Maricopa project and our interests in the Cal Canal and Lucky Dog prospects in the approximate amount of $2,812,000. Interest Expense. We recorded $82,894 in interest expense for the year ended August 31, 2002 and no interest expense for the year ended August 31, 2001. The current year interest expense results from the May 24, 2002 sale of convertible notes, for which we received $6 million in gross proceeds. The notes are due May 24, 2009, and call for semi-annual interest payments at an annual rate of 4.99% and are convertible into common stock at a conversion price of $1.30 per share. The interest can be paid in cash or added to the principal amount at the discretion of the Company. We have reflected the outstanding balance of these notes as Convertible Notes under Long Term Debt on our August 31, 2002 balance sheet. 28 The twelve months ended August 31, 2001 ("2001") compared with the twelve months ended August 31, 2000 ("2000") Operations during the fiscal year ended August 31, 2001 resulted in a net loss of $13,142,291 compared with a net loss $982,547 for the fiscal year ended August 31, 2000. Oil and Gas Revenues and Expenses. Production commenced at the East Lost Hills ELH #1 well on February 6, 2001. We recorded $1,055,382 from the sale of 99,535 mcf of natural gas for an average price of $10.60 per mcf and $146,597 from the sale of 5,804 bbls of hydrocarbon liquids for an average price of $25.26 per barrel during the year ended August 31, 2001. Lease operating expenses during this period were $102,018. We recorded no revenues or expenses from oil and gas operations for the year ended August 31, 2000. None of our oil or gas properties was producing before February 6, 2001. Interest Income. We recorded $422,117 and $165,411 in interest income for the years ended August 31, 2001 and August 31, 2000, respectively. The increase in the year ended August 31, 2001 is attributable to interest earned on cash balances remaining from the common stock offering in March 2001 and the private placement completed in August of 2000. General and Administrative Expense. We incurred $1,306,635 and $929,420 in general and administrative expenses during 2001 and 2000, respectively. The increase is primarily attributable to unrecoverable financing costs and increases in personnel and salaries. Depreciation, Depletion and Amortization. We recorded no depreciation, depletion and amortization expense from oil and gas properties for the years ended August 31, 2001 or August 31, 2000. Although we commenced our first production during 2001, we recorded an impairment against our entire amortizable full cost pool at August 31, 2001, and therefore had no costs to amortize. In the prior year, none of our oil and gas properties were producing, and therefore no DD&A expense was recognized. We recorded $17,823 and $18,327 in depreciation expense associated with capitalized office furniture and equipment during the years ended August 31, 2001 and August 31, 2000, respectively. Dry Hole, Impairment and Abandonments. In 2001, we recorded an impairment of $13,340,000 against our oil and gas properties as the result of the capitalized costs of a portion of our oil and gas properties exceeding the present value of estimated future net revenues of proved reserves. The costs from this impairment relating to our East Lost Hills project include drilling and completion costs associated with our working interests in the ELH #1, ELH #2, ELH #3, Bellevue 1-17 and 1-17R wells and allocated land, geological and geophysical costs. In addition, we have recorded property impairments with respect to our Southeast Maricopa project and our interests in the Cal Canal and Lucky Dog prospects in the approximate amount of $2,812,000. In 2000, we recorded an impairment of $200,000 against our Cal Canal project. Interest Expense. We recorded no interest expense for the year ended August 31, 2001 and nominal interest expense for the year ended August 31, 2000. ITEM 7.A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required under Item 7A is not applicable. 29 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA The Financial Statements and schedules that constitute Item 8 are attached at the end of Annual Report on Form 10-K. An index to these Financial Statements and schedules is also included in Item 14(a) of this Annual Report on Form 10-K. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. Not applicable. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT The directors and executive officers of the Company, their respective positions and ages, and the year in which each director was first elected, are set forth in the following table. Each director has been elected to hold office until the next annual meeting of stockholders and thereafter until his successor is elected and has qualified. Additional information concerning each of these individuals follows the table. Name Age Position with the Company Director Since ---- --- ------------------------- -------------- D. Scott Singdahlsen 44 Chief Executive Officer, 1997 President, and Chairman Of the Board Andrew P. Calerich 38 Chief Financial Officer, Vice --- President and Secretary S. L. Hutchison 70 Director 1999 David Kilpatrick 52 Director 2002 Borden Putnam 49 Director 2002 Bryce W. Rhodes 49 Director 1999 Eric M. Sippel 41 Director 2002 Kenneth R. Berry, Jr. 50 Vice President-Land --- D. Scott Singdahlsen has served as President, Chief Executive Officer, and Chairman of the Board of the Company since August 1997. Mr. Singdahlsen co-founded PYR Energy, LLC in 1996, and served as General Manager and Exploration Coordinator. In 1992, Mr. Singdahlsen co-founded Interactive Earth Sciences Corporation, a 3-D seismic management and interpretation consulting firm in Denver, where he served as vice president and president and lead seismic interpretation specialist from 1992 to 1996. Prior to forming Interactive Earth 30 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 and geostatistical analysis. Mr. Singdahlsen started his career at UNOCAL as an Exploration Geologist in Midland, Texas. Mr. Singdahlsen earned a B.A. in Geology from Hamilton College and a M.S. in Structural Geology from Montana State University. Andrew P. Calerich has served as Chief Financial Officer of the Company since August 1997, as Secretary of the Company since May 1998 and as Vice President since August of 1999. From 1993 to 1997, Mr. Calerich was a business consultant specializing in accounting for public and private oil and gas producers in Denver. From 1990 to 1993, Mr. Calerich was employed as corporate Controller at a public oil and gas company in Denver. Mr. Calerich began his professional career in public accounting at Arthur Andersen & Company. Mr. Calerich is a Certified Public Accountant and earned B.S. degrees in both Accounting and Business Administration at Regis College. David B. Kilpatrick has been a Director of the Company since June 2002. He is currently President of Kilpatrick Energy Group, which provides strategic management consulting services to the California oil and gas industry. Prior to the 1998 merger with Texaco, he was President and Chief Operating Officer of Monterey Resources, Inc., the largest independent oil and gas producer in California. Previously, he served as Western Division Manager of Monterey's corporate predecessor, Santa Fe Energy Resources, from 1990 to 1996. Mr. Kilpatrick has served as President of the California Independent Petroleum Association and is a member of its Board of Directors and also serves as a Director of the Independent Oil Producers Agency. In the past, he has served on the Board of Directors of the Western States Petroleum Association and the Conservation Committee of California Oil and Gas Producers. He earned a Bachelor of Science degree in Petroleum Engineering from the University of Southern California and a Bachelor's Degree in Geology and Physics from Whittier College. Borden Putnam became a Director of the Company in May of 2002. Mr. Putnam has been an analyst with Eastbourne Capital Management, L.L.C. since July 2001. Prior to Eastbourne, Mr. Putnam was a principal and analyst at RS Investment Management from 1996 to 2001. From 1991 to 1996, Mr. Putnam was VP of Geology for an international mining consulting firm and from 1982 to 1991, he was a manager and district manager with Newmont Exploration. Mr. Putnam began his career as a geologist with AMAX Exploration in 1975. He is a Registered Professional Geologist, and holds B.S. and M.S. degrees in Geology and Geochemistry from the New Mexico Institute of Mining and Technology. Mr. Putnam is a member of the Society of Economic Geologists, AAPG, and SME. S. L. Hutchison has been a Director of the Company since April 1999, when he was nominated and elected to the Board in connection with the sale by the Company of convertible promissory notes issued in a private placement transaction in October and November 1998. Since 1979, Mr. Hutchison has served as Vice President and Chief Financial Officer of Victory Oil Company, an oil and gas production company based in California, and other companies in the Victory Group of Companies. Also during that period, Mr. Hutchison has served as Vice-President and Chief Financial Officer and a Director of Crail Capital, a real estate investment company that is owned by Victory Oil Company, and Victex, Inc., a real estate and oil and gas company. Mr. Hutchison also serves as Chief Financial Officer and a director of each of the Crail Johnson Foundation and the Independent Oil Producers Agency, and is the Treasurer and a director of the Los Angeles Maritime Institute. Mr. Hutchison received a Bachelor's degree in accounting from the University of Washington in 1954. 31 Bryce W. Rhodes has been a Director of the Company since April 1999, when he was nominated and elected to the Board in connection with the sale by the Company of convertible promissory notes issued in a private placement transaction in October and November 1998. Since 1996, Mr. Rhodes has served as Vice President of Whittier Energy Company ("WEC"), an oil and gas investment company. Mr. Rhodes served as Investment Manager of WEC from 1990 until 1996. Mr. Rhodes received B.A. degrees in Geology and Biology from the University of California, Santa Cruz, in 1976 and an MBA degree from Stanford University in 1979. Eric M. Sippel became a Director of the Company in May of 2002. Mr. Sippel joined Eastbourne Capital Management, L.L.C. as its Chief Operating Officer and General Counsel in 2000. Prior to that, he was a partner at the law firm of Shartsis, Friese & Ginsburg LLP, in San Francisco, California, where he practiced law from 1990-1999. Mr. Sippel currently serves on the Board of Directors of Blacklight Power, Inc., a private company. He received his B.A. degree with Honors in General Scholarship from Wesleyan University in 1983 and his J.D. degree with Distinction from Stanford Law School in 1986. Kenneth R. Berry, Jr. has served as Vice President of land since August 1999, and as land manager for the Company since October 1997. Mr. Berry is responsible for the management of all land issues including leasing and permitting. Prior to joining the Company, Mr. Berry served as the managing land consultant for Swift Energy Company in the Rocky Mountain region. Mr. Berry began his career in the land department with Tenneco Oil Company after earning a B.A. degree in Petroleum Land Management at the University 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's common stock to file with the Securities and Exchange Commission initial reports of ownership and reports of changes in ownership of common stock and other equity securities of the Company. The Company believes that during the year ended August 31, 2002, its officers, directors and holders of more 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 of the Section 16(a) reports filed for the fiscal year ended August 31, 2002 on behalf of the Company's directors, officers and holders of more than 10% of the Company's common stock. ITEM 11. EXECUTIVE COMPENSATION Summary Compensation Table The following table sets forth in summary form the compensation received during each of the last three completed fiscal years ended August 31, 2002 by D. Scott Singdahlsen, our Chief Executive Officer, President and Chairman Of The Board, and Andrew P. Calerich, our Chief Financial Officer, Vice President and Secretary. Other than Messrs. Singdahlsen and Calerich, none of our executive officers received total salary and bonus exceeding $100,000 during any of the last three fiscal years. 32
Summary Compensation Table -------------------------- Long-Term Compensation ---------------------- Annual Compensation Awards Payouts ----------------------------------------- ------------------------------ Other Restricted LTIP All other Name and Fiscal Salary Bonus Annual Stock Options Payouts compensation Principal Position Year ($)(1) ($)(2) Compensation Awards ($) (#) ($)(4) ($)(5) ($)(3) ----------------------------------------------------------------------------------------------------------------- D. Scott Singdahlsen 2002 $175,000 $-0- -0- -0- -0- -0- -0- Chief Executive Officer, President and Chairman 2001 $128,250 $40,000 -0- -0- -0- -0- -0- Of the Board 2000 $110,000 $-0- -0- -0- -0- -0- -0- Andrew P. Calerich 2002 $95,682 $-0- -0- -0- -0- -0- -0- Chief Financial Officer, Vice President and 2001 $90,666 $10,000 -0- -0- -0- -0- -0- Secretary 2000 $85,000 $-0- -0- -0- -0- -0- -0- ---------------
(1) The dollar value of base salary (cash and non-cash) received during the year indicated. (2) The dollar value of bonus (cash and non-cash) received during the year indicated. (3) During the period covered by the Summary Compensation Table, we did not pay any other annual compensation not properly categorized as salary or bonus, including perquisites and other personal benefits, securities or property. (4) We do not have in effect any plan that is intended to serve as incentive for performance to occur over a period longer than one fiscal year except for our 1997 and 2000 Stock Option Plans. (5) All other compensation received that we could not properly report in any other column of the Summary Compensation Table including annual Company contributions or other allocations to vested and unvested defined contribution plans, and the dollar value of any insurance premiums paid by, or on behalf of, the Company with respect to term life insurance for the benefit of the named executive officer, and, the full dollar value of the remainder of the premiums paid by, or on behalf of, the Company. Option Grants Table The following table provides certain summary information concerning individual grants of stock options made during the fiscal year ended August 31, 2002 to the following named executive officers. 33 Option Grants For Fiscal Year Ended August 31, 2002 --------------------------------------------------- Number of Securities % of Total Underlying Options Granted Exercise Options to Employees in Price Expiration Name Granted (#) Fiscal Year ($/Share) Date ---- ----------- ----------- --------- ---- D. Scott Singdahlsen 15,000 5.8% $1.82 4/11/07 Andrew P. Calerich 45,000 17.6% $1.68 4/11/07 Aggregated Option Exercises And Fiscal Year-End Option Value Table The following table provides certain summary information concerning stock option exercises during the fiscal year ended August 31, 2002 by the named executive officers and the value of unexercised stock options held by the named executive officers as of August 31, 2002.
Aggregated Option Exercises For Fiscal Year Ended August 31, 2002 And Year-End Option Values (1) ------------------------------ Number of Securities Value of Unexercised Underlying Unexercised In-the- Options at Fiscal Year- Money Options at End (#) (4) Fiscal Year-End ($) (5) -------------------------- ------------------------- Shares Acquired on Name Exercise (2) Value Realized ($)(3) Exercisable Unexercisable Exercisable Unexercisable ---- ------------ --------------------- ----------- ------------- ----------- ------------- D. Scott Singdahlsen None $-0- 100,000 115,000 $-0- $-0- Andrew P. Calerich None $-0- 105,000 90,000 18,750 $-0-
(1) No stock appreciation rights are held by any of the named executive officers. (2) The number of shares received upon exercise of options during the year ended August 31, 2002. (3) With respect to options exercised during the year ended August 31, 2002, the dollar value of the difference between the option exercise price and the market value of the option shares purchased on the date of the exercise of the options. (4) The total number of unexercised options held as of August 31, 2002, separated between those options that were exercisable and those options that were not exercisable on that date. (5) For all unexercised options held as of August 31, 2002, the aggregate dollar value of the excess of the market value of the stock underlying those options over the exercise price of those unexercised options. These values are shown separately for those options that were exercisable and those options that were not yet exercisable on August 31, 2002 based on the closing sale price of our common stock on that date, which was $1.00 per share. 34 Employee Retirement Plans, Long-Term Incentive Plans and Pension Plans Excluding the Company's stock option plans, we do not have any long-term incentive plan to serve as incentive for performance to occur over a period longer than one fiscal year. Compensation of Outside Directors On April 12, 2002, the Company granted options to purchase 20,000 shares of common stock to Mr. Hutchison and Mr. Rhodes who, at that time, were the only outside directors of the Company. The exercise price of the options is $1.65 per share, with 5,000 of the options immediately vesting and the remaining 15,000 of the options vesting 2,500 options for each fiscal quarter served as Director beginning June 1, 2002. Effective with Mr. Kilpatrick becoming a non-employee member of the Board of Directors on June 4, 2002, the Company granted him options to purchase 20,000 shares of common stock at an exercise price of $1.72 per share. The options vest 2,500 options for each fiscal quarter served as Director beginning with the Company's fiscal quarter ended August 31, 2002. The Company has not granted options to Mr. Sippel or Mr. Putnam. Should the Company grant options to Mr. Sippel or Mr. Putnam, each has notified the Company that they will assign beneficial ownership of the options to the entities currently holding the Company's Convertible Notes. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Stock Ownership Of Directors And Principal Stockholders As of December 19, 2002, there were 23,701,357 shares of common stock outstanding. The following table sets forth certain information as of that date with respect to the beneficial ownership of common stock by each director and nominee for director, by all executive officers and directors as a group, and by each other person known by us to be the beneficial owner of more than five percent of our common stock:
Name and Address of Number of Shares Percentage of Beneficial Owner Beneficially Owned (1) Shares Outstanding ---------------- ---------------------- ------------------ D. Scott Singdahlsen 2,007,034 (2) 8.4% 1675 Broadway, Suite 2450 Denver, Colorado 80202 S.L. Hutchison 3,305,908 (3) 13.93% c/o Victory Oil Company 222 West Sixth Street, Suite 1010 San Pedro, California 90731 Borden Putnam 8,374,696 (4) 29.45% c/o Eastbourne Capital Management, L.L.C. 1101 Fifth Avenue, Suite 160 San Rafael, CA 94901 35 Name and Address of Number of Shares Percentage of Beneficial Owner Beneficially Owned (1) Shares Outstanding ---------------- ---------------------- ------------------ Bryce W. Rhodes 284,089(5) 1.2% c/o Whittier Energy Company 462 Stevens Avenue, Suite 109 Solana Beach, California 92075 Eric M. Sippel 8,366,116 (6) 29.42% c/o Eastbourne Capital Management, L.L.C. 1101 Fifth Avenue, Suite 160 San Rafael, CA 94901 All Executive Officers and Directors as a 14,494,592 50.08% group (eight persons) (2)(3)(4)(5)(6)(7)(8)(9) Victory Oil Company 3,079,384 (10) 12.99% 222 West Sixth Street, Suite 1010 San Pedro, California 90731 Eastbourne Capital Management, L.L.C. 8,366,116 (11) 29.42% 1101 Fifth Avenue, Suite 160 San Rafael, CA 94901 ----------
(*) Less than one percent. (1) "Beneficial ownership" is defined in the regulations promulgated by the U.S. Securities and Exchange Commission as having or sharing, directly or indirectly (1) voting power, which includes the power to vote or to direct the voting, or (2) investment power, which includes the power to dispose or to direct the disposition of shares of the common stock of an issuer. The definition of beneficial ownership includes shares underlying options or warrants to purchase common stock, or other securities convertible into common stock, that currently are exercisable or convertible or that will become exercisable or convertible within 60 days. Unless otherwise indicated, the beneficial owner has sole voting and investment power. (2) The shares shown for Mr. Singdahlsen include 200,000 shares owned by Mr. Singdahlsen's two minor children. Also includes options to purchase 66,667 shares at $4.40 per share until May 15, 2005 and 66,667 shares at $5.98 per share until November 27, 2005. (3) Includes options to purchase 20,000 shares at $4.125 per share until December 20, 2002 and options to purchase 15,000 shares at $1.65 per share until April 11, 2007 that currently are exercisable or that will become exercisable within the next 60 days. Also includes the shares shown as beneficially owned by Victory Oil Company as described in note (10) below. Mr. Hutchison is the Vice President and Chief Financial Officer of Victory Oil Company. Mr. Hutchison disclaims beneficial ownership of the shares beneficially owned by Victory Oil Company. 36 (4) Includes 7,150 shares and warrants to purchase 1,430 shares at $4.80 per share until July 31, 2003 owned by Mr. Putnam. Also includes the shares shown as beneficially owned by Eastbourne Capital Management, L.L.C. as described in note (11) below. Mr. Putnam is an analyst with Eastbourne and disclaims beneficial ownership of the shares benefically owned by Eastbourne Capital Management, L.L.C. (5) Includes 13,000 shares of common stock owned by Mr. Rhodes and 64,414 shares of common stock owned by Adventure Seekers Travel, Inc. Adventure Seekers is owned by Mr. Rhodes' wife and Mr. Rhodes is the President of Adventure Seekers. Also includes 171,625 shares that are held by Whittier Energy Company. Mr. Rhodes is a Vice President of Whittier Energy Company. Mr. Rhodes disclaims beneficial ownership of the shares beneficially owned by Whittier Energy Company. Also includes options to purchase 20,000 shares at $4.125 per share until December 20, 2002 and options to purchase 15,000 shares at $1.65 per share until April 11, 2007 that currently are exercisable or that will become exercisable within the next 60 days. (6) The shares shown for Mr. Sippel reflect the shares shown as beneficially owned by Eastbourne Capital Management, L.L.C. as described in note (11) below. Mr. Sippel is Chief Operating Officer and General Counsel for Eastbourne and disclaims beneficial ownership of the shares beneficially owned by Eastbourne Capital Management, L.L.C. (7) Includes 100,000 shares of common stock and options to purchase 105,000 shares of common stock at exercise prices ranging from $.69 to $5.44 per share that currently are exercisable or that will become exercisable within the next 60 days that are held by Andrew P. Calerich, Vice-President, Chief Financial Officer and Secretary of the Company, and 32,600 shares held by Mr. Calerich's wife's individual retirement account. (8) Includes the following securities held directly or indirectly by Kenneth R. Berry, Jr., who is Vice President of Land: an aggregate of 70,265 shares owned by various entities, IRAs, and trusts with which Mr. Berry, or his spouse or minor daughter, is associated; and options to purchase 210,000 shares of common stock at exercise prices ranging from $.69 to $5.44 per share that currently are exercisable or that will become exercisable within the next 60 days. (9) Includes options to purchase 5,000 shares at $1.72 per share until June 4, 2007 that currently are exercisable or that will become exercisable within the next 60 days owned by Mr. Kilpatrick. (10) Includes 100,000 shares owned by Crail Fund, a partnership that is owned by the shareholders of Victory Oil Company. See "Certain Transactions With Management And Principal Stockholders". (11) The shares reflected include the shares beneficially owned by Eastbourne Capital Management, L.L.C., a registered investment adviser, Richard Jon Barry, Manager of Eastbourne and the following companies to which Eastbourne is investment adviser: Black Bear Offshore Master Fund Limited, a Cayman Island exempted company, Black Bear Fund I, L.P. and Black Bear Fund II, LLC. These shares include the equivalent shares of common stock underlying $6,151,751 of convertible notes held by Black Bear Offshore Master Fund Limited, Black Bear Fund I, L.P. and Black Bear Fund II, LLC in the aggregate amount of 4,732,116 shares. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS On May 24, 2002, certain investment entities managed by Eastbourne Capital Management, LLC purchased $6 million of convertible notes from the Company. The notes provide for semi-annual interest payments at an annual rate of 4.99% and are convertible into common stock at the rate of $1.30 per share. At the time of the transaction, these entities had aggregate ownership in PYR Energy Corporation of approximately 15%. Concurrent with the sale, we agreed to add Messrs. Eric Sippel and Borden Putnam, of Eastbourne, to our Board of Directors. 37 During the fiscal year ended August 31, 2002, there were no other transactions between the Company and its directors, executive officers or known holders of greater than five percent of the Company's common stock in which the amount involved exceeded $60,000 and in which any of the foregoing persons had or will have a material interest. ITEM 14. CONTROLS AND PROCEDURES (a) Evaluation of disclosure controls and procedures Based on an evaluation carried out under the supervision, and with the participation of the management of the Company, including the Chief Executive Officer and the Chief Financial Officer, during the 90 day period prior to the filing of this report, the Company's Chief Executive Officer and Chief Financial Officer believe the Company's disclosure controls and procedures, as defined in Securities Exchange Act Rules 13a-14 and 15d-14, are, to the best of their respective knowledge, effective. (b) Changes in internal controls Subsequent to the date of this evaluation, the Chief Executive Officer and Chief Financial Officer are not aware of any significant changes in the Company's internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses, or in other factors that could significantly affect these controls to ensure that information required to be disclosed by the Company, in reports that it files or submits under the Securities Act of 1934, is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and regulations. PART IV ITEM 15. EXHIBITS, FINANCIAL SCHEDULES AND REPORTS ON FORM 8-K (a)(1) and (a)(2) Financial Statements And Financial Statement Schedules INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES INDEX Independent Auditor's Report F-2 Balance Sheets August 31, 2002 and 2001 F-3 Statements of Operations Years Ended August 31, 2002, 2001, and 2000 and Cumulative Amounts from Inception to August 31, 2002 F-4 Statements of Members'/ Stockholders' Equity Period from Inception (May 31, 1996) to December 31, 1996, Eight Months Ended August 31, 1997 and Years Ended August 31, 1999, 2000, 2001 and 2002 F-5 - F-8 Statements of Cash Flows Years Ended August 31, 2002, 2001, and 2000 and F-9 - F-10 Cumulative Amounts from Inception to August 31, 2002 Notes to Financial Statements F-11 - F-23 38 All other schedules are omitted because the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Financial Statements and Notes thereto. (a)(3) Exhibits. --------- Exhibit Index Number Description ------ ----------- 3.1 Articles Of Incorporation filed with the Maryland Secretary Of State on June 18, 2001. (1) 3.2 Articles of Merger filed with the Maryland Secretary Of State on July 3, 2001 in connection with Maryland reincorporation. (1) 3.3 Bylaws (1) 99.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (1) Incorporated by reference from the Registrant's Form 10-K for the year ended August 31, 2001. (b) Reports On Form 8-K. -------------------- During the fourth quarter of the fiscal year ended August 31, 2002, the Company filed one Current Report on Form 8-K dated July 16, 2002. This event consisted of the dissemination of a press release by the Company and was reported under "ITEM 5. OTHER EVENTS". 39 SIGNATURES ---------- In accordance with Section 13 or 15(d) of the Exchange Act, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. PYR ENERGY CORPORATION Date: December 30, 2002 By: /s/ D. Scott Singdahlsen ---------------------------------- D. Scott Singdahlsen Chief Executive Officer In accordance with the requirements of the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signatures Title Date ---------- ----- ---- /s/ D. Scott Singdahlsen Chief Executive Officer, December 30, 2002 ------------------------ President and Chairman D. Scott Singdahlsen Of The Board /s/ S. L. Hutchison Director December 30, 2002 ------------------------ S. L. Hutchison /s/ David Kilpatrick Director December 30, 2002 ------------------------ David Kilpatrick /s/ Borden Putnam Director December 30, 2002 ------------------------ Borden Putnam /s/ Bryce W. Rhodes Director December 30, 2002 ------------------------ Bryce W. Rhodes /s/ Eric M. Sippel Director December 30, 2002 ------------------------ Eric M. Sippel /s/ Andrew P. Calerich Vice-President, Chief December 30, 2002 ------------------------ Financial Officer Andrew P. Calerich and Secretary 40 CERTIFICATIONS I, D. Scott Singdahlsen, certify that: 1. I have reviewed this annual report on Form 10-K/A1 of PYR Energy Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: December 30, 2002 /s/ D. Scott Singdahlsen ---------------------------------- D. Scott Singdahlsen Chief Executive Officer 41 I, Andrew P. Calerich, certify that: 1. I have reviewed this annual report on Form 10-K/A1 of PYR Energy Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: December 30, 2002 /s/ Andrew P. Calerich ---------------------------------- Andrew P. Calerich Chief Financial Officer 42 PYR ENERGY CORPORATION (A Development Stage Company) INDEX Independent Auditor's Report F-2 Balance Sheets August 31, 2002 and 2001 F-3 Statements of Operations Years Ended August 31, 2002, 2001 and 2000 and Cumulative Amounts from Inception to August 31, 2002 F-4 Statements of Members'/ Stockholders' Equity Period from Inception (May 31, 1996) to December 31, 1996, Eight Months Ended August 31, 1997 and Five Years Ended August 31, 2002 F-5 - F-8 Statements of Cash Flows Years Ended August 31, 2002, 2001 and 2000 and F-9 - F-10 Cumulative Amounts from Inception to August 31, 2002 Notes to Financial Statements F-11 - F-23 F - 1 INDEPENDENT AUDITOR'S REPORT To The Board of Directors and Stockholders PYR ENERGY CORPORATION We have audited the accompanying balance sheets of PYR Energy Corporation (a development stage company) as of August 31, 2002 and 2001, and the related statements of operations, stockholders' equity and cash flows for each of the three years in the period ended August 31, 2002 and cumulative amounts from inception to August 31, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of PYR Energy Corporation as of August 31, 2002 and 2001, and the results of its operations and its cash flows for each of the three years in the period ended August 31, 2002 and cumulative amounts from inception to August 31, 2002 in conformity with accounting principles generally accepted in the United States of America. /s/ Wheeler Wasoff, P.C. ------------------------ Wheeler Wasoff, P.C. Denver, Colorado October 28, 2002 F - 2
PYR ENERGY CORPORATION (A Development Stage Company) BALANCE SHEETS AUGUST 31, 2002 and 2001 ASSETS 2002 2001 ------------ ------------ CURRENT ASSETS Cash $ 6,516,086 $ 9,800,842 Accounts receivable -- 1,173,751 Prepaid expenses 47,365 74,636 ------------ ------------ Total Current Assets 6,563,451 11,049,229 PROPERTY AND EQUIPMENT 6,805,355 11,017,955 OTHER 31,444 -- ------------ ------------ $ 13,400,250 $ 22,067,184 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities $ 532,597 $ 2,263,368 ------------ ------------ Total Current Liabilities 532,597 2,263,368 ------------ ------------ CONVERTIBLE NOTES PAYABLE 6,000,000 -- ------------ ------------ COMMITMENTS AND CONTINGENCIES (Note 7) STOCKHOLDERS' EQUITY Preferred stock, $.001 par value; authorized 1,000,000 shares Series A authorized 25,000 shares; issued and outstanding none -- -- Common stock, $.001 par value; authorized 75,000,000 shares Issued and outstanding 23,701,357 shares (2002) and 23,691,357 shares (2001) 23,701 23,691 Capital in excess of par value 35,407,657 35,214,002 Deficit accumulated during the development stage (28,563,705) (15,433,877) ------------ ------------ 6,867,653 19,803,816 ------------ ------------ $ 13,400,250 $ 22,067,184 ============ ============ The accompanying notes are an integral part of the financial statements. F - 3 PYR ENERGY CORPORATION (A Development Stage Company) STATEMENTS OF OPERATIONS Cumulative from Inception to Years ended August 31, August 31, 2002 2001 2000 2002 ------------ ------------ ------------ ------------ REVENUES Oil and gas production $ 132,569 $ 1,201,979 $ -- $ 1,334,548 Interest income 145,645 422,117 165,411 891,627 Other -- -- -- 127,528 ------------ ------------ ------------ ------------ 278,214 1,624,096 165,411 2,353,703 ------------ ------------ ------------ ------------ OPERATING EXPENSES Lease operating expenses 91,384 102,018 -- 193,402 Impairment, dry hole, and abandonments 11,722,830 13,339,911 200,000 25,584,110 Depreciation and amortization 14,605 17,823 18,327 98,601 General and administrative 1,496,329 1,306,635 929,420 5,294,424 Interest 82,894 -- 211 267,200 ------------ ------------ ------------ ------------ 13,408,042 14,766,387 1,147,958 31,437,737 ------------ ------------ ------------ ------------ OTHER INCOME Gain on sale of oil and gas prospects -- -- -- 556,197 ------------ ------------ ------------ ------------ (13,129,828) (13,142,291) (982,547) (28,527,837) INCOME APPLICABLE TO PREDECESSOR LLC (Note 1) -- -- -- (35,868) ------------ ------------ ------------ ------------ NET (LOSS) (13,129,828) (13,142,291) (982,547) (28,563,705) Less dividends on preferred stock -- (62,880) (178,621) (292,411) ------------ ------------ ------------ ------------ NET (LOSS) TO COMMON STOCKHOLDERS $(13,129,828) $(13,205,171) $ (1,161,168) $(28,856,116) ============ ============ ============ ============ NET (LOSS) PER COMMON SHARE BASIC AND DILUTED (Note 1) $ (.55) $ (.59) $ (.07) $ (2.07) ============ ============ ============ ============ WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING BASIC AND DILUTED (Note 1) 23,693,521 22,226,906 16,069,869 13,935,299 ============ ============ ============ ============ The accompanying notes are an integral part of the financial statements. F - 4 PYR ENERGY CORPORATION (A Development Stage Company) STATEMENTS OF MEMBERS'/STOCKHOLDERS' EQUITY PERIOD FROM INCEPTION (MAY 31, 1996) TO DECEMBER 31, 1996, EIGHT MONTHS ENDED AUGUST 31, 1997 AND FIVE YEARS ENDED AUGUST 31, 2002 Deficit Accumulated Preferred Stock Common Stock Capital in During the Members' ------------------- ------------------------- Excess of Development Equity Shares Amount Shares Amount Par Value Stage ----------- -------- -------- ----------- ----------- ----------- ----------- Inception, May 31, 1996 $ -- -- $ -- -- $ -- $ -- $ -- Initial member contributions - cash 5,000 -- -- -- -- -- -- Member contribution- services 12,000 -- -- -- -- -- -- Distributions to members (24,000) -- -- -- -- -- -- Net income 18,963 -- -- -- -- -- -- ----------- -------- -------- ----------- ----------- ----------- ----------- Balance, December 31, 1996 11,963 -- -- -- -- -- -- Member contributions - cash 23,000 -- -- -- -- -- -- Member contribution - services 24,000 -- -- -- -- -- -- Distributions to members (42,000) -- -- -- -- -- -- Net income - January 1, 1997 to August 5, 1997 16,905 -- -- -- -- -- -- Issuance of common stock to members of PYR Energy, LLC upon merger ($.008 per share) (33,868) -- -- 4,000,000 4,000 29,868 -- Recapitalization of shares issued by Mar prior to merger -- -- -- 1,059,804 1,060 (724) -- Sales of common stock pursuant to private placement at $.25 per share -- -- -- 2,095,000 2,095 521,655 -- Sale of common stock pursuant to private placement at $.75 per share -- -- -- 2,000,000 2,000 1,498,000 -- Costs of private placements offerings -- -- -- -- -- (280,711) -- Net (loss) August 6, 1997 to August 31, 1997 -- -- -- -- -- -- (57,825) ----------- -------- -------- ----------- ----------- ----------- ----------- Balance, August 31, 1997 -- -- -- 9,154,804 9,155 1,768,088 (57,825) Net (loss) -- -- -- -- -- -- (110,807) Balance, August 31, 1998 $ -- -- $ -- 9,154,804 $ 9,155 $ 1,768,088 $ (168,632) ----------- -------- -------- ----------- ----------- ----------- ----------- The accompanying notes are an integral part of the financial statements. F - 5 PYR ENERGY CORPORATION (A Development Stage Company) STATEMENTS OF MEMBERS'/STOCKHOLDERS' EQUITY (continued) PERIOD FROM INCEPTION (MAY 31, 1996) TO DECEMBER 31, 1996, EIGHT MONTHS ENDED AUGUST 31, 1997 AND FIVE YEARS ENDED AUGUST 31, 2002 Deficit Accumulated Preferred Stock Common Stock Capital in During the ----------------------- ------------------------- Excess of Development Shares Amount Shares Amount Par Value Stage ----------- -------- ------------ --------- ------------ ------------ Balance Forward -- $ -- 9,154,804 $ 9,155 $ 1,768,088 $ (168,632) Issuance of preferred stock for convertible notes 25,000 25 -- -- 2,499,976 -- Unamortized convertible note financing costs -- -- -- -- (73,319) -- Issuance of common stock for interest on convertible debt, at $2.19 per share -- -- 53,326 53 116,769 -- Issuance of common stock warrants for financing costs -- -- -- -- 56,833 -- Conversion of preferred stock to common stock at $.60 per share (2,021) (2) 336,833 337 (335) -- Sale of common stock pursuant to private placement for cash of $1.60 per share -- -- 4,375,000 4,375 6,995,625 -- Costs of private placement -- -- -- -- (83,155) -- Exercise of private placement warrants for cash of $2.50 per share -- -- 3,125 3 7,809 -- Issuance of common stock for property, valued at $.75 per share -- -- 266,666 267 199,733 -- Issuance of common stock for property, valued at $2.00 per share -- -- 218,866 219 437,513 -- Preferred dividends paid -- -- -- -- (50,910) -- Net (loss) -- -- -- -- -- (1,140,407) ----------- -------- ------------ --------- ------------ ------------ Balance August 31, 1999 22,979 $ 23 14,408,620 $ 14,409 $ 11,874,627 $ (1,309,039) ----------- -------- ------------ --------- ------------ ------------ The accompanying notes are an integral part of the financial statements. F - 6 PYR ENERGY CORPORATION (A Development Stage Company) STATEMENTS OF MEMBERS'/STOCKHOLDERS' EQUITY (continued) PERIOD FROM INCEPTION (MAY 31, 1996) TO DECEMBER 31, 1996, EIGHT MONTHS ENDED AUGUST 31, 1997 AND FIVE YEARS ENDED AUGUST 31, 2002 Deficit Accumulated Preferred Stock Common Stock Capital in During the ------------------------ ---------------------------- Excess of Development Shares Amount Shares Amounts Par Value Stage ------------ -------- ------------ ------------ ------------ ------------ Balance Forward 22,979 $ 23 14,408,620 $ 14,409 $ 11,874,627 $ (1,309,039) Issuance of common stock for services (valued at $4.00 per share) -- -- 5,000 5 19,995 -- Conversion of preferred stock to common stock at $.60 per share (8,716) (9) 1,452,597 1,452 (1,443) -- Exercise of warrants for cash of $.75 per share -- -- 58,333 58 43,692 -- Exercise of private placement warrants for cash of $2.50 per share -- -- 160,938 161 402,184 -- Issuance of common stock for payment of preferred dividends (valued at $4.30 per share) -- -- 24,914 25 (25) -- Issuance of common stock for payment of preferred dividends (valued at $5.24 per share) -- -- 13,617 14 (14) -- Sale of common stock pursuant to private placement for cash of $3.25 per share -- -- 220,000 220 714,780 -- Cost of private placement -- -- -- -- (11,857) -- Exercise of common stock options -- -- 27,500 28 26,285 Retirement of common stock received for option exercise -- -- (2,500) (3) (10,310) Sale of common stock pursuant to private placement for cash of $3.50 per share -- -- 2,700,000 2,700 9,447,300 -- Issuance of common stock warrants for offering costs -- -- -- -- 110,606 -- Costs of private placement -- -- -- -- (567,436) -- Net (loss) -- -- -- -- -- (982,547) ------------ -------- ------------ ------------ ------------ ------------ Balance August 31, 2000 14,263 $ 14 19,069,019 $ 19,069 $ 22,048,384 $ (2,291,586) ------------ -------- ------------ ------------ ------------ ------------ The accompanying notes are an integral part of the financial statements. F - 7 PYR ENERGY CORPORATION (A Development Stage Company) STATEMENTS OF MEMBERS'/STOCKHOLDERS' EQUITY (continued) PERIOD FROM INCEPTION (MAY 31, 1996) TO DECEMBER 31, 1996, EIGHT MONTHS ENDED AUGUST 31, 1997 AND FIVE YEARS ENDED AUGUST 31, 2002 Deficit Accumulated Preferred Stock Common Stock Capital in During the ---------------------- ---------------------------- Excess of Development Shares Amounts Shares Amounts Par Value Stage --------- --------- ------------ ------------ ------------ ------------ Balance Forward 14,263 $ 14 19,069,019 $ 19,069 $ 22,048,384 $ (2,291,586) Conversion of preferred stock to common stock (14,263) (14) 2,377,234 2,377 (2,363) -- Exercise of warrants for cash of $.75 per share -- -- 116,667 117 87,384 -- Exercise of private placement warrants for cash of $2.50 to $4.80 per share -- -- 439,723 439 1,469,226 -- Issuance of common stock for payment of preferred dividends (valued at $6.40 per share) -- -- 9,825 10 (10) -- Exercise of common stock options for cash at $.69 to $3.66 per share -- -- 246,000 246 288,272 Retirement of common stock received for option exercise -- -- (17,111) (17) (114,971) Sale of common stock for cash of $8.00 per share -- -- 1,450,000 1,450 11,598,550 -- Costs of common stock sale -- -- -- -- (160,470) -- Net (loss) -- -- -- -- -- (13,142,291) --------- --------- ------------ ------------ ------------ ------------ Balance August 31, 2001 -- -- 23,691,357 23,691 35,214,002 (15,433,877) Exercise of common stock options for cash at $1.50 per share -- -- 10,000 10 14,990 -- Issuance of common stock warrants for services -- -- -- -- 178,665 -- Net (loss) -- -- -- -- -- (13,129,828) --------- --------- ------------ ------------ ------------ ------------ Balance August 31, 2002 -- $ -- 23,701,357 $ 23,701 $ 35,407,657 $(28,563,705) ========= ========= ============ ============ ============ ============ The accompanying notes are an integral part of the financial statements. F - 8 PYR ENERGY CORPORATION (A Development Stage Company) STATEMENTS OF CASH FLOWS Cumulative Years Ended August 31, Amounts from 2002 2001 2000 Inception ------------ ------------ ------------ ------------ CASH FLOWS FROM OPERATING ACTIVITIES Net (loss) $(13,129,828) $(13,142,291) $ (982,547) $(28,527,837) Adjustments to reconcile net (loss) to net cash (used) by operating activities Depreciation and amortization 14,605 17,823 18,327 98,602 Contributed services -- -- -- 36,000 Gain on sale of oil and gas prospects -- -- -- (556,197) Impairment, dry hole and abandonments 11,722,830 13,339,911 200,000 25,584,110 Common stock issued for interest and services -- -- 20,000 136,822 Warrants issued for services 178,665 -- -- 178,665 Amortization of financing costs 867 -- -- 27,806 Amortization of marketable securities -- -- -- (20,263) Changes in assets and liabilities Decrease (increase) in accounts receivable 1,173,751 (1,173,751) 2,516 (566) Decrease (increase) in prepaids 27,270 (53,801) (6,644) (51,917) (Decrease) increase in accounts payable (1,172,192) 22,303 (105,802) (1,090,286) Other (6,916) 1,946 -- 1,279 ------------ ------------ ------------ ------------ Net cash (used) by operating activities (1,190,948) (987,860) (854,150) (4,183,782) ------------ ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES Cash paid for furniture and equipment (11,293) (30,757) (4,200) (132,205) Cash paid for oil and gas properties (8,325,204) (11,329,468) (5,929,267) (30,811,699) Proceeds from sale of oil and gas properties 250,000 -- -- 1,300,078 Cash paid for marketable securities -- -- -- (5,090,799) Proceeds from sale of marketable securities -- -- 5,111,062 5,111,062 Cash received (paid) for reimbursable property costs -- 381,605 -- (28,395) ------------ ------------ ------------ ------------ Net cash (used) in investing activities (8,086,497) (10,978,620) (822,405) (29,651,958) ------------ ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES Members capital contributions -- -- -- 28,000 Distributions to members -- -- -- (66,000) Cash from short-term borrowings -- -- -- 285,000 Repayment of short-term borrowings -- -- -- (285,000) Cash received upon recapitalization and merger -- -- -- 336 Proceeds from sale of common stock -- 11,600,000 10,165,000 30,788,750 Proceeds from sale of convertible debt 6,000,000 -- -- 8,500,001 Proceeds from exercise of warrants -- 1,557,166 446,095 2,011,073 Proceeds from exercise of options 15,000 173,530 16,000 204,530 Cash paid for offering and financing costs (22,311) (160,470) (468,687) (1,058,759) Payments on capital lease -- (920) (1,742) (5,195) Preferred dividends paid -- -- -- (50,910) ------------ ------------ ------------ ------------ Net cash provided by financing activities 5,992,689 13,169,306 10,156,666 40,351,826 ------------ ------------ ------------ ------------ NET (DECREASE) INCREASE IN CASH (3,284,756) 1,202,826 8,480,111 6,516,086 CASH, BEGINNING OF PERIODS 9,800,842 8,598,016 117,905 -- ------------ ------------ ------------ ------------ CASH, END OF PERIODS $ 6,516,086 $ 9,800,842 $ 8,598,016 $ 6,516,086 ============ ============ ============ ============ The accompanying notes are an integral part of the financial statements. F - 9
PYR ENERGY CORPORATION (A Development Stage Company) STATEMENTS OF CASH FLOWS (continued) YEARS ENDED AUGUST 31, 2002, 2001 and 2000 and PERIOD FROM INCEPTION TO AUGUST 31, 2002 SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION During the years ended August 31, 2002, 2001 and 2000, the Company paid cash for interest of $0, $0, and $211 respectively, on a capital lease. SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES During the year ended August 31, 2002, the Company issued warrants, valued at $178,665, in conjunction with a financial advisory services agreement. During the year ended August 31, 2001, the Company issued 9,825 shares of common stock as payment of dividends on preferred stock. During the year ended August 31, 2000, the Company issued common stock, valued at $20,000, for services; issued warrants, valued at $110,606, as partial consideration for a finders fee in connection with a private placement sale of common stock; and issued 38,531 shares of common stock as payment of dividends on preferred stock. During the year ended August 31, 1999, the Company issued common stock, valued at $637,732, as partial consideration for oil and gas properties; issued common stock, valued at $116,822 for interest on convertible debt; and issued warrants, valued at $56,833, as partial consideration for a finders fee in connection with the sale of convertible debt. During the year ended August 31, 1998, the Company entered into a capital lease obligation of $5,195 for office equipment. During 1996 and 1997 the President of the Company performed services for PYR LLC valued at $12,000 and $24,000, respectively. The value of these services was charged to members' equity as a non-cash capital contribution. In August 1997, 4,000,000 shares of common stock were issued to the members of PYR Energy, LLC ("PYR LLC") in exchange for 100 percent of the ownership interests in PYR LLC, for which the net members' equity in PYR LLC was $33,868. These shares were issued pursuant to a plan of reorganization and merger effective August 6, 1997 (Note 1). The accompanying notes are an integral part of the financial statements. F - 10 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES ORGANIZATION AND BUSINESS PYR Energy Corporation (the "Company") is an independent oil and gas company primarily engaged in the exploration for, acquisition, development and production of, crude oil and natural gas. The Company's current activities are principally conducted in the State of California and the Rocky Mountain region of the United States. As of August 31, 2002, the Company is considered a development stage company as defined by Statement of Financial Accounting Standards No. 7 (SFAS 7). The Company's predecessor, Mar Ventures Inc. ("Mar"), was incorporated under the laws of the State of Delaware on March 27, 1996 for the purpose of producing and marketing traditional television programming and marketing its film library. Mar was a public company which had no significant operations as of July 31, 1997. On August 6, 1997 Mar acquired all the interests in PYR Energy LLC ("PYR LLC") (a Colorado limited liability company organized on May 31, 1996), a development stage company as defined by SFAS No. 7. PYR LLC, an independent exploration company, was engaged in the acquisition of oil and gas properties for exploration and exploitation in the Rocky Mountain region and California. Effective August 6, 1997, Mar transferred to its former president substantially all its assets and liabilities that were related to its film library operations. Upon completion of the acquisition of PYR LLC by Mar, PYR LLC ceased to exist as a separate entity. Mar remained as the legal surviving entity and, effective November 12, 1997, Mar changed its name to PYR Energy Corporation. For financial reporting purposes, the business combination was accounted for as an additional capitalization of Mar (a reverse acquisition with PYR LLC as the acquirer). The operations of PYR LLC are the only continuing operations of the Company. Effective July 02, 2001, the Company was reincorporated in Maryland through the merger of the Company into a wholly owned subsidiary, PYR Energy Corporation, a Maryland corporation The Company is an exploration stage oil and gas company. The Company's efforts, since August 1997, have consisted of financing activities and the acquisition of unproven properties and related seismic data. The Company has entered into participation and farm-in agreements with industry partners on certain of its properties pursuant to which these partners have acquired, for cash, interests in the Company's properties. During the year ended August 31, 1998, drilling of two test wells was commenced, with one well being plugged and abandoned and the other suffering a blowout. During the years ended August 31, 1999 and 2000, the Company continued its acquisition of unproven properties and related seismic data with industry partners, and participated in exploration of the properties, including the drilling of exploratory wells. During the year ended August 31, 2001, initial production of oil and gas commenced from the Company's East Lost Hills prospect. Although initial production resulted in test revenue from oil and gas sales of $1,201,979 being earned through August 31, 2001, a reserve report prepared as of August 31, 2001 by an independent petroleum engineering firm concluded that reserves from the Company's producing properties were not economic to produce. (See Notes 2 and 3). Accordingly, based on the ceiling test limitation required for oil and gas companies utilizing the full cost method of accounting, the Company recognized an impairment of $13,339,911 on its oil and gas properties at August 31, 2001. F - 11 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) During the year ended August 31, 2002, the Company participated in ongoing drilling operations at East Lost Hills and continued to refine seismic data and obtain the rights for additional exploration acreage in its other California and Rocky Mountain projects. Due to the uncertainty of whether or not additional activity will occur at its East Lost Hills project, and because of the uncertainty as to whether or not the Company will participate should additional activity occur, at August 31, 2002 the Company recognized an impairment expense of $11,722,830, primarily for the remaining basis in its East Lost Hills project. PROPERTY AND EQUIPMENT Furniture and equipment is recorded at cost. Depreciation and amortization of assets under capital lease is provided by use of the straight-line method over the estimated useful lives of the related assets of three to five years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Long-lived assets, other than oil and gas properties, are evaluated for impairment to determine if current circumstances and market conditions indicate the carrying amount may not be recoverable. The Company has not recognized any impairment losses on non oil and gas long-lived assets. OIL AND GAS PROPERTIES The Company utilizes the full cost method of accounting for oil and gas activities. Under this method, subject to a limitation based on estimated value, all costs associated with property acquisition, exploration and development, including costs of unsuccessful exploration, are capitalized within a cost center. The Company's oil and gas properties are located within the United States, which constitutes one cost center. No gain or loss is recognized upon the sale or abandonment of undeveloped or producing oil and gas properties unless the sale represents a significant portion of oil and gas properties and the gain significantly alters the relationship between capitalized costs and proved oil and gas reserves of the cost center. Depreciation, depletion and amortization of oil and gas properties is computed on the units of production method based on proved reserves. Amortizable costs include estimates of future development costs of proved undeveloped reserves. A reserve report prepared as of August 31, 2001 by an independent petroleum engineering firm concluded that reserves from the Company's producing properties are not currently economic to produce and, therefore, at August 31, 2001, the Company had no proved reserves. The Company had not established additional production as of August 31, 2002 and, accordingly, did not prepare a reserve report. Capitalized costs of oil and gas properties may not exceed an amount equal to the present value, discounted at 10%, of the estimated future net cash flows from proved oil and gas reserves plus the cost, or estimated fair market value, if lower, of unproved properties. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net cash flows is computed by applying year end prices of oil and natural gas to estimated future production of proved oil and gas reserves as of year end, less estimated future expenditures to be incurred in developing and producing the proved reserves and assuming continuation of existing economic conditions. The Company has not accrued costs for future site restoration, dismantlement and abandonment costs related to oil and gas properties because the Company estimates that such costs will be offset by the salvage value of the equipment sold upon abandonment of such properties. F - 12 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) Due to the uncertainty of whether or not additional activity will occur at its East Lost Hills project, and because of the uncertainty as to whether or not the Company will participate should additional activity occur, at August 31, 2002 the Company recognized an impairment expense of $11,722,830, primarily for the remaining basis in its East Lost Hills project. At August 31, 2001, the ceiling test limitation resulted in the Company's recognizing an impairment expense of $13,339,911 on its oil and gas properties. At August 31, 2000 and 1999, the Company had determined that an impairment loss of $200,000 and $285,229, respectively, on evaluated oil and gas properties be recognized. The Company leases non-producing acreage for its exploration and development activities. The cost of these leases is included in unevaluated oil and gas property costs recorded at the lower of cost or fair market value. REVENUE RECOGNITION The Company recognizes oil and gas revenues from its interests in producing wells as oil and gas is produced and sold from these wells. The Company has no gas balancing arrangements in place. Oil and gas sold is not significantly different from the Company's product entitlement. INCOME TAXES The Company has adopted the provisions of SFAS 109, "Accounting for Income Taxes". SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. At August 31, 2002, the Company had a net operating loss carryforward of approximately $22,530,000 that may be offset against future taxable income through 2022. These carryforwards are subject to review by the Internal Revenue Service. The Company has fully reserved the $4,900,000 tax benefit of operating loss carryforwards, by a valuation allowance of the same amount, because the likelihood of realization of the tax benefit cannot be determined. Of the total tax benefit, $1,800,000 is attributable to 2002. Temporary differences between the time of reporting certain items for financial and tax reporting purposes consist primarily of exploration and development costs on oil and gas properties, and impairment pursuant to the ceiling test limitation. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. F - 13 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 1 -ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) The oil and gas industry is subject, by its nature, to environmental hazards and clean-up costs. At this time, management knows of no substantial costs from environmental accidents or events for which it may be currently liable. In addition, the Company's oil and gas business makes it vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on current oil and gas prices and estimated reserves. Price declines reduce the estimated quantity of proved reserves and increase annual amortization expense (which is based on proved reserves). (LOSS) PER SHARE (Loss) per common share is computed based on the weighted average number of common shares outstanding during each period. Common shares issued to the members of PYR LLC upon completion of the merger are considered outstanding for all periods presented. Convertible equity instruments, such as convertible notes payable, stock options and warrants, are not considered in the calculation of net loss per share as their inclusion would be antidilutive. SHARE BASED COMPENSATION In October 1995, SFAS 123, "Accounting for Stock-Based Compensation", was issued. This standard defines a fair value based method of accounting for an employee stock option or similar equity instrument. This statement gives entities a choice of recognizing related compensation expense by adopting the new fair value method or to continue to measure compensation using the intrinsic value approach under Accounting Principles Board (APB) Opinion No. 25. The Company has elected to utilize APB 25 for measurement; and will, pursuant to SFAS 123, disclose supplementally the pro forma effects on net income and earnings per share of using the new measurement criteria. CASH EQUIVALENTS For purposes of reporting cash flows, the Company considers as cash equivalents all highly liquid investments with a maturity of three months or less at the time of purchase. On occasion, the Company has cash in banks in excess of federally insured amounts. See below, "Concentration of Credit Risks". RECENT ACCOUNTING PRONOUNCEMENTS In June 2001, the Financial Accounting Standards Board ("FASB"), issued SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS 143 generally requires obligations associated with asset retirements to be recognized earlier and displayed as liabilities rather than as contra-assets. The pronouncement is effective for financial statements issued for fiscal years beginning after June 15, 2002. Management does not believe that the adoption of SFAS 143 will have any impact on its financial position or results of operations. In August 2001, FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS 144 establishes a single accounting model for long-lived assets to be disposed of by sale. The pronouncement is effective for financial statements issued for fiscal years beginning after December 15, 2001. Management does not believe that the adoption of SFAS 144 will have any impact on its financial position or results of operations. F - 14 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 1 -ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (continued) In June 2002, FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity." SFAS 146 generally requires a liability for a cost associated with an exit or disposal activity to be recognized and measured initially at its fair value in the period in which the liability is incurred. The pronouncement is effective for exit or disposal activities initiated after December 31, 2002. Management does not believe that the adoption of SFAS 146 will have any impact on its financial position or results of operations. FAIR VALUE The carrying amount reported in the balance sheet for cash, prepaid expenses, accounts payable and accrued liabilities approximates fair value because of the immediate or short-term maturity of these financial instruments. CONCENTRATION OF CREDIT RISK Financial instruments which potentially subject the Company to concentrations of credit risk consist of cash and receivables. The Company maintains cash accounts at one financial institution. The Company periodically evaluates the credit worthiness of financial institutions, and maintains cash accounts only in large high quality financial institutions, thereby minimizing exposure for deposits in excess of federally insured amounts. The Company believes that credit risk associated cash is remote. RECLASSIFICATION Certain reclassifications have been made to 2001 and 2000 amounts to conform to the 2002 presentation. NOTE 2 - ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE Accounts receivable at August 31, 2001 included $1,173,155 of net revenue due from operator for oil and gas sales for the initial period from February to August 2001. At August 31, 2001, the Company had not received any payments for production from the operator. During 2002, the Company and the operator agreed to offset the receivable against payments due to the operator for cash calls and other liabilities in an amount equal to the revenue due. As of August 31, 2001, the Company's liability due to the operator exceeded accounts receivable for oil and gas sales by $774,037, including $456,585 for drilling costs not billed as of August 31, 2001. Accounts payable and accrued liabilities at August 31, 2002 and 2001 are as follows: 2002 2001 ---------- ---------- Due to operators $ 339,475 $1,947,192 Trade payables 49,132 254,213 Ad Valorem Tax 61,963 61,963 Accrued interest 82,027 -- ---------- ---------- $ 532,597 $2,263,368 ========== ========== F - 15 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 3 - PROPERTY AND EQUIPMENT Property and equipment at August 31, 2002 and 2001 consisted of the following: 2002 2001 ------------ ------------ Oil and gas properties, full cost method Unevaluated costs, not subject to amortization or ceiling test $ 6,771,111 $ 10,977,317 Evaluated costs 25,547,971 13,825,140 Furniture and equipment 121,904 118,208 ------------ ------------ 32,440,986 24,920,665 Less accumulated depreciation, amortization, and impairment (25,635,631) (13,902,710) ------------ ------------ $ 6,805,355 $ 11,017,955 ============ ============ Information relating to the Company's costs incurred in its oil and gas operations during the years ended August 31, 2002, 2001, and 2000 is summarized as follows: 2002 2001 2000 ----------- ----------- ----------- Property acquisition costs, unproved properties $ 1,790,820 $ 4,114,449 $ 1,318,813 Exploration costs 1,519,819 2,448,990 4,610,454 Development costs 4,455,986 6,460,201 -- ----------- ----------- ----------- $ 7,766,625 $13,023,640 $ 5,929,267 =========== =========== =========== Property acquisition costs include costs incurred to purchase, lease, or otherwise acquire a property. Exploration costs include the costs of geological and geophysical activity, and drilling and equipping exploratory wells. The Company reviews and determines the cost basis of drilling prospects on a drilling location basis. At August 31, 2002, the Company recognized an impairment expense of $11,722,830, primarily for the remaining basis in its East Lost Hills project. It is uncertain as to whether or not additional activity will occur at its East Lost Hills project, and it is uncertain as to whether or not the Company will participate should additional activity occur. During the year ended August 31, 2001, the Company earned its initial revenues from its oil and gas producing activities. A reserve report prepared as of August 31, 2001 by an independent petroleum engineering firm concluded that reserves from the Company's producing properties are not economic to produce, and, therefore, at August 31, 2001, the Company had no proved reserves. Therefore, the Company has recorded an impairment of $13,339,911 based on the ceiling test limitation. The Company recorded impairment losses on undeveloped oil and gas properties of $200,000 for the year ended August 31, 2000. F - 16 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 3 - PROPERTY AND EQUIPMENT (continued) At August 31, 2002, 2001, and 2000, accumulated charges to impairment were $25,547,970, $13,825,140, and $485,229, respectively. Depreciation expense for the years ended August 31, 2002, 2001, and 2000 was $14,605, $17,823, and $18,327, respectively. In November 2000, the Company purchased from a privately held non-related entity an additional 1.544% interest in the East Lost Hills project. At August 31, 2002, the Company had a 12.1193% interest in East Lost Hills. NOTE 4 - CONVERTIBLE NOTES PAYABLE In May 2002, the Company completed the sale of $6,000,000, 4.99% convertible promissory notes, due May 2009. The notes are convertible, together with accrued interest, into shares of the Company's common stock at the rate of $1.30 per share, at the option of the holder. No beneficial interest has been accrued to the notes, as the conversion price approximates the fair market value of the common shares as of the transaction date. Interest is payable semiannually in May and November. NOTE 5 - STOCKHOLDERS' EQUITY PREFERRED STOCK In April 1999, the stockholders of the Company approved an amendment to the Certificate of Incorporation pursuant to which the Company was authorized to issue 1,000,000 shares of preferred stock, with a par value of $.001 per share. The Board of Directors authorized the designation of a "Series A Preferred Stock," consisting of 25,000 shares, face value of $100 per share and a 10% cumulative dividend payable in cash or shares of common stock on January 1 and July 1 of each year. Holders of Series A Preferred Stock receive preference in the event of any liquidation, dissolution or winding up of the Company. The shares of Series A Preferred Stock were convertible into shares of common stock of the Company at an initial conversion price of $.60 per share. No beneficial interest has been accrued to the preferred stockholders as the conversion price of $.60 per share was substantially in excess of the fair market value of the common shares as of the transaction date. In April 1999, the holders of $2,500,000 of 10% convertible notes, due October 1999, converted the notes to 25,000 shares of Series A Preferred Stock. As of August 31, 2001, all shares of Series A Preferred Stock were converted to 4,166,664 shares of common stock at the initial conversion price of $.60 per share. COMMON STOCK Effective August 6, 1997, Mar completed a merger with PYR LLC (Note 1). In conjunction with the merger, the members of PYR LLC received 4,000,000 shares of common stock of Mar. These shares were recorded at the net members' equity of PYR LLC as of that date of $33,868. The 1,059,804 Mar shares outstanding as of the date of merger were recapitalized to the net assets of Mar of $336. For financial statement reporting purposes, this transaction was treated as a reverse acquisition whereby PYR LLC was considered the surviving and reporting entity. For legal purposes, however, Mar remained as the surviving entity; therefore, the capital structure of the Company was accordingly restated. F - 17 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 5 - STOCKHOLDERS' EQUITY (continued) In July 1997, the Company completed the sale of common stock and warrants pursuant to a private placement as follows: o 2,095,000 units, at a price of $.25 per unit, consisting of 2,095,000 shares of common stock, warrants to purchase 1,047,500 shares of common stock at an exercise price of $1.25 per share before October 31, 1997, and warrants to purchase 1,047,500 shares of common stock at an exercise price of $1.75 per share before January 31, 1998. Subsequent to the offering, each of the warrant expiration dates was extended one or more times, and all the warrants ultimately expired without having been exercised. In August 1997, the Company completed the sale of common stock and warrants pursuant to a private placement as follows: o 2,000,000 units, at a price of $.75 per unit, consisting of 2,000,000 shares of common stock, warrants to purchase 1,000,000 shares of common stock at an exercise price of $1.25 per share before October 31, 1997, and warrants to purchase 1,000,000 shares of common stock at an exercise price of $1.75 per share before January 31, 1998. Subsequent to the offering, each of the warrant expiration dates was extended one or more times, and all the warrants ultimately expired without having been exercised. Proceeds from these offerings were $523,750 and $1,500,000, respectively, before costs of the offerings of $280,711. In May 1999, the Company completed the sale of 437,500 units of common stock and warrants pursuant to a private placement at a price of $16 per unit. Each unit consisted of 10 shares of common stock and one warrant to purchase one share of common stock at an exercise price of $2.50 per share for a period of five years. The Company may repurchase the warrants for $.001 per warrant at any time after the weighted average trading price of the Company's common stock has been at least $6.00 per share for a 45-day period. Proceeds from the offering were $7,000,000, before costs of the offering of $83,155. During the year ended August 31, 1999, the Company issued shares of common stock, valued at the non-discounted trading market price as of the date of the transaction, in conjunction with the assignment to the Company of certain undeveloped oil and gas prospects located in California as follows: o 266,666 shares, valued at $.75 per share, as full consideration for property received. o 218,866 shares, valued at $2.00 per share, as partial consideration for property received. In April 1999, the Company issued 53,326 shares of common stock for accrued interest on convertible notes of $116,822. The shares issued were valued at $2.19 per share, the non-discounted trading price of the Company's common stock at the transaction date. In May 2000, the Company completed the sale of 22,000 units of common stock and warrants pursuant to a private placement at a price of $32.50 per unit. Each unit consisted of 10 shares of common stock and one warrant to purchase one share of common stock at an exercise price of $4.25 per share for a period of three years. The Company may repurchase the warrants for $.001 per warrant at any time after the weighted average trading price of the Company's common stock has been at least $7.50 per share for a 30 day period. Proceeds from the offering were $715,000, before costs of the offering of $11,857. F - 18 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 5 - STOCKHOLDERS' EQUITY (continued) In August 2000, the Company completed the sale of 540,000 units of common stock and warrants pursuant to a private placement at a price of $17.50 per unit. Each unit consisted of five shares of common stock and one warrant to purchase one share of common stock at an exercise price of $4.80 per share for a period of three years. The Company may repurchase the warrants for $.001 per warrant at any time after the weighted average trading price of the Company's common stock has been at least $10.00 per share for a 30 day period. Proceeds from the offering were $9,450,000, before costs of the offering of $567,436, which included warrants valued at $110,606. During the year ended August 31, 2000, the Company issued 5,000 shares of common stock for services, valued at the non-discounted trading market price as of the date of the transaction of $20,000 ($4.00 per share). During the year ended August 31, 2001, the Company sold 1,450,000 shares of common stock pursuant to a shelf registration at a price of $8.00 per share. Proceeds from the offering were $11,600,000 before costs of $160,470. During the year ended August 31, 2002, options to acquire 10,000 shares of common stock, at $1.50 per share, were exercised. WARRANTS In 2000, the Company issued warrants to purchase 70,875 shares of common stock at an exercise price of $5.50 per share through July 31, 2003 as partial consideration for a finder's fee in conjunction with the private placement of common stock. The warrants are valued at $110,606, using the Black-Scholes option pricing model. In May 2000, in conjunction with the sale of units of common stock and warrants as described above, the Company issued warrants to purchase 22,000 shares of common stock at an exercise price of $4.25 through May 19, 2003. In August 2000, in conjunction with the sale of units and common stock, the Company issued warrants to purchase 540,000 shares of common stock at an exercise price of $4.80 through July 31, 2003. At August 31, 2002, 395,714 warrants were outstanding. In May 2002, the Company issued warrants to purchase 200,000 shares of common stock at an exercise price of $1.49 per share through May 8, 2007, as partial consideration for a financial advisory services agreement. The warrants are valued at $178,665, based on the Black-Scholes option pricing model, and this amount is included in general and administrative expenses as of August 31, 2002. At August 31, 2002, the status of outstanding warrants is as follows: Issue Shares Exercise Expiration Date Exercisable Price Date ---- ----------- ----- ---- July 31, 2000 395,714 $4.80 July 31, 2003 August 1, 2000 70,875 $5.50 July 31, 2003 May 9, 2002 200,000 $1.49 May 8, 2007 At August 31, 2002, the per share weighted average exercise price of outstanding warrants was $3.88 per share and the weighted average remaining contractual life was 2.0 years. F - 19 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 6 - STOCK OPTION PLAN Under two stock option plans, options to purchase common stock may be granted until 2010. Stock options are granted to employees at exercise prices equal to the fair market value of the Company's stock at the dates of grants. Generally, options vest 1/3 each year for a period of three years from grant date and can have a maximum term of up to 10 years. Options are issued to key employees and other persons who contribute to the success of the Company. The Company has reserved 2,500,000 shares of common stock for these plans. At August 31, 2002 and 2001, options to purchase 825,000 and 1,000,000 shares, respectively, were available to be granted pursuant to the stock option plans. The status of outstanding options granted pursuant to the plans are as follows:
Number of Weighted Avg. Weighted Avg. Shares Exercise Price Fair Value ------ -------------- ---------- Options Outstanding - September 1, 1999 821,000 $1.20 $ .74 (149,000 exercisable) Granted 379,000 $3.06 $2.37 Exercised (27,500) $ .96 ------- Options Outstanding - August 31, 2000 1,172,500 $2.12 $1.26 (447,500 exercisable) Granted 300,000 $6.10 $3.66 Exercised (246,000) $1.17 -------- Options Outstanding - August 31, 2001 1,226,500 $3.31 $1.94 (537,333 exercisable) Granted 315,000 $1.66 $1.18 Exercised (10,000) $1.50 Expired (140,000) $2.57 -------- Options Outstanding - August 31, 2002 (858,165 exercisable) 1,391,500 $3.03 $1.90 ========= The calculated value of stock options granted under these plans, following calculation methods prescribed by SFAS 123, uses the Black-Scholes stock option pricing model with the following assumptions used: 2002 2001 2000 ---- ---- ---- Expected option life-years 5 5 2-5 Risk-free interest rate 4.375% 5.75% 5.50% Dividend yield 0 0 0 Volatility 82-89% 68-75% 71-81% At August 31, 2002, the number of options exercisable was 858,165, the weighted average exercise price of these options was $2.57, the weighted average remaining contractual life of the options was 1.97 years and the exercise price was $.69 to $8.63 per share. F - 20 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 6 - STOCK OPTION PLAN (continued) The Company has adopted the disclosure-only provisions of SFAS 123. Had compensation cost for the Company's stock option plan been determined based on the fair value at the grant date consistent with the provisions of SFAS 123, the Company's net loss and loss per share for 2002, 2001, and 2000 would have been increased to the pro forma amounts indicated below: 2002 2001 2000 ------------ ------------ ----------- Net (loss) applicable to common stockholders - as reported $(13,129,828) $(13,205,171) $(1,161,168) ============ ============ =========== Net (loss) applicable to common stockholders - pro forma $(13,995,781) $(13,632,412) $(1,483,622) ============ ============ =========== (Loss) per share - as reported $ (.55) $ (.59) $ (.07) ============ ============ =========== (Loss) per share - pro forma $ (.59) $ (.61) $ (.09) ============ ============ ===========
NOTE 7 - COMMITMENTS AND CONTINGENCIES The Company has entered into a non-cancelable lease, as amended, for office facilities. Minimum payments due under this lease are as follows: Year ending August 31, 2003 $97,723 2004 97,723 Rent expense was $98,415, $58,988, and $41,036 for the years ended August 31, 2002, 2001, and 2000, respectively. In conjunction with the Company's working interests in undeveloped oil and gas prospects, the Company must pay approximately $1,120,000 in delay rentals and other costs during the fiscal year ending August 31, 2003 to maintain the right to explore these prospects. The Company may be subject to various possible contingencies which are derived primarily from interpretations of federal and state laws and regulations affecting the oil and gas industry. Although management believes it has complied with the various laws and regulations, new rulings and interpretations may require the Company to make adjustments. NOTE 8 - SEGMENT REPORTING In June 1997, SFAS 131, "Disclosure about Segments of an Enterprise and Related Information", was issued, which amends the requirements for a public enterprise to report financial and descriptive information about its reportable operating segments. Operating segments, as defined in the pronouncement, are components of an enterprise about which separate financial information is available and that are evaluated regularly by the Company in deciding how to allocate resources and in assessing performance. The financial information is required to be reported on the basis that is used internally for evaluating segment performance and deciding how to allocate resources to segments. The Company has one reportable segment, oil and gas exploration and production. The Company has concentrated its oil and gas acquisition and exploration activities in the western United States, primarily in California and the Rocky Mountain region. All significant activities in this segment have been with industry partners. F - 21 PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 8 - SEGMENT REPORTING (continued) During 2001, initial production commenced on the Company's East Lost Hills Prospect in California, and production continued through 2002. Results of operations for oil and gas operations in 2002 and 2001 are as follows: 2002 2001 ------------ ------------ Revenues Oil and gas sales $ 132,569 $ 1,201,979 ------------ ------------ Expense Lease operating expense 91,384 40,055 Ad Valorem Taxes -- 61,963 Impairment 11,722,830 13,339,911 ------------ ------------ 11,814,214 13,441,929 ------------ ------------ (Loss) from oil and gas operations $(11,681,645) $(12,239,950) ============ ============ All sales of oil and gas were made to one customer. No depletion has been recorded on oil and gas properties. The Company recorded impairments against its entire amortizable full cost pool as of August 31, 2002, and 2001 and accordingly, had no costs to amortize. (See Note 3). NOTE 9 - COMPREHENSIVE INCOME There are no adjustments necessary to net (loss) as presented in the accompanying statements of operations to derive comprehensive income in accordance with SFAS 130, "Reporting Comprehensive Income." F-22
PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements NOTE 10 - QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary of the unaudited financial data for each quarter for the years ended August 31, 2002, 2001 and 2000: Three Months Ended 2002 11/30/01 2/28/02 5/31/02 8/31/02 Revenues $ 108,914 $ 58,564 $ 62,087 $ 48,649 ------------ ------------ ------------ ------------ Operating expenses Lease operating expenses 25,167 6,794 28,808 30,615 Impairment, dry hole and abandonments 113,544 -- -- 11,609,286 Depreciation and amortization 3,496 3,730 3,691 3,688 General and administrative 324,143 328,142 323,474 520,570 Interest -- -- 6,562 76,332 ------------ ------------ ------------ ------------ 466,350 338,666 362,535 12,240,491 ------------ ------------ ------------ ------------ Net (Loss) $ (357,436) $ (280,102) $ (300,448) $(12,191,842) ============ ============ ============ ============ Net (Loss) per common share Basic and diluted $ (.02) $ (.01) $ (.01) $ (.51) ============ ============ ============ ============ In the quarter ended August 31, 2002, the Company recorded an impairment of $11,560,212 on its East Lost Hills project. Three Months Ended 2001 11/30/00 2/28/01 5/31/01 8/31/01 Revenues $ 111,128 $ 309,566 $ 965,155 $ 238,247 ------------ ------------ ------------ ------------ Operating expenses Lease operating expenses -- 3,052 78,005 20,961 Impairment -- -- -- 13,339,911 Depreciation and amortization 4,098 4,843 5,507 3,375 General and administrative 254,248 320,781 370,021 361,585 ------------ ------------ ------------ ------------ 258,346 328,676 453,533 13,725,832 ------------ ------------ ------------ ------------ Net (Loss) Income $ (147,218) $ (19,110) $ 511,622 $(13,487,585) ============ ============ ============ ============ Net (Loss) income per common share Basic and diluted $ (.007) $ (.001) $ .022 $ (.569) ============ ============ ============ ============ In the quarter ended August 31, 2001, the Company recorded an impairment of $13,339,911 on its oil and gas properties due to a ceiling test limitation. Included in the impairment is a reclassification of depletion originally recorded on oil and gas properties of $16,035 and $52,421 for the quarters ended February 28, 2001 and May 31, 2001, respectively. F-23