10QSB 1 pyr205.txt 10QSB U.S. Securities And Exchange Commission Washington, D.C. 20549 FORM 10-QSB [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended February 28, 2005 OR [ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______________ to ______________ Commission File No. 001-15511 PYR ENERGY CORPORATION ---------------------- (Exact name of small business issuer as specified in its charter) Maryland 95-4580642 -------- ---------- (State or other jurisdiction (I.R.S. Employer Identification No.) of incorporation or organization) 1675 Broadway, Suite 2450, Denver, CO 80202 ------------------------------------- ----- (Address of principal executive offices) (Zip Code) Issuer's telephone number, including area code (303) 825-3748 Check whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X] (APPLICABLE ONLY TO CORPORATE REGISTRANTS) The number of shares outstanding of each of the issuer's classes of common equity as of February 28, 2005 is as follows: $.001 Par Value Common Stock 31,574,426 ----------
PART I. FINANCIAL INFORMATION Item 1. Financial Statements 3 Balance Sheets - February 28, 2005 (Unaudited) and August 31, 2004 3 Statements of Operations - Three and Six Months Ended February 28, 2005 and February 29, 2004 (Unaudited) 4 Statements of Cash Flows - Six Months Ended February 28, 2005 and February 29, 2004 (Unaudited) 5 Notes to Financial Statements 7 Item 2. Management's Discussion and Analysis or Plan of Operation 10 Item 3. Controls and Procedures 22 PART II. OTHER INFORMATION Item 1. Legal Proceedings 23 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 23 Item 3. Defaults Upon Senior Securities 23 Item 4. Submission of Matters to a Vote of Security Holders 23 Item 5. Other Information 23 Item 6. Exhibits 23 Signatures 24 2 ITEM 1. FINANCIAL STATEMENTS PYR ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS ASSETS February 28, August 31, CURRENT ASSETS 2005 2004 ------------ ------------ Cash $ 5,171,981 $ 6,038,156 Receivables: Oil and gas receivables 1,365,116 477,176 Joint billing receivables 109,373 -- Other receivables 7,692 -- Exploration option receivable -- 750,000 ------------ ------------ 1,482,181 1,227,176 Prepaid expenses and other assets 114,206 102,239 ------------ ------------ Total current assets 6,768,368 7,367,571 ------------ ------------ PROPERTY AND EQUIPMENT, at cost Furniture and equipment, net 31,945 26,736 Oil and gas properties under full cost, net 10,276,172 8,851,351 ------------ ------------ 10,308,117 8,878,087 ------------ ------------ OTHER ASSETS Deferred financing costs and other assets 63,476 65,070 ------------ ------------ 63,476 65,070 ------------ ------------ TOTAL ASSETS $ 17,139,961 $ 16,310,728 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable $ 203,536 $ 83,042 Accrued expenses: Ad valorem tax payable 65,068 65,068 Accrued interest payable 89,114 89,644 Accrued net profits interest payable 354,954 -- Other accrued liabilities 251,738 199,688 ------------ ------------ 760,874 354,400 Asset retirement obligation 868,163 868,163 ------------ ------------ Total current liabilities 1,832,573 1,305,605 ------------ ------------ LONG TERM LIABILITIES Convertible Notes 6,789,962 6,623,351 Asset retirement obligation 315,757 289,489 ------------ ------------ Total long term liabilities 7,105,719 6,912,840 ------------ ------------ COMMITMENTS AND CONTINGENCIES STOCKHOLDERS' EQUITY Preferred stock, $.001 par value; authorized 1,000,000 shares; issued and outstanding - none -- -- Common stock, $.001 par value; authorized 75,000,000 shares Issued and outstanding - 31,574,426 at 2/28/05 and 31,564,426 shares at 8/31/04 31,574 31,564 Capital in excess of par value 43,239,529 43,221,391 Accumulated deficit (35,069,434) (35,160,672) ------------ ------------ Total stockholders' equity 8,201,669 8,092,283 ------------ ------------ $ 17,139,961 $ 16,310,728 ============ ============ 3 PYR ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS Three Three Six Six Months Months Months Months Ended Ended Ended Ended 2/28/2005 2/29/2004 2/28/2005 2/29/2004 --------- --------- --------- --------- REVENUES Oil and gas revenues $ 1,195,671 $ 44,376 $ 2,278,181 $ 84,394 ------------ ------------ ------------ ------------ 1,195,671 44,376 2,278,181 84,394 ------------ ------------ ------------ ------------ OPERATING EXPENSES Lease operating expenses 203,153 21,681 483,729 36,952 Accretion expense 6,307 21,152 12,607 42,304 Net profits interest expense 232,588 -- 354,954 -- Depreciation and amortization 167,046 41,804 205,083 81,924 General and administrative 497,669 285,442 1,009,056 536,932 ------------ ------------ ------------ ------------ Total operating expenses 1,106,763 370,079 2,065,429 698,112 INCOME (LOSS) FROM OPERATIONS 88,908 (325,703) 212,752 (613,718) OTHER INCOME (EXPENSE) Interest income 24,833 5,041 45,132 10,608 Other income 4,141 -- 8,281 -- Interest (expense) (84,342) (81,196) (167,675) (160,550) Other (expense) (3,335) -- (7,253) ------------ ------------ ------------ ------------ Total other (expense) (58,703) (76,155) (121,515) (149,942) NET INCOME (LOSS) $ 30,205 $ (401,858) $ 91,237 $ (763,660) ============ ============ ============ ============ NET INCOME (LOSS) PER COMMON SHARE -BASIC & DILUTED $ 0.00 $ (0.02) $ 0.00 $ (0.03) ============ ============ ============ ============ BASIC WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 31,564,870 23,701,357 31,564,647 23,701,357 ============ ============ ============ ============ DILUTED WEIGHTED AVERAGE COMMON SHARES OUTSTANDING 32,130,113 23,701,357 32,086,400 23,701,357 ============ ============ ============ ============ 4 PYR ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS Six Months Six Months Ended Ended February 28, February 29, 2005 2004 ----------- ----------- CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 91,237 $ (763,660) Adjustments to reconcile net income (loss) to net cash (used) by operating activities Depreciation and amortization 205,083 81,924 Amortization of financing costs 1,594 1,593 Interest expense converted into debt 166,611 158,577 Accretion of asset retirement obligation 12,605 42,304 Stock options issued for director service 15,248 -- Changes in assets and liabilities (Increase) in accounts receivable (888,567) (6,553) (Increase) in joint billings receivable (109,373) -- (Increase) in prepaids and other receivables (19,032) (55,957) Increase (decrease) in accounts payable 122,121 (72,184) Increase in net profits interest liability 354,954 -- Increase (decrease) in accrued expenses 48,953 (33,748) Other -- (50,000) ----------- ----------- Net cash provided (used) by operating activities 1,435 (697,704) ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Cash paid for furniture and equipment (10,609) (237) Cash paid for oil and gas properties (1,659,181) (238,200) Deferred acquisition costs -- (250,000) Proceeds from exercise of exploration options 750,000 -- Proceeds from exercise of stock options 2,900 -- Proceeds from sale of oil and gas properties 49,280 186,016 Other -- (10,000) ----------- ----------- Net cash (used) in investing activities (867,610) (312,421) ----------- ----------- ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES -- -- ----------- ----------- NET DECREASE IN CASH (866,175) (1,010,125) CASH, BEGINNING OF PERIODS 6,038,156 3,657,938 ----------- ----------- CASH, END OF PERIODS $ 5,171,981 $ 2,647,813 =========== =========== 5
PYR ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) SIX MONTHS ENDED FEBRUARY 28, 2005 AND FEBRUARY 29, 2004 (Unaudited) SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES During the six months ended February 28, 2005 and February 29, 2004, the asset retirement obligation increased by $13,660 and $0, respectively. 6 PYR ENERGY CORPORATION Notes to Consolidated Financial Statements February 28, 2005 (Unaudited) The accompanying interim financial statements of PYR Energy Corporation are unaudited. In the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the results for the interim period. The results of operations for the three and six months ended February 28, 2005 are not necessarily indicative of the operating results for the entire year. We have prepared the financial statements included herein pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosure normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. We believe the disclosures made are adequate to make the information not misleading and recommend that these condensed financial statements be read in conjunction with the financial statements and notes included in our Form 10-KSB for the year ended August 31, 2004. 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: ------------------------------------------- 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. The Company's financial statements are based on a number of significant estimates, including reliability of receivables, selection of the useful lives for property and equipment, timing and costs associated with its retirement obligations and oil and gas reserve quantities which are the basis for the calculation of depreciation, depletion and impairment of oil and gas properties. 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, which is considered a significant estimate by the Company, which is subject to changes. Price declines reduce the estimated quantity of proved reserves and increase annual amortization expense (which is based on proved reserves) and may impact the impairment analysis of the Company's full cost pool. Earnings (Loss) Per Share - Basic earnings (loss) per common share is computed by dividing net earnings (loss) attributed to common stock by the weighted average number of common shares outstanding during each period. Diluted earnings (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible equity instruments, such as convertible notes payable, stock options and warrants. The following table sets forth the computation of basic and diluted earnings per share: 7
Three Three Six Six Months Months Months Months Ended Ended Ended Ended 2/28/2005 2/29/2004 2/28/2005 2/29/2004 ----------- ----------- ----------- ----------- Numerator: Numerator for basic and diluted earnings per share - income (loss) available to common stockholders 30,205 (401,858) 91,237 (763,660) Denominator: Denominator for basic earnings per share -weighted average shares outstanding 31,564,870 23,701,357 31,564,647 23,701,357 Effect of dilutive securities - stock options and warrants 565,243 -- 521,753 -- ----------- ----------- ----------- ----------- Denominator for diluted earnings per common share 32,130,113 23,701,357 32,086,400 23,701,357 =========== =========== =========== =========== Basic earnings (loss) per common share $ 0.00 $ (0.02) $ 0.00 $ (0.03) =========== =========== =========== =========== Diluted earnings (loss) per common share $ 0.00 $ (0.02) $ 0.00 $ (0.03) =========== =========== =========== =========== Share Based Compensation - In October 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation (SFAS 123), effective for fiscal years beginning after December 15, 1995. This statement defines a fair value method of accounting for employee stock options and encourages entities to adopt that method of accounting for its stock compensation plans. SFAS 123 allows an entity to continue to measure compensation costs for these plans using the intrinsic value based method of accounting as prescribed in Accounting Pronouncement Bulletin Opinion No. 25, Accounting for Stock Issued to Employees (APB 25). The Company has elected to continue to account for its employee stock compensation plans as prescribed under APB 25. Had compensation cost for the Company's stock-based compensation plans been determined based on the fair value at the grant dates for awards under those plans consistent with the method prescribed in SFAS 123, the Company's net income (loss) and income (loss) per share for the quarters ended February 28, 2005 and February 29, 2004 would have been increased (decreased) to the pro forma amounts indicated below: 8 Three Three Six Six Months Months Months Months Ended Ended Ended Ended 2/28/2005 2/29/2004 2/28/2005 2/29/2004 ----------- ----------- ----------- ----------- Net income (loss) as reported $ 30,205 $ (401,858) $ 91,237 $ (763,660) Deduct: stock-based compensation costs under SFAS No. 123 (82,839) (162,444) (165,678) (295,064) ----------- ----------- ----------- ----------- Pro forma net income (loss) (52,634) (564,302) (74,441) (1,058,724) =========== =========== =========== =========== Pro forma basic and diluted net income per share: As reported $ 0.00 $ (0.02) $ 0.00 $ (0.03) Pro forma $ 0.00 $ (0.02) $ 0.00 $ (0.04)
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: February 28, February 29, 2005 2004 ---- ---- Expected option life-years 5 5-7 Risk-free interest rate 3.3 - 3.7% 3.0 % Dividend yield 0.00% 0.00% Volatility 58-83% 100-125% Reclassification - Certain reclassifications have been made to the February 29, 2004 financial statements to conform to February 28, 2005 presentation. Such reclassifications had no effect on net loss. Recent Accounting Pronouncements - In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123(R), "Share-Based Payment". This statement requires all entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. SFAS No. 123(R) is effective the first reporting period beginning after December 15, 2005. Due to the recent adoption of SFAS No. 123(R), the Company has not determined the future impact on its financial statements; however, it will result in additional future financial reporting expense to the Company when implemented. 2. ACQUISITION OF PROPERTIES: -------------------------- In May 2004, the Company acquired certain oil and gas properties from Venus Exploration Inc. ("Venus") for cash consideration of $3,230,000. The financial statements therefore reflect the revenue and other operating expenses associated with these properties since the date of acquisition. The purchase also provides for the Company to pay a net profits interest payable to the Venus Exploration Trust ("Trust"). During the three and six months ended February 28, 2005, the Company accrued $232,588 and $354,954, respectively, which is payable to the Trust based on the net profits interest agreement; however, the company does not anticipate that it will be required to pay this amount as the Company intends to drill additional wells in the future on the property subject to payout. Costs incurred in connection with additional drilling would reduce this liability; however, in the unlikely event the Company does not incur additional drilling costs, such amount would then be payable to the Trust. The net profits interest, which applies only to the exploration and exploitation projects on the Venus acreage acquired, varies from 25% to 50% with respect to different Venus exploration and exploitation project areas, and decreases by one-half of its original amount after a total of $3,300,000 in net profits proceeds has been paid to the Trust. 9 3. CONTINGENCY ----------- We are currently in dispute with the operator of the Sun Fee #1, Sampson Lone Star L.P. ("Sampson"), concerning the pooling of certain lands into the production unit at Nome Field. The pooling of these lands in which the Company does not own an interest, comprises approximately 32% of the unit area, and may result in a reduction of working interest and net revenue interest, relative to production from the Sun Fee #1, attributable to the Company. If the current pooling were to stand, our working interest in the well would be reduced from 8.33% to 5.19%. The Company strongly believes that the lands in question are `Non-Productive', and therefore not eligible for pooling, based on all available geological, seismic, and existing well data. As a result of this dispute, we will vigorously pursue and defend our rights to our proportionate share of production and revenue from the Sun Fee #1 with all legal avenues and remedies available. For this reason, the Company has not signed any of the proposed production and revenue division orders, and has not received any revenue, attributable to the well, to date. If we undertake legal action against the operator relative to this issue, which we currently intend, it may result in all revenues attributable to the Sun Fee #1 well being held in suspense until the legal action is completed. If the outcome of the dispute results in the operator recognizing our working interest of 8.33%, the increased working interest could potentially result in increased revenue to the Company and increased net profits liability to Venus Exploration Trust, subject to the net profits interest agreement. The oil and gas receivable pertaining to the Sun Fee #1 well is approximately $1,011,000 at February 28, 2005. For the quarter ended February 28, 2005, we accrued approximately $512,000 in royalty and working interest revenues from the Sun Fee #1. As a result of the dispute with Sampson, revenues were accrued at the lower working interest percentage (5.19%) as stated by the operator. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION OR PLAN OF OPERATION The following discussion should be read in conjunction with the Financial Statements and Notes thereto referred to in "Item 1. Financial Statements" of this Form 10-QSB. Overview PYR Energy Corporation (referred to as "PYR," the "Company," "we," "us" and "our") is an independent oil and gas exploration and production company, engaged in the exploration, development and acquisition of crude oil and natural gas reserves. Our exploration activities are focused in select areas of the Rocky Mountains, Texas and Gulf Coast, Southeast Alberta, and in the San Joaquin Basin of California. We continue to focus our exploration efforts and advanced technical expertise on the pre-drill phases of our high potential exploration projects in the Rocky Mountain region. Liquidity and Capital Resources Our primary sources of liquidity historically have been from placements of common stock and convertible notes, and to a much lesser extent, cash provided by operating activities. Our primary use of capital has been for the acquisition, development, and exploration of oil and natural gas properties. As we pursue growth, we continually monitor the capital resources available to us to meet our future financial obligations, planned capital expenditure activities and liquidity. Our future success in growing proved reserves and production is highly dependent on capital resources available to us, and our success in finding or acquiring additional reserves. At February 28, 2005, we had approximately $4,935,795 in working capital. During the quarter ended February 28, 2005, our capitalized costs for oil and gas properties increased by approximately $512,457. The increase reflects net costs incurred for undeveloped leasehold, drilling and completion, workover, geological and geophysical costs, delay rentals and other related direct costs with respect to our exploration and development prospects, which is further discussed in Capital Expenditures and Summary of Exploration Projects. 10 It is anticipated that the continuation and future development of our business will require additional, and possibly substantial, capital expenditures. We have no reliable source for additional funds for administration and operations to the extent our existing funds have been utilized. 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 or that it will be available on satisfactory terms. CAPITAL EXPENDITURES During the quarter ended February 28, 2005, we incurred approximately $570,865 of capital costs for our oil and gas properties. This amount includes costs associated with undeveloped leasehold, drilling and completion, workover, geological and geophysical costs, delay rentals, and other related direct costs with respect to our exploration and development prospects. Revenues from oil and gas production during the quarter were $1,195,671. We currently anticipate that we will participate in the drilling of up to six exploration wells during the calendar year ending December 31, 2005.However, there can be no assurance that any such wells will be drilled and if drilled that any of these wells will be successful. We anticipate spending a minimum of $3,000,000, possibly up to $7,000,000 million, on exploration and development activities during the calendar year ending December 31, 2005. In total, we hope to drill between 8 and 12 wells by the end of the calendar year, depending on rig availability. 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. PRODUCTION AND RESERVES For the quarter ended February 28, 2005, production averaged 1,865 Mcfe per day compared to 1,584 Mcfe per day for the quarter ended November 30, 2004. The 18% increase in average daily production was primarily due to a full quarter of production from the Sun Fee #1-ST, a well in the Nome Field that reached payout status in mid-October, 2004. Total proved reserves, at calendar year end (December 31, 2004), were 6.73 Bcfe based on external estimation. Estimated 'total proved' reserves increased by 22% when compared to estimates made at August 31, 2004, and by 41% when compared to the estimated 'total proved' reserves on May 31, 2004. The increase in 'total proved' reserves results from additions to the 'proved developed producing' and 'proved un-developed' classification attributable to several new discoveries resulting from drilling, primarily in South Texas. The external estimated 'total proved' reserves includes the addition of 'proved developed producing' reserves at the Sun Fee #1-ST well in Jefferson County, Texas, where the Company's working interest is currently under dispute with the operator of the well. Reserves for the well were estimated using the Company's claimed higher working interest of 8.33%. Reserve estimations using the operator's proposed working interest of 5.19%, currently being used to accrue revenue, results in a reduction of 'proved developed producing' reserves of 101 MMcfe giving 'total proved' reserves estimated at 6.63 Bcfe. Present value, discounted at 10%, for the 'total proved' reserves is estimated to be $14.49 million at December 31, 2004, compared to $6.94 million estimated at May 31, 2004. The 109% increase in estimated present value is attributable to higher product prices and increased reserves from drilling. SUMMARY OF EXPLORATION PROJECTS Our exploration activities are focused primarily in select areas of the Rocky Mountains, Texas and Gulf Coast, Southeast Alberta, and in the San Joaquin Basin of California. 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. 11 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. ROCKY MOUNTAIN EXPLORATION Montana Foothills Project. This extensive natural gas exploration project, located in west-central 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 the 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, the Unocal #1-B30, drilled in 1989 to a depth of 17,817 feet, which was plugged and abandoned after testing. 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. Within the Rogers Pass acreage block, we have undertaken extensive seismic analysis and geological study, resulting in the identification of multiple untested, prospective structures. In March 2004, we signed an Exploration Option Agreement with a subsidiary of Suncor Energy, Incorporated, covering our Rogers Pass exploration project. We currently control approximately 241,800 gross and 226,300 net leasehold acres in the Rogers Pass project. Pursuant to our agreement with the subsidiary of Suncor Energy, Suncor Energy Natural Gas America, Inc. ("SENGAI"), SENGAI has paid us a $500,000 option fee for a technical evaluation period of up to three months. On August 31, 2004 SENGAI exercised its option to drill an initial test well at Rogers Pass, and paid us $750,000 in the form of a prospect fee (received in September 2004). On March 11, 2005, drilling activities began at the Company's Rogers Pass Project in the Montana Foothills. The Suncor Energy Natural Gas America, Inc. #14063-12 Flesher Pass well, located approximately twenty-five miles northwest of Helena, Montana, will test a potential structural closure within the Montana Foothills trend. Anticipated target depth for the prospect is estimated to be approximately 14,500 feet. SENGAI will bear 100% of the costs of the well, to a depth sufficient to evaluate the Mississippian, to earn a 100% working interest in 100,000 acres of the project area. SENGAI will have the option to pay a second prospect fee of $1,250,000 and drill a second test well, to be spud by December 31, 2005. By paying this second prospect fee and bearing 100% of the costs of the second well, SENGAI will earn a 100% working interest in the remaining acreage within the project area. We will retain a 12.5% overriding royalty interest, subject to amortized recovery of gas plant and certain transportation costs, covering all earned acreage within the Rogers Pass project area. Mallard Project. The Mallard project, located within the Overthrust Belt of southwest Wyoming, is a sour gas and condensate exploration prospect in Uinta County, Wyoming. We believe that 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 splaying 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. The agreement we entered into with two private companies ("the Participants") in December 2003 requires the Participants to drill the initial test well at the Mallard Prospect to earn part of our acreage position within a designated area of mutual interest. We currently control 4,160 net leasehold acres within the AMI. During the fiscal year ended 2004, the partners paid us approximately $450,000 in prospect fees and pro-rata development costs. The 12 Mallard well started drilling in mid-July and Intermediate casing was set to 9,735 feet in the Thaynes Formation. The Bureau of Land Management suspended drilling activities at Mallard, effective December 1, 2004, due to wildlife critical winter range restrictions. As a result, the well has been temporarily suspended and secured in compliance with applicable federal and state regulations, until the wildlife restrictions are lifted in mid - 2005. We are participating with a 5% working interest in the drilling of Mallard, and will be carried to casing point, at an estimated total depth of 15,500 feet, for an additional 23.75% working interest. After casing point, we will have a 28.75% working interest in the initial test well and all subsequent wells in the prospect. Cumberland Project. Drilling at the Cumberland prospect located within the Overthrust Belt of southwest Wyoming, started in early November 2004. The Cumberland #1-16 State well reached total drilling depth of 10,860 feet in the Nugget Sandstone. Based on preliminary log analysis, the Nugget zone of interest appears to be nonproductive, and the well will be plugged and abandoned. Further evaluation of the log data will be analyzed and studied to determine any remaining prospective targets within our 6,233 net leasehold area of mutual interest ("AMI"). PYR participated in the drilling of the well at a 10% working interest and was carried for an additional 22.5% working interest to casing point. Ryckman Creek Project. We have recently leased approximately 1,820 net acres, covering the majority of the abandoned Ryckman Creek field, in the Overthrust of southwestern Wyoming. Ryckman Creek, located 5 miles southwest of our Cumberland prospect, was discovered in 1975 and produced approximately 250 Bcfe prior to abandonment. We believe that significant remaining recoverable gas reserves were stranded in Ryckman Creek upon abandonment. We are currently analyzing production and geologic data to determine potential reserves in multiple zones, including the Twin Creek, Nugget, and Thaynes Formations, in the field. Due to winter activity restrictions, it is anticipated that a well may be drilled at Ryckman Creek in mid-2005, and, based on our analysis, we may decide to sell part of our 100% working interest in the project. TEXAS AND GULF COAST EXPLORATION: In May 2004, we acquired interests from Venus Exploration, Inc. ("Venus") in certain producing properties with estimated proved reserves of 4.784 Bcfe for approximately $3,230,000 (excluding acquisition expenses and subject to retention, by the Venus Exploration Trust, of a net profits interest covering the non-productive exploration projects). This equates to $0.67 per Mcf, with a PV-10 value of $6.94 million. The purchase also provides for us to pay a net profits interest payable to the Venus Exploration Trust. The net profits interest, which applies only to the exploration and exploitation projects on the Venus acreage being acquired, varies from 25% to 50% with respect to different Venus exploration and exploitation project areas, and decreases by one-half of its original amount after a total of $3,300,000 in net profits proceeds has been paid to the Trust. Venus was in Chapter 11 Bankruptcy, and the properties were acquired through public auction as approved by the United States Bankruptcy Court. To finance the purchase, we primarily used existing cash reserves and also a portion of the proceeds from a private placement of common stock. Oil and gas interests acquired from Venus include producing oil and gas properties, exploitation drilling projects, and exploration acreage. The assets acquired include interests in 80 non-operated wells in Utah, Oklahoma and Texas. In Texas, we have interests in three projects that were drilled and completed over this past summer. Two of the three wells, the Nome and Madison Prospects, were completed as producers and are currently flowing to sales lines. These two successful projects are, upon reaching payout, subject to a 50% net profits interest payable to the Venus Exploration Trust. Tortuga Grande prospect, located in east Texas, is a project to test the productivity of the Cotton Valley Sand section at depths ranging from 13,000 to 14,500 feet. Drilled originally in 1984 for deeper targets, the Brady #1 is the only deep well on the structure, and had shows in the Cotton Valley Sand, but was never fracture stimulated. Log analysis indicates that the well contains approximately 322 feet of potential pay greater than 8% porosity. The Brady #1, in which we have a 20% carried working interest, was re-entered and the middle Cotton Valley Sand section was fracture stimulated and tested. Results of the test were inconclusive and the partners continue to evaluate the test data. The partners may decide at a future date to drill another well to test the Cotton Valley within the project area. Should this occur, PYR would be responsible for 20% of the costs of any additional well. In all additional locations within the Tortuga Grande area of mutual interest, we will participate with a cost bearing 20% working interest. We currently control approximately 5,600 net leasehold 13 acres within the project. It is anticipated that the partners will drill another test well at Tortuga Grande during the second calendar quarter of 2005. This proposed well will be approximately 1000 feet structurally high to the Brady #1 and should test a complete section of Cotton Valley Sand. The operator has built the location for the well, and is currently waiting on rig availability prior to commencing drilling activities, which are anticipated to begin within the next month or two. Nome Field was discovered in 1994, and our interpretation of subsequently acquired 3D seismic over the field indicates the presence of numerous undeveloped fault blocks. Multiple structural closures and associated bright spot locations have been identified at Nome based on the 3D seismic. PYR owns a 1.5% overriding royalty interest with an additional 8.33% working interest, after project payout, in the project. Production in the Sun Fee #1 well, from the upper Yegua, was initiated in late May 2004, and over the past months, the well has averaged approximate production of 15MMcfe per day. Cumulative production since inception is in excess of 3.0 Bcfe through February 7, 2005. Payout on the Sun Fee #1 occurred on October 13th, 2004 and PYR is currently a working interest participant in the well. We and our partners control approximately 4,200 acres of gross leasehold acres in the project. PYR plans, in the near future, to submit a drilling operations AFE (Authorizaton for Expenditure) to the partners to drill, test and complete a well offsetting the current Sun Fee #1 location. We are currently in dispute with the operator of the Sun Fee #1, Sampson Lone Star L.P. ("Sampson"), concerning the pooling of certain lands into the production unit. The pooling of these lands in which the Company does not own an interest, comprises approximately 32% of the unit area, and may result in a reduction of working interest and net revenue interest, relative to production from the Sun Fee #1, attributable to the Company. If the current pooling were to stand, our working interest in the well would be reduced from 8.33% to 5.19%. The Company strongly believes that the lands in question are `Non-Productive', and therefore not eligible for pooling, based on all available geological, seismic, and existing well data. As a result of this dispute, we will vigorously pursue and defend our rights to our proportionate share of production and revenue from the Sun Fee #1 with all legal avenues and remedies available. For this reason, the Company has not signed any of the proposed production and revenue division orders, and has not received any revenue, attributable to the well, to date. If we undertake legal action against the operator relative to this issue, which we currently intend, it may result in all revenues attributable to the Sun Fee #1 well being held in suspense until the legal action is completed. For the quarter ended February 28, 2005, we accrued approximately $512,000 in royalty and working interest revenues from the Sun Fee #1. As a result of the dispute with Sampson, revenues were accrued at the lower working interest percentage (5.19%) as stated by the operator. The oil and gas receivable pertaining to the Sun Fee #1 well is approximately $1,011,000 at February 28, 2005. Both revenues and costs associated with the production from the Sun Fee #1, as well as the costs incurred on the Nome Project, are subject to the net profits interest agreement we hold with Venus Exploration Trust ("Trust"). The net profits interest agreement arose out of the acquisition of properties from Venus Exploration Inc. ("Venus") in May 2004. The agreement varies from 25% to 50% with respect to different Venus exploration and exploitation project areas, and decreases by one-half of its original amount after a total of $3,300,000 in net profits proceeds has been paid to the Trust. The amount of net profits interest liability recognized over time is subject to fluctuation, because both revenues and costs associated with production from any wells and other costs incurred on the designated exploration and exploitation project areas will increase or decrease over a given period of time. As of February 28, 2005, we accrued a net profits interest liability of $354,954 payable to the Trust. Madison prospect, located in the northern part of the Constitution Field, is an exploitation project to test multiple sand intervals within the expanded Yegua section, downthrown to a major growth fault. The prospect involves sidetracking an existing cased hole updip to test multiple sand targets at a location offsetting, but significantly high to Doyle sand production from the Texaco #1 Doyle well within the field. The location is also offset to the Texaco #1 Sanders Gas Unit well, which tested the Doyle sand interval at a rate of 1,176 Bcf/d and 2.7 MMcf/d with no water. This well was subsequently plugged and abandoned in the Doyle interval and never produced from the zone. The Maness Gas Unit location represents a proved undeveloped location for Doyle sand, 183 feet structurally high to the equivalent produced zone in the Texaco Doyle #1 well. The current well has been drilled to total depth, production casing has been run, and the well is currently producing at a rate of approximately 5.00 MMcfe per day. We own a 0.5% overriding royalty interest that converts to a 12.5% working interest in the project after payout (which has not been reached) of the initial test well. The operator has converted an existing wellbore within the project area into a water disposal well, and is planning to drill an offset development well (Maness GU#2). The cost of the water disposal well will be covered under the payout account, and we will participate for 12.5% working interest in the drilling of this development well. It is anticipated that the offset well will begin drilling operations in May 2005, based on rig availability. 14 Cotton Creek prospect, located in Jefferson County, Texas, is adjacent to the Nome project. The prospect is located approximately one mile west of the productive Sun Fee #1 well in the same structural fault block. PYR owns a 50% working interest in the project and controls with its partner approximately 500 acres of leasehold. It is anticipated that an initial test well will be drilled in 2005. PYR will retain approximately 25% working interest in the well and will farm-out the remainder of its interest to an industry partner. Merganser prospect, located in Leon County, Texas, targets Cotton Valley and Bossier sandstone reservoirs in an undrilled structural feature defined by 3D seismic data. The prospect occupies a fault-bounded salt-withdrawal trough resulting in potential significant thickening of the Bossier and Cotton Valley sand sections. The prospect location is structurally and stratigraphically downdip from Cotton Valley production as well as updip from recent Bossier productive discoveries. PYR owns 100% of the prospect and controls in excess of 1,500 gross acres of leasehold. Bayou Duralde Project, located in Evangeline Parish, LA, is an exploration program to identify and drill potential gas reservoirs in Yegua/Cockfield channel complexes. PYR owns a 25% working interest in the project and controls, along with its partner, in excess of 3,000 net acres of leasehold. PYR will participate with a 15% cost bearing interest and farm-out the remainder of its working interest. It is anticipated that the initial test well at Bayou Duralde will begin drilling operations in early May 2005, contingent upon contracting an available drilling rig. In the Canadian River Project, located in Eastern Oklahoma, the Orbison #3-11, a Cromwell development well operated by Questar, started drilling in mid-March. PYR has a 28.98% WI in the well. Hansford Project, located in the Texas panhandle, is a development project at the southern end of the Houghton Embayment. Main producing horizons within the Hansford area include the upper and lower Morrow as well as the Chester. Purchased originally as part of the Venus Exploration acquisition, the Company has recently purchased additional working interest in two wells and associated undeveloped acreage at Hansford. Approximately 42% working interest in the Lackey #152-1 well and acreage, as well as 15% working interest in the Archer Trust well and acreage, were purchased for approximately $440,000. The Company believes that additional development drilling opportunities targeting gas are available on the un-developed acreage that was purchased at Hansford. The Company has submitted a drilling AFE, to partners, to drill a development well offsetting the Lackey #152-1. It is anticipated that this well will be drilled during the summer of 2005 based on rig availability. SOUTHEAST ALBERTA SHALLOW GAS REDEVELOPMENT PROJECT: We have entered into two joint ventures, the Atlas Joint Venture and the Blue River Joint Venture, to redevelop shallow gas reserves in southeastern Alberta, Canada. Southeastern Alberta has been the site of significant shallow gas development drilling and production over the last two decades. We have undertaken geologic and engineering studies of the region, and believe that many wellbores in the region were prematurely suspended and/or abandoned due to water coning and production. These premature well abandonments suggest the possibility that significant additional reserves may remain in a number of shallow gas reservoirs in local areas within the Southeastern Alberta. We own a 5% working interest in the Atlas Joint Venture, which has identified multiple potential re-entry and redevelopment opportunities for which the Joint Venture intends to acquire the right to participate. The first well has been re-entered, re-perforated, and completed in the upper Bow Island sand. The well is currently producing into a sales line during long term testing. An offset wellbore is currently being permitted for re-entry based on results from the initial well. A number of other prospects are being leased and permitted at this time. We also own a 25% working interest in the Blue River Joint Venture, which intends to operate in different areas of southeastern Alberta. Initial investigation indicates multiple wells that exhibit an appropriate production type decline curve, potential disposal interval, and gas reservoir. We are currently undertaking detailed geologic and production analysis to refine certain areas, for which the Joint Venture will undertake to acquire and develop prospects for recompletion or drilling. 15 SAN JOAQUIN BASIN, CALIFORNIA 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. Despite repeated attempts to facilitate drilling interest at Wedge during 2003, no industry interest was generated sufficient to put together a drilling partnership during the year. As a result, PYR re-evaluated its acreage position at Wedge and made the decision to consolidate the leasehold by abandoning non-core prospect acreage in the project area. We currently control approximately 3,500 gross and net acres here. Our approach is to sell down our working interest to industry partners, 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. During 2003, we re-evaluated our acreage position at Bulldog and consolidated the leasehold by releasing approximately 3,200 non-core acres in the project area. We currently control approximately 11,900 gross and 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. Blizzard Prospect. This project is a 3D seismic derived exploration and exploitation program offsetting the Rio Viejo field at the south end of the San Joaquin Basin. A linear sand body, stratigraphically higher than any of the productive Rio Viejo sands, has been identified, north of the field, on the seismic data and represents an exploration opportunity for new reserves. Additionally, analysis of the seismic data over the field suggests that up to two additional undrilled field exploitation locations may exist. PYR owns 100% of the prospect and controls approximately 2,500 net and gross acres. CASH FLOW The six months ended February 28, 2005 ("2005") compared with the six months ended February 29, 2004 ("2004"). CASH FLOWS FROM OPERATING ACTIVITIES Net cash provided (used) by operating activities was $1,435 and ($697,704) for the six months ended February 28, 2005 and February 29, 2004, respectively. A discussion of these and other items are presented below. Net income (loss). See discussion of net income (loss) in "Results of Operations" section below. Depreciation and amortization. Depreciation and amortization expense was $205,083 in 2005, compared to $81,924 in 2004. The 2005 expense includes $199,683 of depletion of oil and gas properties. There was no depletion expense from oil and gas properties in 2004, due to an impairment taken against our entire amortizable full cost pool at August 31, 2003, and accordingly, there were no costs to amortize; however, included in depreciation expense reported for 2004, is $75,642 of depreciation of Asset Retirement Obligation assets. Accrued interest converted into debt. For the six months ended 2005, accrued interest converted into debt was $166,611 compared to $158,577 for the six months ended 2004. Both amounts reflect interest accrued on the $6,000,000 convertible notes issued May 24, 2002. Accretion of asset retirement obligation. During the six months ended 2005 and 2004, accretion of unamortized discount of the Asset Retirement Obligation liability was $12,605 and $42,304, respectively. The prior year is higher because the estimated lives of the East Lost Hills properties escalated the accretion rate, while the current year includes properties (acquired from Venus Exploration Inc. in May 2004) with longer estimated lives, and hence a lower accretion rate. 16 Stock options issued for director service. During the six months ended 2005 and 2004, stock options issued for director service were $15,248 and $0, respectively. The current year activity represents stock options issued to a former member of the Company's Board of Directors for services rendered. Accounts receivable. For the six months ended 2005 and 2004, accounts receivable increased $888,567 and $6,553, respectively. The increase in 2005 related principally to revenue receivables generated from the Sun Fee #1 well. See Note 3 to the financial statements regarding contingency on the Sun Fee #1 and further discussion below regarding the net profits interest liability associated with this well. Joint billings receivable. For the six months ended 2005 and 2004, joint billings receivable increased $109,373 and $0, respectively. The increase in 2005 relates principally to undeveloped leasehold costs the Company paid on behalf of its partners for certain projects. Billings to partners were made pursuant to participation agreements the Company has with its designated partners. Prepaid expenses and other. During the six months ended 2005, prepaid expenses increased $19,032, compared to an increase of $55,957 during the six months ended 2004. The increase in 2005 primarily reflects timing of payments. The increase in 2004 reflected higher Directors and Officers liability insurance premiums. Accounts payable. During the six months ended 2005, accounts payable and accruals increased $122,121, compared to a decrease of $72,184 during the six months 2004. The increase in the current year primarily resulted from the timing of payments. The decrease in 2004 reflected primarily decreased amounts due to the operator of the East Lost Hills wells. Net profits interest liability. During the six months ended 2005, the cumulative net profits interest liability increased $354,954, compared to $0 during the six months ended 2004. The net profits interest agreement with Venus Exploration Trust ("Trust") agreement arose out of the acquisition of properties from Venus Exploration Inc. ("Venus") in May 2004. The current year increase resulted from an accrued liability to the Trust for net profits accrued on the Sun Fee #1 well in the Nome Project. Accrued expenses. During the six months ended 2005 and 2004, accrued expenses increased $48,953 and decreased $33,748, respectively. The change in the current year primarily reflects an increase in accrued lease operating costs. The increase was partially offset by the conversion of accrued interest payable into convertible debt. The $6,000,000 4.99% convertible notes were issued on May 24, 2002. The decrease in 2004 relates to the conversion of accrued interest payable into convertible debt. CASH FLOWS FROM INVESTING ACTIVITIES Cash paid for oil and gas properties. During the six months ended 2005, we paid $1,659,181 for oil and gas properties, compared to $238,200, during the six months ended 2004. The increase in 2005 includes increased leasehold and lease rental activity, primarily in the Rocky Mountain and Gulf Coast regions, including the acquisition of additional working interest in the Hansford project for approximately $440,000, and costs associated with a saltwater disposal well conversion. The increase in 2004 relates to costs incurred on exploration projects in the California and the Rocky Mountain regions. Proceeds from sale of exploration options. During the year ended August 31, 2004, we signed an Exploration Option Agreement with Suncor Energy Natural Gas America, Inc. ("SENGAI"), covering our Rogers Pass exploration project in the Foothills of west-central Montana. On August 31, 2004, SENGAI exercised its option to drill an initial test well and paid us $750,000 in the form of a prospect fee, which was received in September 2004. We received $0 in proceeds from the sale of exploration options during the six months ended February 29, 2004. Proceeds from sale of oil and gas properties. We received $25,000 in prospect fees from a private company in connection with our Madison project, as well as approximately $23,000 for the sale of a partial interest in our Bayou Duralde project during the six months ended February 28, 2005. We received $0 in proceeds from the sale of oil and gas properties during the six months ended February 29, 2004. 17 CASH FLOWS FROM FINANCING ACTIVITIES Cash provided by financing activities was $0 for the six months ended 2005 and 2004, respectively. Results of Operations The quarter ended February 28, 2005 ("2005") compared with the quarter ended February 29, 2004 ("2004"). Operations during the quarter ended February 28, 2005 resulted in net income of $30,205 compared to a net loss of ($401,858) for the quarter ended February 29, 2004. Oil and Gas Revenues and Expenses. During the quarter ended February 28, 2005, we recorded $1,195,671 in total oil and gas revenues. Of this amount, we recorded $553,457 from the sale of 81,655 mcf of natural gas for an average price of $6.78 per mcf, and $642,214 from the sale of 14,369 bbls of hydrocarbon liquids for an average price of $44.69 per bbl. During the quarter ended February 29, 2004, we recorded $44,376 in total oil and gas revenues. Of this amount, we recorded $32,782 from the sale of 7,113 mcf of natural gas for an average price of $4.61 per mcf and $11,594 from the sale of 398 bbls of hydrocarbon liquids for an average price of $29.13 per barrel. 2005 revenues increased largely due to the acquisition of properties from Venus Exploration Inc. in May 2004 and subsequent drilling results, while 2004 revenues related wholly to the Company's interest in East Lost Hills in California. Lease operating expenses during the quarters ended 2005 and 2004, respectively, were $203,153 and $21,681. Accretion Expense. We recorded $6,307 and $21,152, respectively, for the quarters ended 2005 and 2004, of accretion of the unamortized discount of the Asset Retirement Obligation liability. The prior quarter is higher because the estimated lives of the East Lost Hills properties escalated the accretion rate, while the current quarter includes properties (acquired from Venus Exploration Inc. in May 2004) with longer estimated lives, and hence a lower accretion rate. Net Profits Interest Expense. The net profits interest agreement with Venus Exploration Trust ("Trust") agreement arose out of the acquisition of properties from Venus Exploration Inc. ("Venus") in May 2004. The agreement varies from 25% to 50% with respect to different Venus exploration and exploitation project areas, and decreases by one-half of its original amount after a total of $3,300,000 in net profits proceeds has been paid to the Trust. For the quarter ended February 28, 2005, we accrued net profits interest expense of $232,588 in connection with net profits realized for the Sun Fee #1 well for the quarter ended February 28, 2005. For the quarter ended February 29, 2004, there was no net profits interest expense recognized. Depreciation, Depletion and Amortization. We recorded $167,046 and $41,804, respectively, in depreciation, depletion and amortization expense for the quarters ended 2005 and 2004. Of these amounts, we recorded $164,861 and $0, respectively, in depreciation, depletion and amortization of oil and gas properties for the quarters ended 2005 and 2004, respectively. The 2005 increase was attributable to the properties acquired from Venus Exploration, Inc. in May 2004, which increased the amount of oil and gas production, and an increase in the amortizable oil and gas asset base due to increased future development costs. We recorded no depreciation, depletion and amortization expense from oil and gas properties for the quarter ended February 29, 2004, due to an impairment taken against our entire amortizable full cost pool at August 31, 2003, and accordingly, there were no costs to amortize; however, included in depreciation expense reported for 2004, is $37,821 of depreciation of Asset Retirement Obligation assets. We recorded $2,185 and $3,983 in depreciation expense associated with capitalized office furniture and equipment during the quarters ended 2005 and 2004, respectively. General and Administrative Expenses. General and administrative expenses during the quarters ended 2005 and 2004 were $497,669 and $285,442, respectively. The increase principally reflects an increase in salaries as a result of hiring additional personnel and costs incurred related to the implementation of a new computer system, both of which resulted from the acquisition of properties from Venus Exploration Inc. in May 2004. Interest Income. We recorded $24,833 and $5,041 in interest income for the quarters ended 2005 and 2004, respectively. The increase was due to interest on the funds received from the private placement of our common stock in May 2004. 18 Interest Expense. During the quarters ended 2005 and 2004, we recorded interest expense of $84,342 and $81,196, respectively. The interest expense for each year is associated with the May 24, 2002 sale of outstanding 4.99% convertible notes due on May 24, 2009. We have reflected the outstanding balance of these notes as Convertible Notes under Long Term Debt on our February 28, 2005 and August 31, 2004 consolidated balance sheets. The six months ended February 28, 2005 ("2005") compared with the six months ended February 29, 2004 ("2004"). Operations during the six months ended February 28, 2005 resulted in net income of $91,237 compared to a net loss of ($763,660) for the six months ended February 29, 2004. Oil and Gas Revenues and Expenses. During the six months ended February 28, 2005, we recorded $2,278,181 in total oil and gas revenues. Of this amount, we recorded $999,441 from the sale of 144,712 mcf of natural gas for an average price of $6.91 per mcf, and $1,278,740 from the sale of 28,347 bbls of hydrocarbon liquids for an average price of $45.11 per bbl. During the six months ended February 29, 2004, we recorded $84,394 in total oil and gas revenues. Of this amount, we recorded $63,500 from the sale of 14,600 mcf of natural gas for an average price of $4.35 per mcf and $20,894 from the sale of 799 bbls of hydrocarbon liquids for an average price of $26.15 per barrel. 2005 revenues increased largely due to the acquisition of properties from Venus Exploration Inc. in May 2004 and subsequent drilling results, while 2004 revenues related wholly to the Company's interest in East Lost Hills in California. Lease operating expenses during the six months ended 2005 and 2004, respectively, were $483,729 and $36,952. Accretion Expense. We recorded $12,607 and $42,604, respectively, for the six months ended 2005 and 2004, of accretion of the unamortized discount of the Asset Retirement Obligation liability. The six months ended 2004 is higher because the estimated lives of the East Lost Hills properties escalated the accretion rate, while the six months ended 2005 includes properties (acquired from Venus Exploration Inc. in May 2004) with longer estimated lives, and hence a lower accretion rate. Net Profits Interest Expense. The net profits interest agreement with Venus Exploration Trust ("Trust") agreement arose out of the acquisition of properties from Venus Exploration Inc. ("Venus") in May 2004. The net profits interest agreement varies from 25% to 50% with respect to different Venus exploration and exploitation project areas, and decreases by one-half of its original amount after a total of $3,300,000 in net profits proceeds has been paid to the Trust. For the six months ended February 28, 2005, we accrued net profits interest expense of $354,954, in connection with net profits realized for the Sun Fee #1 well for the six months ended February 28, 2005. For the six months ended February 29, 2004, there was no net profits interest expense recognized. Depreciation Depletion and Amortization. We recorded $205,083 and $81,924, respectively, in depreciation, depletion and amortization expense for the six months ended 2005 and 2004. Of these amounts, we recorded $199,683 and $0, respectively, in depreciation, depletion and amortization expense from oil and gas properties for the six months ended 2005 and 2004. We recorded no depreciation, depletion and amortization expense from oil and gas properties for the six months ended 2004, due to an impairment taken against our entire amortizable full cost pool at August 31, 2003, and accordingly, there were no costs to amortize; however, included in depreciation expense reported for the six months ended 2004, is $75,642 of depreciation of Asset Retirement Obligation assets. The 2005 increase was attributable to the properties acquired from Venus Exploration, Inc. in May 2004, which increased the amount of oil and gas production, and an increase in the amortizable oil and gas asset base due to increased future development costs. We recorded $5,400 and $6,282 in depreciation expense associated with capitalized office furniture and equipment during the six months ended 2005 and 2004, respectively. General and Administrative Expenses. General and administrative expenses during the quarters ended February 28, 2005 and 2004 were $1,009,056 and $536,932, respectively. The increase principally reflects an increase in salaries as a result of hiring additional personnel and an increase in audit and legal fees, both of which resulted from the acquisition of properties from Venus Exploration, Inc. in May 2004. Interest Income. We recorded $45,132 and $10,608 in interest income for the six months ended 2005 and 2004, respectively. The increase was due to interest on the funds received from the private placement of our common stock in May 2004. 19 Interest Expense. During the six months ended 2005 and 2004, we recorded interest expense of $167,675 and $160,550, respectively. The interest expense for each year is associated with the sale of outstanding 4.99% convertible notes due on May 24, 2009. The Company elected to add $166,611 and $158,577 of accrued interest to the balance of the debt for the six months ended 2005 and 2004, respectively. We have reflected the outstanding balance of these notes as Convertible Notes under Long Term Debt on our February 28, 2005 and August 31, 2004 consolidated balance sheets. 20 Critical Accounting Policies And Estimates We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of our Financial Statements. Reserve Estimates: Our estimates of oil and natural gas reserves, by necessity, are projections based on geological and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected from there may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of the oil and gas properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. Many factors will affect actual net cash flows, including the following: the amount and timing of actual production; supply and demand for natural gas; curtailments or increases in consumption by natural gas purchasers; and changes in governmental regulations or taxation. Property, Equipment and Depreciation: We follow the full cost method to account for our oil and gas exploration and development activities. Under the full cost method, all costs incurred which are directly related to oil and gas exploration and development are capitalized and subjected to depreciation and depletion. Depletable costs also include estimates of future development costs of proved reserves. Costs related to undeveloped oil and gas properties may be excluded from depletable costs until those properties are evaluated as either proved or unproved. The net capitalized costs are subject to a ceiling limitation based on the estimated present value of discounted future net cash flows from proved reserves. As a result, we are required to estimate our proved reserves at the end of each quarter, which is subject to the uncertainties described in the previous section. Gains or losses upon disposition of oil and gas properties are treated as adjustments to capitalized costs, unless the disposition represents a significant portion of the Company's proved reserves. Revenue Recognition: The Company recognizes oil and gas revenues from its interests in producing wells as oil 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. Asset Retirement Obligations: In 2001, the 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. This statement requires companies to record the present value of obligations associated with the retirement of tangible long-lived assets in the period in which it is incurred. The liability is capitalized as part of the related long-lived asset's carrying amount. Over time, accretion of the liability is recognized as an operating expense and the capitalized cost is depreciated over the expected useful life of the related asset. The Company's asset retirement obligations relate primarily to the plugging, dismantlement, removal, site reclamation and similar activities of its oil and gas properties. Prior to adoption of this statement, such obligations were accrued ratably over the productive lives of the assets through depreciation, depletion and amortization of oil and gas properties without recording a separate liability for such amounts. 21 Recent Accounting Pronouncements In December 2004, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 123(R), "Share-Based Payment". This statement requires all entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. SFAS No. 123(R) is effective the first reporting period beginning after December 15, 2005. Due to the recent adoption of SFAS No. 123(R), the Company has not determined the future impact on its financial statements; however, it will result in additional future financial reporting expense to the Company when implemented. ITEM 3. CONTROLS AND PROCEDURES As of the end of the period covered by this report, we conducted an evaluation under the supervision and with the participation of the principal executive officer and principal financial officer, of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act")). Based on this evaluation, the principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective to ensure that the information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. There was no change in our internal controls over financial reporting during our most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 22 PART II. OTHER INFORMATION Item 1. Legal Proceedings Not Applicable Item 2. Unregistered Sales of Equity Securities and Use of Proceeds None Item 3. Defaults Upon Senior Securities None Item 4. Submission of Matters to a Vote of Security Holders None Item 5. Other Information None Item 6. Exhibits Exhibit Index -------------------------------------------------------------------------------- Number Description -------------------------------------------------------------------------------- 31 Rule 13a-14(a) Certifications of Chief Executive Officer and Principal Financial Officer 32 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 23 SIGNATURES In accordance with the requirements of the Exchange Act, the Registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. Signatures Title Date ---------- ----- ---- /s/ D. Scott Singdahlsen President, Chief Executive Officer April 14, 2005 ------------------------ and Principal Financial Officer D. Scott Singdahlsen 24