-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, FFPcy3jrCCbCTraAF1lRsOfJtl5/hL32EijfGX/+K6SOdXHCi+CQLuzePqXvw0ew /o6ZYiGiyDt7lS+qvUBYkw== 0001050502-04-000406.txt : 20040715 0001050502-04-000406.hdr.sgml : 20040715 20040715165627 ACCESSION NUMBER: 0001050502-04-000406 CONFORMED SUBMISSION TYPE: 10QSB PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20040531 FILED AS OF DATE: 20040715 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PYR ENERGY CORP CENTRAL INDEX KEY: 0001016289 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 954580642 STATE OF INCORPORATION: DE FISCAL YEAR END: 0831 FILING VALUES: FORM TYPE: 10QSB SEC ACT: 1934 Act SEC FILE NUMBER: 001-15511 FILM NUMBER: 04916282 BUSINESS ADDRESS: STREET 1: 1675 BROADWAY STREET 2: STE 2450 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3038253748 MAIL ADDRESS: STREET 1: 1675 BROADWAY STREET 2: SUITE 2450 CITY: DENVER STATE: CO ZIP: 80202 FORMER COMPANY: FORMER CONFORMED NAME: MAR VENTURES INC DATE OF NAME CHANGE: 19960606 10QSB 1 pyr504.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 May 31, 2004 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 of (I.R.S. Employer Identification No.) 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 May 31, 2004 is as follows: $.001 Par Value Common Stock 28,243,023 PART I. FINANCIAL INFORMATION Item 1. Financial Statements........................................... 3 Balance Sheets - May 31, 2004 (Unaudited) and August 31, 2003........................................................... 3 Statements of Operations - Three Months and Nine Months Ended May 31, 2004 and May 31, 2003 (Unaudited)................ 4 Statements of Cash Flows - Nine Months Ended May 31, 2004 and May 31, 2003 (Unaudited)................................... 5 Notes to Financial Statements.................................. 6 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations............................ 10 Item 3. Controls and Procedures......................................... 20 PART II. OTHER INFORMATION Item 1. Legal Proceedings.............................................. 21 Item 2. Changes in Securities and Use of Proceeds; Recent Sales of Unregistered Securities........................................ 21 Item 3. Defaults Upon Senior Securities................................ 21 Item 4. Submission of Matters to a Vote of Security Holders............ 21 Item 5. Other Information.............................................. 21 Item 6. Exhibits and Reports on Form 8-K............................... 21 Signatures.............................................................. 22 2
PART I ITEM 1. FINANCIAL STATEMENTS PYR ENERGY CORPORATION BALANCE SHEETS ASSETS May 31, August 31, 2004 2003 (Unaudited) CURRENT ASSETS Cash $ 3,956,819 $ 3,657,938 Oil and gas receivables 316,265 -- Deposits, prepaid expenses and other receivables 110,463 46,559 ------------ ------------ Total Current Assets 4,383,547 3,704,497 ------------ ------------ PROPERTY AND EQUIPMENT, at cost Furniture and equipment, net 22,890 29,313 Oil and gas properties under full cost, net 8,572,006 5,287,837 ------------ ------------ 8,594,896 5,317,150 ------------ ------------ OTHER ASSETS Deferred financing costs and other assets 75,867 68,257 ------------ ------------ 75,867 68,257 ------------ ------------ $ 13,054,310 $ 9,089,904 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities $ 427,987 $ 309,796 Asset retirement obligation 793,749 727,231 ------------ ------------ Total Current Liabilities 1,221,736 1,037,027 ------------ ------------ LONG TERM LIABILITIES Convertible Notes 6,623,351 6,303,975 Asset retirement obligation 292,380 118,862 ------------ ------------ Total Long Term Liabilities 6,915,731 6,422,837 STOCKHOLDERS' EQUITY Common stock, $.001 par value; authorized 75,000,000 shares Issued and outstanding - 28,243,023 at 5/31/04 and 23,701,357 shares at 8/31/03 28,243 23,701 Capital in excess of par value 39,845,468 35,407,657 Accumulated deficit (34,956,868) (33,801,318) ------------ ------------ 4,916,843 1,630,040 ------------ ------------ $ 13,054,310 $ 9,089,904 ============ ============ 3 PYR ENERGY CORPORATION STATEMENTS OF OPERATIONS (UNAUDITED) Three Three Nine Nine Months Months Months Months Ended Ended Ended Ended 5/31/2004 5/31/2003 5/31/2004 5/31/2003 REVENUES Oil and gas revenues $ 184,551 $ 43,041 268,945 $ 137,079 ------------ ------------ ------------ ------------ 184,551 43,041 268,945 137,079 ------------ ------------ ------------ ------------ OPERATING EXPENSES Lease operating expenses 77,958 18,349 114,910 64,694 Impairment, dry hole, and abandonments -- -- -- 1,178,267 Depreciation and amortization 71,813 3,020 196,041 8,892 General and administrative 350,377 339,576 887,309 1,010,119 ------------ ------------ ------------ ------------ 500,148 360,945 1,198,260 2,261,972 LOSS FROM OPERATIONS (315,597) (317,904) (929,315) (2,124,893) OTHER INCOME (EXPENSE) Interest income 4,921 11,044 15,529 45,879 Other income 1,020 -- 1,020 -- Interest (expense) (82,234) (78,316) (242,784) (230,371) ------------ ------------ ------------ ------------ (76,293) (67,272) (226,235) (184,492) ------------ ------------ ------------ ------------ NET LOSS $ (391,890) $ (385,176) $ (1,155,550) $ (2,309,385) ============ ============ ============ ============ NET LOSS PER COMMON SHARE -BASIC AND DILUTED (0.02) (0.02) (0.05) (0.10) ============ ============ ============ ============ WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 24,930,795 23,701,357 24,114,161 23,701,357 ============ ============ ============ ============ 4
PYR ENERGY CORPORATION STATEMENTS OF CASH FLOWS (UNAUDITED) Nine Months Nine Months Ended Ended 5/31/2004 5/31/2003 CASH FLOWS FROM OPERATING ACTIVITIES Net loss $(1,155,550) $(2,309,385) Adjustments to reconcile net loss to net cash used by operating activities Depreciation and amortization 196,041 8,892 Impairment, dry hole and abandonments -- 1,178,267 Amortization of financing costs 2,390 2,390 Interest expense converted into debt 319,376 221,948 Changes in assets and liabilities (Increase) in accounts receivable (328,787) -- (Increase) decrease in prepaids (51,382) (23,976) Increase in accounts payable, accruals 88,891 311,024 Other (10,000) (40,000) ----------- ----------- Net cash used by operating activities (939,021) (650,840) ----------- ----------- CASH FLOWS FROM INVESTING ACTIVITIES Cash paid for furniture and equipment (3,161) (4,688) Cash paid for oil and gas properties (3,887,304) (1,067,737) Proceeds from sale of exploration options 500,000 -- Proceeds from sale of oil and gas properties 186,014 -- ----------- ----------- Net cash used in investing activities (3,204,451) (1,072,425) ----------- ----------- CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from sale of common stock 4,430,269 -- Proceeds from exercise of options 12,084 -- ----------- ----------- Net cash provided by financing activities 4,442,353 -- ----------- ----------- NET (DECREASE) INCREASE IN CASH 298,881 (1,723,265) CASH, BEGINNING OF PERIODS 3,657,938 6,516,086 ----------- ----------- CASH, END OF PERIODS $ 3,956,819 $ 4,792,821 =========== =========== NON-CASH TRANSACTIONS Increase in asset retirement obligation $ 169,874 $ -- =========== =========== 5 PYR ENERGY CORPORATION Notes to Financial Statements May 31, 2004 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 periods ended May 31, 2004, 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, 2003. PYR Energy Corporation, formerly known as Mar Ventures Inc. ("Mar"), was incorporated under the laws of the State of Delaware on March 27, 1996. Mar was a public company with 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 Statement of Financial Accounting Standards (SFAS) No. 7. PYR LLC, an independent oil and gas exploration company, was engaged in the acquisition of undeveloped oil and gas interests for exploration and exploitation in the Rocky Mountain region and California. As of August 6, 1997, PYR LLC had acquired only non-producing leases and acreage, and no exploration had commenced on the properties. Upon completion of the acquisition of PYR LLC by Mar, PYR LLC ceased to exist as a separate entity. Mar remained as the surviving legal entity and, effective November 12, 1997, Mar changed its name to PYR Energy Corporation. Effective July 2, 2001, we re-incorporated in Maryland through our merger into our wholly owned subsidiary, PYR Energy Corporation, a Maryland corporation. On February 18, 2004, PYR Cumberland LLC, PYR Mallard LLC, and PYR Pintail LLC were formed as wholly owned subsidiaries of PYR Energy Corporation. The purpose of these entities is to own and develop certain assets related to designated individual exploration projects. As of May 31, 2004, PYR Cumberland LLC, PYR Mallard LLC, and PYR Pintail LLC had no business activity. Prior to the third quarter ended May 31, 2004, we were a development stage company. As discussed in Note 3, we acquired interests in certain producing properties from Venus Exploration, Inc. As a result of this acquisition, during the third quarter ended May 31, 2004, we began receiving revenues from our planned operations, and therefore we are no longer considered to be a development stage company. NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES USE OF ESTIMATES - The preparation of financial statements in conformity with generally accepted accounting principles requires us 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. CASH EQUIVALENTS - For purposes of reporting cash flows, we consider as cash equivalents all highly liquid investments with a maturity of three months or less at the time of purchase. At May 31, 2004, there were no cash equivalents. 6 PROPERTY AND EQUIPMENT - Furniture and equipment is recorded at cost. Depreciation 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. OIL AND GAS PROPERTIES - We follow 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 on a country-by-country basis. 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. We lease non-producing acreage for our 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. In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 141, "Business Combinations," which requires the purchase method of accounting for business combinations initiated after June 30, 2001, and eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The oil and gas industry is currently discussing the appropriate balance sheet classification of oil and gas mineral rights held by lease or contract. We classify these assets as a component of oil and gas properties in accordance with the full cost method of accounting for oil and gas activities and common industry practice. There is also a view that these mineral rights are intangible assets as defined in SFAS No. 141, "Business Combinations," and, therefore, should be classified separately on the balance sheet as intangible assets. We did not change or reclassify contractual mineral rights included in oil and gas properties on the balance sheet upon adoption of SFAS No. 141. We believe our current accounting of such mineral rights, as part of oil and gas properties, is appropriate under the full cost method of accounting. However, if the accounting for mineral rights held by lease or contract is ultimately changed so that costs associated with mineral rights not held under fee title and pursuant to the guidelines of SFAS No. 141 are required to be classified as long-term intangible assets, then the reclassified amount as of May 31, 2004, would be approximately $7,140,000, and the reclassified amount as of August 31, 2003 (the end of our last completed fiscal year), would be approximately $4,366,000. Management does not believe that the ultimate outcome of this issue will have a significant impact on our cash flows, results of operations or financial condition. DEPLETION, DEPRECIATION AND AMORTIZATION - Depletion of exploration and development costs and depreciation of production equipment is provided using the unit-of-production method based upon estimated proven oil and gas reserves. The costs of significant unevaluated or otherwise impaired properties are excluded from costs subject to depletion. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. In conjunction with the May 2004 acquisition of oil and gas properties from Venus Exploration, Inc. ("Venus"), a reserve report was prepared by an independent petroleum engineering firm as of August 31, 2003. This report was used to calculate depreciation, depletion and amortization charges of the recently acquired properties at May 31, 2004. Prior to the property acquisition from Venus, we had no proved reserves. 7 CEILING TEST - 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. A reserve is provided for estimated future costs of site restoration, dismantlement and abandonment activities, net of residual salvage value, as a component of impairment, dry holes and abandonment expense. REVENUE RECOGNITION - We recognize oil and gas revenues from our interests in producing wells as oil and gas is produced and sold from these wells. We have no gas balancing arrangements in place. Oil and gas sold is not significantly different from our product entitlement. INCOME TAXES - We have adopted the provisions of SFAS No. 109, "Accounting for Income Taxes." SFAS No. 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. ASSET RETIREMENT OBLIGATIONS - In 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 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. Our asset retirement obligations relate primarily to the plugging, dismantlement, removal, site reclamation and similar activities of our oil and gas properties. Prior to adoption of this statement, such obligations were accrued ratably over the productive lives of the assets through our depreciation, depletion and amortization for oil and gas properties without recording a separate liability for such amounts. The transition adjustment related to adopting SFAS No. 143 on September 1, 2002, was recognized as a cumulative effect of a change in accounting principle. The cumulative effect on net income of adopting SFAS No. 143 was a net unfavorable effect of $341,175. At the time of adoption, total assets increased $629,816, and total liabilities increased $769,175. The amounts recognized upon adoption are based upon numerous estimates and assumptions, including future retirement costs, future recoverable quantities of oil and gas, future inflation rates and the credit-adjusted risk-free interest rate. During the quarter ended May 31, 2004, an additional asset retirement obligation of $169,874 was recognized in conjunction with the acquisition of properties from Venus. As of May 31, 2004, the asset retirement obligation net asset balance, after depreciation and impairment, was $244,125, and the total asset retirement obligation liability, after accretion of unamortized discount, was $1,086,129. STOCK OPTION COMPENSATION - We have elected to follow Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees," and related interpretations in accounting for its stock options and grants to employees and directors since the alternative fair market value accounting provided for under SFAS No. 123 requires use of grant valuation models that were not developed for use in valuing employee stock options and grants. Under APB Opinion No. 25, if the exercise price of our stock grants and options equal the fair value of the underlying stock on the date of grant, no compensation expense is recognized. 8 If compensation cost for our stock-based compensation plans had been determined based on the fair value at the grant dates for awards under those plans consistent with the method of SFAS No. 123, then our net loss per share would have been adjusted to the pro forma amounts indicated below:
Three Months Three Months Nine Months Nine Months Ended Ended Ended Ended 5/31/2004 5/31/2003 5/31/2004 5/31/2003 Net loss as reported $ (391,890) $ (385,176) $ (1,155,550) $ (2,309,385) Deduct: stock-based compensation Costs under SFAS No. 123 (184,070) -- (479,134) -- ------------ ------------ ------------ ------------ Pro forma net loss (575,960) (385,176) (1,634,684) (2,309,385) ============ ============ ============ ============ Pro forma basic and diluted net income per share: Pro forma shares used in the 24,930,795 23,701,357 24,114,161 23,701,357 calculation of pro forma net income per common share basic and diluted Reported net income per common share - basic and diluted $ (0.02) $ (0.02) $ (0.05) $ (0.10) Pro forma net income per common share - basic and diluted $ (0.02) $ (0.02) $ (0.06) $ (0.10)
Pro forma information regarding net income is required by SFAS No. 123. Options granted were estimated using the Black-Scholes valuation model. The following weighted average assumptions were used for the three and nine months ended May 31, 2004. Volatility 87-125% Expected life of options (in years) 5-7 Dividend Yield 0.00% Risk free interest rate 3.1-3.85% NOTE 2 - COMMON STOCK In early May 2004, we received subscriptions for an aggregate of $8,175,000 in gross proceeds from a private placement of our common stock. The private placement (the "Placement") consisted of the sale of 7.5 million shares of common stock, priced at $1.09 per share, to a group of twelve institutional and accredited individual investors pursuant to exemptions from registration under Sections 3(b) and 4(2) of the Securities Exchange Act of 1934, as amended. The first tranche of the Placement, consisting of 4.5 million shares and $4,905,000 in gross proceeds, was received and accepted in early May 2004. The second tranche of the Placement, consisting of 3.0 million shares and $3,270,000 in gross proceeds, was approved by our stockholders at our Annual Meeting of Stockholders on June 11, 2004. We received the funds from the second tranche in late June 2004. Proceeds from the Placement will be used for general corporate purposes, partial funding of the acquisition of assets from Venus Exploration, Inc. (as discussed in Note 3 below), and project development and drilling costs associated with our exploration and exploitation portfolio. In early July 2004, we filed a registration statement with the Securities and Exchange Commission to register any resales of the shares purchased in the Placement under the Securities Act of 1933, as amended. 9 NOTE 3 - ACQUISITION OF ASSETS FROM VENUS EXPLORATION, INC. In May 2004, we acquired interests in certain producing properties for approximately $3,230,000 (excluding costs associated with the acquisition) from Venus Exploration, Inc. ("Venus"). Venus is 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. The purchase also provides for 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. NOTE 4 - CONVERTIBLE NOTES 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 the rate of $1.30 per share. The interest can be paid in cash or added to the principal amount at our discretion. The notes were issued to three investment funds pursuant to exemptions from registration under Sections 3(b) and/or 4(2) of the Securities Act of 1933, as amended. Between May 24, 2002 and May 31, 2004, we elected to add all semi-annual interest payments, totaling $623,351, to the principal balance (rather than pay the interest in cash on a current basis) so that at May 31, 2004, the aggregate balance of these notes, reflected as Convertible Notes under Long-Term Debt, was $6,623,351. ITEM 2. 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 1. Financial Statements" of this Form 10-QSB. Overview We are an independent oil and gas exploration and production 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, sharing both risk and rewards with other participants. We do not currently operate any projects in which we own a working interest, although we may operate some projects in the future. We do not have the financial ability to commence exploratory drilling operations without third party participation. We have pursued, and will continue to pursue, exploration opportunities in regions in which 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. 10 Liquidity and Capital Resources At May 31, 2004, we had approximately $3,161,811 in working capital. In early May 2004, we received subscriptions for an aggregate of $8,175,000 in gross proceeds from a private placement of our common stock. The private placement (the "Placement") consisted of the sale of 7.5 million shares of common stock, priced at $1.09 per share, to a group of twelve institutional and accredited individual investors pursuant to exemptions from registration under Sections 3(b) and 4(2) of the Securities Exchange Act of 1934, as amended. The first tranche of the Placement, consisting of 4.5 million shares and $4,905,000 in gross proceeds, was received and accepted in early May 2004. The second tranche of the Placement, consisting of 3.0 million shares and $3,270,000 in gross proceeds, was approved by our stockholders at our Annual Meeting of Stockholders on June 11, 2004. We received the funds from the second tranche in late June 2004. Proceeds from the Placement will be used for general corporate purposes, partial funding of the acquisition of assets from Venus Exploration, Inc., and project development and drilling costs associated with our exploration and exploitation portfolio. In early July 2004, we filed a registration statement with the Securities and Exchange Commission to register any resales of the shares purchased in the Placement under the Securities Act of 1933, as amended. In May 2004, we acquired interests in certain producing properties for approximately $3,230,000 (excluding costs associated with the acquisition) from Venus. Venus is 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 the Placement. The purchase also provides for 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. During the quarter ended May 31, 2004, capitalized costs for oil and gas properties increased by approximately $3,400,000. The increase is due largely to the acquisition of assets from Venus, and also includes net costs incurred for drilling and completion, geological and geophysical costs, delay rentals, other related direct costs with respect to our exploration and development prospects, as well as an increase of approximately $170,000 in asset retirement obligations related to the acquisition from Venus, less depreciation of asset retirement obligation assets of approximately $115,000. There was no charge to impairment during the quarter, based upon management's determination that no further impairment of undeveloped properties had occurred since the end of the prior fiscal year. It is anticipated that the continuation and future development of our business will require additional, and possibly substantial, capital expenditures. Our capital expenditure budget depends 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. For the fiscal year ending August 31, 2004, we anticipate spending a minimum of approximately $900,000 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. 11 Capital Expenditures During the quarter ended May 31, 2004, we incurred approximately $3,400,000 of capital costs, largely due to the acquisition of assets from Venus, as well as our continuing exploration projects, acreage lease obligations and associated geological and geophysical costs. Approximately $24,000 in capital costs were incurred on our East Lost Hills Project during the quarter, resulting from inventory audit adjustments. Revenues from oil and gas production during the three months ended May 31, 2004 were $184,551. We currently anticipate that we will participate in the drilling of up to four exploration wells during our fiscal year ending August 31, 2004, 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. The following table summarizes our obligations and commitments to make future payments under our convertible notes payable and office and equipment leases for the periods specified as of May 31, 2004:
Payments Due By Period Contractual Year Ending Fiscal Years Fiscal Years Fiscal Years Obligations Total August 31, 2004 2005-2007 2008-2009 2010 and After - ----------------- ---------- --------------- ---------- ---------- -------------- Convertible Notes $8,474,313 $ -- $ -- $8,474,313 $ -- Office Lease, Denver, CO 236,045 25,827 186,861 23,357 -- Office Lease, San Antonio, TX 108,000 12,000 96,000 -- -- Copier Lease 3,108 777 2,331 -- -- Subscriber Agreement to Computer Service 14,700 1,225 13,475 -- -- ---------- ---------- ---------- ---------- ------- Total Contractual Cash Obligations $8,836,166 $ 39,820 $ 298,667 $8,497,670 $ --
The above schedule assumes convertible note interest payments will be added to the principal amount (which is at our discretion), and the entire balance will be paid in full on maturity of May 24, 2009, and there will be no conversion of debt to common stock. In addition to the above obligations, if we elect to continue holding all our existing leases on a delayed rental basis, we would have to pay approximately $560,000 during the year ending August 31, 2004. We consider on a quarterly basis whether to continue holding all or part of each acreage block by making delay rental payments on existing leases. 12 Summary of Exploration Projects The following is a summary of the current status of our exploration projects: Wyoming Overthrust Prospects: In December 2003, we entered into an agreement with two private oil and gas exploration companies covering two of our exploration projects in the Overthrust of southwestern Wyoming. The first agreement relates to the Mallard Prospect, which is located adjacent to the south end of the Whitney Canyon - Carter Creek field. The agreement requires the participants to drill the initial test well at the Mallard Prospect to earn part of our acreage position within our Greater Duck area of mutual interest. We currently control 4,160 net leasehold acres within the Greater Duck AMI. The partners will pay us approximately $500,000 in prospect fees and pro-rata development costs. The construction and preparation of the drilling location is completed, and it is anticipated that the Mallard test well will begin drilling in mid to late July. We will participate with a 5% working interest in the drilling of Mallard, and will be carried to casing point 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. The second agreement relates to the Cumberland Prospect. The Cumberland prospect is on trend with these productive features, and also is located in the Overthrust of Southwestern Wyoming, approximately 5 miles northeast of the Ryckman Creek field. It is currently anticipated that the test well for the Cumberland Prospect will be drilled in mid to late-calendar 2004, contingent on rig availability. The partners paid us $186,016 in prospect fees and pro-rata development costs. An additional $86,004 will be paid upon the well reaching casing point. We will participate with a 10% working interest in the drilling, and will be carried for an additional 22.5% working interest to casing point in the initial test well. After casing point, we will have a 32.5% working interest in the initial well and all subsequent wells in the Prospect. The anticipated total depth of the well is estimated to be 10,600 feet. We control 6,233 net leasehold acres within the Cumberland area of mutual interest. 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. It is anticipated that a well may be drilled at Ryckman Creek late in 2004, and based on our analysis, we may decide to sell down part of our 100% working interest in the project. Montana Foothills Project: In March 2004, we signed an Exploration Option Agreement with a subsidiary of Suncor Energy, Incorporated, covering our Rogers Pass exploration project in the Foothills of west-central Montana. We currently control approximately 241,800 gross and 226,300 net leasehold acres in the Rogers Pass project. Within the Rogers Pass acreage block, we have undertaken extensive seismic analysis and geological study, resulting in the identification of multiple untested, prospective structures. Historically, only one well has been drilled within the acreage block: the Unocal #1-B30, drilled in 1989 to a depth of 17,817 feet, which was plugged and abandoned after testing. 13 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. Before the end of the technical evaluation period, SENGAI will make an election, by late-July 2004 either to proceed to drill the first test well or to drop the project. Should SENGAI elect to drill the first test well within the project area, a prospect fee of $750,000 will be paid to us, and the well will be spud prior to December 31, 2004. 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. Interests Acquired from Venus Exploration, Inc.: As part of our acquisition of oil and gas interests from Venus Exploration, Inc. ("Venus"), Venus retained 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 acquired Venus acreage, 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. Oil and gas interests acquired from Venus include producing oil and gas properties, exploitation drilling projects, and exploration acreage. Producing assets include both operated and non-operated properties. Current net production from the acquired properties is approximately 980 Mcfe per day, with estimated `total proved' reserves of 4.784 Bcfe. Proved developed producing reserves are estimated to be 2.025 Bcfe, while the proved developed non-producing reserves are estimated at 1.761 Bcfe. Proved undeveloped reserves are estimated to be 0.998 Bcfe. Present value, discounted at 10%, is $6,941,000 for total proved reserves and $3,089,000 for proved developed producing reserves. In Texas, we have interests in three projects recently acquired from Venus. The test wells in these three projects are currently at total depth, and are being production tested, and evaluated. The three wells currently engaged in operations are subject to a 50% net profits interest payable to the Venus Exploration Trust. The Tortuga Grande prospect, located in east Texas, is a re-entry of an existing well, drilled on a large turtle structure, 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 of the re-entry in which we are currently involved indicates that the well contains approximately 322 feet of potential pay greater than 8% porosity. The middle Cotton Valley Sand section has been fracture stimulated, and the well is currently flowing back load fluid. Should the fracture treatment prove successful, we believe that multiple additional development locations would be available to us. We have a 10% carry through the tanks with an additional 10% working interest, after well payout, on the initial test 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 acres within the project. The 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, and we own a 1.5% overriding royalty interest with an additional 8.33% working interest, after project payout, in the project. The well is currently being evaluated and tested in the Yegua section. We and our partners control approximately 4,200 acres of gross leasehold acres in the project. We also own additional acreage in the Cotton Creek prospect, located adjacent to the Nome project. 14 The 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 Bcp/d and 2.7 MMcf/d with no water. This well was subsequently junked and abandoned in the Doyle interval and never produced from the zone. The Sanders 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 being production tested and evaluated in the Yegua section. We own a 0.5% overriding royalty interest that converts to a 12.5% working interest in the project after payout of the initial test well. 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. Numerous sandstone reservoirs (including Milk River, Belly River, Medicine Hat, Bow Island, Glauconite, and Viking), generally shallower than 4,000 feet, have produced in excess of 10 tcf of natural gas. 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 that significant additional reserves may remain in a number of shallow gas reservoirs in local areas within the Southeastern Alberta. Reworking of existing prematurely abandoned wellbores can potentially result in increased production rates and capture of incremental reserves if water coning can be reversed and surface water disposal can be mitigated. To this end, the partners in the Atlas Joint Venture have entered into Exclusive Supply Agreements with a down hole water disposal tool design and manufacturing company to supply separation and disposal tools for use in Canada. These tools are intended to gravity separate gas and water in the wellbore, reverse the flow of water, and inject the water into a disposal zone below the existing production interval. In this manner, existing wells with water production issues can potentially have increased gas productivity due to the lack of water coning and lifting. These down hole disposal tools also remove the issues related to surface handling and disposal of produced fluids. 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 Property Impairment During the quarter ended May 31, 2004, we recognized no impairment of our capitalized oil and gas properties, based upon management's determination that no further impairment of undeveloped properties had occurred since the end of the prior fiscal year. As of the end of the prior fiscal year, August 31, 2003, management completed a comprehensive evaluation of our capitalized oil and gas properties for purposes of determining impaired properties and recognized an impairment charge against the East Lost Hills properties of approximately $3,234,000 for the year then ended. East Lost Hills, San Joaquin Basin, California During the quarter ended May 31, 2004, no drilling or development activities occurred at our East Lost Hills project. 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, and it is unlikely that additional activity will occur on the project. As of the end of the prior fiscal year, August 31, 2003, we recognized an impairment charge against the entire amortizable balance of these properties. Results of Operations The quarter ended May 31, 2004 compared with the quarter ended May 31, 2003. Operations during the quarter ended May 31, 2004 resulted in a net loss of $391,890 compared with a net loss of $385,176 for the quarter ended May 31, 2003. While we had increased revenues associated with properties acquired from Venus Exploration Inc. ("Venus"), the overall increase in net loss was primarily due to an increase in non-cash expense from implementing SFAS No. 143, "Accounting for Asset Retirement Obligations." A broader discussion of these and other items are presented below. Oil and Gas Revenues and Expenses. During the quarter ended May 31, 2004, we recorded $60,787 from the sale of 11,435 Mcf of natural gas, for an average price of $5.32 per Mcf, and $123,762 from the sale of 3,362 bbls of hydrocarbon liquids, for an average price of $36.81 per barrel. Lease operating expenses during this period were $77,958. Revenues and lease operating expenses related to the properties acquired from Venus represent activity from the acquisition close date (in May 2004) through the quarter ended May 31, 2004. During the quarter ended May 31, 2003, we recorded $33,884 from the sale of 6,347 Mcf of natural gas for an average price of $5.34 per Mcf and $9,157 from the sale of 332 bbls of hydrocarbon liquids for an average price of $27.58 per barrel. Lease operating expenses during this period were $18,349. Depreciation, Depletion and Amortization. We recorded $1,700 and $0, respectively, in depreciation, depletion and amortization expense from oil and gas properties for the quarters ended May 31, 2004 and May 31, 2003. The increase in depreciation, depletion and amortization expense was attributable to the properties acquired from Venus. We recorded $3,302 and $3,020 in depreciation expense associated with capitalized office furniture and equipment during the quarters ended May 31, 2004 and May 31, 2003, respectively. Additionally, we recorded $38,953 of depreciation of Asset Retirement Obligation assets, and $27,858 of accretion of the unamortized discount of the Asset Retirement Obligation liability. Dry Hole, Impairment and Abandonments. During the quarters ended May 31, 2004 and May 31, 2003, we recorded no impairment expense. Although properties may be considered evaluated for purposes of the ceiling test and included in the impairment calculation, until these properties are completely abandoned, we may continue to incur costs associated with these properties. Until we can establish economic reserves of the impaired properties, of which there is no assurance, any additional costs associated with these properties are capitalized, and then charged to impairment expense as incurred. 16 General and Administrative Expense. We incurred $350,377 and $339,576 in general and administrative expenses during the quarters ended May 31, 2004 and May 31, 2003, respectively. The increase principally reflects additional accounting and auditing fees incurred in conjunction with properties acquired from Venus. Interest Expense. We incurred $82,234 and $78,316 in interest expense for the quarters ended May 31, 2004 and May 31, 2003, respectively. The interest expense for each year is associated with the May 24, 2002 sale of outstanding convertible notes due on May 24, 2009. The nine months ended May 31, 2004 compared with the nine months ended May 31, 2003. Oil and Gas Revenues and Expenses. During the nine months ended May 31, 2004, we recorded $124,287 from the sale of 26,035 Mcf of natural gas, for an average price of $4.77 per Mcf, and $144,657 from the sale of 4,162 bbls of hydrocarbon liquids, for an average price of $35.76 per barrel. Lease operating expenses during this period were $114,910. Revenues and lease operating expenses related to the properties acquired from Venus represent activity from the acquisition close date (in May 2004) through the quarter ended May 31, 2004. During the nine months ended May 31, 2003, we recorded $106,507 from the sale of 25,268 Mcf of natural gas for an average price of $4.22 per Mcf and $30,572 from the sale of 1,192 bbls of hydrocarbon liquids for an average price of $25.65 per barrel. Lease operating expenses during this period were $64,694. Depreciation, Depletion and Amortization. We recorded $1,700 and $0, respectively, in depreciation, depletion and amortization expense from oil and gas properties for the nine months ended May 31, 2004 and May 31, 2003. Although the East Lost Hills #1 has produced continuously since 2001, we previously recorded an impairment charge against our entire amortizable full cost pool, and therefore had no costs to amortize. We recorded $9,584 and $8,892 in depreciation expense associated with capitalized office furniture and equipment during the nine months ended May 31, 2004 and May 31, 2003, respectively. Additionally, we recorded $114,595 of depreciation of Asset Retirement Obligation assets, and $70,162 of accretion of the unamortized discount of the Asset Retirement Obligation liability. Dry Hole, Impairment and Abandonments. During the nine months ended May 31, 2004, we recorded no impairment expense, compared to $1,178,267 of impairment expense for the nine months ended May 31, 2003. Although properties may be considered evaluated for purposes of the ceiling test and included in the impairment calculation, until these properties are completely abandoned, we may continue to incur costs associated with these properties. Until we can establish economic reserves of the impaired properties, of which there is no assurance, any additional costs associated with these properties are capitalized, and then charged to impairment expense as incurred. General and Administrative Expense. We incurred $887,309 and $1,010,119 in general and administrative expenses during the nine months ended May 31, 2004 and May 31, 2003, respectively. The decrease principally reflects fewer employees in 2004, as well as a decrease in funding and acquisition costs. Interest Expense. We incurred $242,784 and $230,371 in interest expense for the nine months ended May 31, 2004 and May 31, 2003, respectively. The interest expense for each year is associated with the May 24, 2002 sale of outstanding convertible notes due on May 24, 2009. Cash Flow The nine months ended May 31, 2004 compared to the nine months ended May 31, 2003 17 Cash Flows From Operating Activities Net cash used by operating activities was $939,021 and $650,840 for the nine months ended May 31, 2004 and May 31, 2003, respectively. A discussion of these and other items are presented below. Net loss. See discussion of net loss in "Results of Operations" section above. Depreciation and amortization. Depreciation expense increased to $196,042 for the nine months ended May 31, 2004, compared to $8,892 for the nine months ended May 31, 2003. The 2004 expense includes depreciation of Asset Retirement Obligation assets of $114,595 together with $70,162 of accretion of unamortized discount of the Asset Retirement Obligation liability, neither of which was recognized in 2003. Impairment, dry hole and abandonments. During the nine months ended May 31, 2004, we recorded no impairment expense as compared to $1,178,267 during the nine months ended May 31, 2003. The 2003 impairment related principally to costs incurred to drill and complete wells in the East Lost Hills project. Accrued interest converted into debt. For the nine months ended May 31, 2004, accrued interest converted into debt was $319,376 compared to $221,948 for the nine months ended May 31, 2003. Both amounts reflect interest accrued on the $6,000,000 convertible notes issued May 24, 2002. Prepaid expenses. During the nine months ended May 31, 2004 and May 31, 2003, prepaid expenses increased $51,382 and $23,976, respectively. The increase reflects higher director and officer liability insurance premiums. Accounts payable and accruals. During the nine months ended May 31, 2004 and May 31, 2003, accounts payable and accruals increased $88,890, and $311,024, respectively, reflecting lower amounts due to the operator of the East Lost Hills project for costs to drill and complete wells. Cash Flows From Investing Activities Cash paid for oil and gas properties. During the nine months ended May 31, 2004, we paid $3,887,304 for oil and gas properties, compared to $1,067,737, during the nine months ended May 31, 2003. The increased payment reflects the acquisition of properties from Venus in May 2004. Proceeds from sale of exploration options. During the nine months ended May 31, 2004, we signed an Exploration Option Agreement with a subsidiary of Suncor Energy, Suncor Energy Natural Gas America, Inc. ("SENGAI"), covering our Rogers Pass exploration project in the Foothills of west-central Montana. Pursuant to our agreement, SENGAI has paid us a (non-refundable) $500,000 option fee for a technical evaluation period of up to three months. Before the end of the technical evaluation period, SENGAI will make an election, by late-July 2004 either to proceed to drill the first test well or to drop the project. Proceeds from sale of oil and gas properties. During the nine months ended May 31, 2004, we entered into an agreement with two private oil and gas exploration companies covering two of our exploration projects in the Overthrust of southwestern Wyoming. In conjunction with this agreement, the partners paid us $186,016 in prospect fees and pro-rata development costs. 18 Cash Flows From Investing Activities Cash provided by financing activities was $4,442,353 and $0 for the nine months ended May 31, 2004 and May 31, 2003, respectively. The increase primarily reflects the first tranche of a private placement of our common stock, consisting of 4.5 million shares and $4,905,000 in gross proceeds, which was received and accepted in early May 2004. The second tranche of the private placement, consisting of 3.0 million shares and $3,270,000 in gross proceeds, was approved by our stockholders at our Annual Meeting of Stockholders on June 11, 2004. We received the funds from the second tranche in late-June 2004, subsequent to the period ended May 31, 2004. 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. 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, or where there are no proved reserves, it would be the estimated market value of our unproved properties. We perform a detailed estimate of the market value of each property on a quarterly basis based on information known to management as to drilling activity in the area of our holdings and our near term intent to develop such properties. Gains or losses upon disposition of or impairment of our unproved oil and gas properties are recorded in the statement of operations as we have no proved reserves. Revenue Recognition: We recognize oil and gas revenues from our interests in producing wells as oil and gas is produced and sold from these wells. We have no gas balancing arrangements in place. Oil and gas sold is not significantly different from our product entitlement. Recent Accounting Pronouncements In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS No. 141, "Business Combinations," which requires the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review for impairment. Intangible assets with a determinable useful life will continue to be amortized over that period. The oil and gas industry is currently discussing the appropriate balance sheet classification of oil and gas mineral rights held by lease or contract. We classify these assets as a component of oil and gas properties in accordance with our interpretation of SFAS No. 19 and common industry practice. There is also a view that these mineral rights are intangible assets as defined in SFAS No. 141, "Business Combinations", and, therefore, should be classified separately on the balance sheet as intangible assets. 19 We did not change or reclassify contractual mineral rights included in oil and gas properties on the balance sheet upon adoption of SFAS No. 141. We believe our current accounting of such mineral rights as part of oil and gas properties is appropriate under the full cost method of accounting. However, if the accounting for mineral rights held by lease or contract is ultimately changed so that costs associated with mineral rights not held under fee title and pursuant to the guidelines of SFAS No. 141 are required to be classified as long term intangible assets, then the reclassified amount as of May 31, 2004 would be approximately $4,059,000 and the reclassified amount as of August 31, 2003 (the end of our last completed fiscal year) would be approximately $4,366,000. Management does not believe that the ultimate outcome of this issue will have a significant impact on our cash flows, results of operations or financial condition. 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. 20 PART II. OTHER INFORMATION Item 1. Legal Proceedings Not Applicable Item 2. Changes in Securities and Use of Proceeds; Recent Sales Of Unregistered Securities In early May 2004, we received subscriptions for an aggregate of $8,175,000 in gross proceeds from a private placement of our common stock. The private placement (the "Placement") consisted of the sale of 7.5 million shares of common stock, priced at $1.09 per share, to a group of twelve institutional and accredited individual investors pursuant to exemptions from registration under Sections 3(b) and 4(2) of the Securities Exchange Act of 1934, as amended. The first tranche of the Placement, consisting of 4.5 million shares and $4,905,000 in gross proceeds, was received and accepted in early May 2004. The second tranche of the Placement, consisting of 3.0 million shares and $3,270,000 in gross proceeds, was approved by our stockholders at our Annual Meeting of Stockholders on June 11, 2004. We received the funds from the second tranche in late June 2004. Proceeds from the Placement will be used for general corporate purposes, partial funding of the acquisition of assets from Venus Exploration, Inc., and project development and drilling costs associated with our exploration and exploitation portfolio. In early July 2004, we filed a registration statement with the Securities and Exchange Commission to register any resales of the shares purchased in the Placement under the Securities Act of 1933, as amended. 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 and Reports on Form 8-K (a) 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 21 (b) During the quarter ended May 31, 2004, we filed the following reports on Form 8-K: On March 18, 2004 disclosing a news release dated March 17, 2004, which announced that we had signed an exploration option agreement for the Montana Foothills Project. On April 6, 2004 disclosing a news release dated April 5, 2004, which announced the acquisition of assets from Venus Exploration, Inc. and three exploration/exploitation projects scheduled to commence drilling operations. On April 15, 2004 disclosing a news release dated April 13, 2004, which announced our unaudited financial results for the three months ended February 29, 2004. On May 11, 2004 disclosing a news release dated May 6, 2004, which announced an $8.175 million private placement of our common stock. On May 13, 2004 disclosing a news release dated May 12, 2004, which announced the closing of the acquisition of assets from Venus Exploration, Inc. and updated operational activities. Following the quarter ended May 31, 2004, we filed reports on Form 8-K for events occurring on the following dates: June 14, 2004 June 16, 2004 July 2, 2004 (Form 8-K/A) 22 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 July 15, 2004 - ------------------------ and Principal Financial Officer D. Scott Singdahlsen 23 EX-31 2 pyr31.txt CERTIFICATION EXHIBIT 31 CERTIFICATIONS I, D. Scott Singdahlsen, certify that: 1. I have reviewed this Form 10-QSB of PYR Energy Corporation; 2. Based on my knowledge, this 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 report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the small business issuer as of, and for, the periods presented in this report; 4. The small business issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the small business issuer and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the small business issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the small business issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the small business issuer's internal control over financial reporting that occurred during the small business issuer's most recent fiscal quarter (the small business issuer's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the small business issuer's internal control over financial reporting; 5. The small business issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the small business issuer's auditors and the audit committee of the small business issuer's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the small business issuer's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the small business issuer's internal control over financial reporting. Date: July 15, 2004 /s/ D. Scott Singdahlsen -------------------------------- D. Scott Singdahlsen Chief Executive Officer I, D. Scott Singdahlsen, certify that: 1. I have reviewed this Form 10-QSB of PYR Energy Corporation; 2. Based on my knowledge, this 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 report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the small business issuer as of, and for, the periods presented in this report; 4. The small business issuer's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the small business issuer and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the small business issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the small business issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the small business issuer's internal control over financial reporting that occurred during the small business issuer's most recent fiscal quarter (the small business issuer's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the small business issuer's internal control over financial reporting; 5. The small business issuer's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the small business issuer's auditors and the audit committee of the small business issuer's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the small business issuer's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the small business issuer's internal control over financial reporting. Date: July 15, 2004 /s/ D. Scott Singdahlsen -------------------------------- D. Scott Singdahlsen Principal Financial Officer EX-32 3 pyr32.txt CERTIFICATION EXHIBIT 32 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report on Form 10-QSB (the "Report") of PYR Energy Corporation (the "Company") for the quarter ended May 31, 2004, D. Scott Singdahlsen, the Chief Executive Officer and the Principal Financial Officer of the Company, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of the undersigned's knowledge and belief: (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: July 15, 2004 /s/ D. Scott Singdahlsen --------------------------------- D. Scott Singdahlsen Chief Executive Officer and Principal Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----