10-Q 1 pyr1101.txt 10-Q U.S. Securities And Exchange Commission Washington, D.C. 20549 FORM 10-Q [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended November 30, 2001 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. 0-20879 PYR ENERGY CORPORATION ---------------------------------------------------- (Exact name of registrant as specified in its charter) Maryland 95-4580642 ----------------------------- ----------------- (State or jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1675 Broadway, Suite 2450, Denver, CO 80202 -------------------------------------- -------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (303) 825-3748 --------------- Check whether the issuer (1) 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 ----- ----- (APPLICABLE ONLY TO CORPORATE REGISTRANTS) The number of shares outstanding of each of the issuer's classes of common equity as of January 11, 2002 is as follows: $.001 Par Value Common Stock 23,691,357 ---------- PYR ENERGY CORPORATION FORM 10-Q INDEX PART I. FINANCIAL INFORMATION Item 1. Financial Statements.................................. 3 Balance Sheets - November 30, 2001 (Unaudited) and August 31, 2001................................... 3 Statements of Operations - Three Months Ended November 30, 2001 and November 30, 2000 and Cumulative Amounts From Inception Through November 30, 2001 (Unaudited)......................... 4 Statements of Cash Flows - Three Months Ended November 30, 2001 and November 30, 2000 and Cumulative Amounts From Inception Through November 30, 2001 (Unaudited)......................... 5 Notes to Financial Statements......................... 6 Summary of Significant Accounting Policies............ 6 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................... 7 Item 3. Quantitative and Qualitative Disclosures about Market Risk........................................... 11 PART II. OTHER INFORMATION Item 1. Legal Proceedings..................................... 11 Item 2. Changes in Securities and Use of Proceeds............. 11 Item 3. Defaults Upon Senior Securities....................... 12 Item 4. Submission of Matters to a Vote of Security Holders... 12 Item 5. Other Information..................................... 12 Item 6. Exhibits and Reports on Form 8-K...................... 12 Signatures..................................................... 13 2
PART I ITEM 1. FINANCIAL STATEMENTS PYR ENERGY CORPORATION (A Development Stage Company) BALANCE SHEETS ASSETS 11/30/01 8/31/01 (UNAUDITED) CURRENT ASSETS Cash $ 7,660,808 $ 9,800,842 Oil and gas receivables 1,209,010 1,173,751 Deposits and prepaid expenses 95,659 74,636 ------------ ------------ Total Current Assets 8,965,477 11,049,229 ------------ ------------ PROPERTY AND EQUIPMENT, at cost Furniture and equipment, net 40,149 40,638 Oil and gas properties, net 13,283,941 10,977,317 ------------ ------------ 13,324,090 11,017,955 ------------ ------------ $ 22,289,567 $ 22,067,184 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable and accrued liabilities $ 2,843,186 $ 2,263,368 ------------ ------------ Total Current Liabilities 2,843,186 2,263,368 ------------ ------------ COMMITMENTS AND CONTINGENCIES STOCKHOLDERS' EQUITY Common stock, $.001 par value Authorized 75,000,000 shares Issued and outstanding - 23,691,357 shares at 11/30/01 and 23,691,357 shares at 8/31/01 23,691 23,691 Capital in excess of par value 35,214,002 35,214,002 Deficit accumulated during the development stage (15,791,312) (15,433,877) ------------ ------------ 19,446,381 19,803,816 ------------ ------------ $ 22,289,567 $ 22,067,184 ============ ============ 3
PYR ENERGY CORPORATION (A Development Stage Company) STATEMENTS OF OPERATIONS (UNAUDITED) Cumulative Three Three from Months Months Inception Ended Ended Through 11/30/01 11/30/00 11/30/01 REVENUES Oil and gas revenues $ 46,256 $ -- 1,248,235 Interest 62,658 111,128 808,640 Other -- -- 127,528 ------------ ------------ ------------ 108,914 111,128 2,184,403 OPERATING EXPENSES Lease operating expenses 25,167 -- 127,185 Impairment, dry hole, and abandonments 113,544 -- 13,974,824 General and administrative 324,143 254,248 4,122,238 Depreciation and amortization 3,496 4,098 87,492 Interest -- -- 184,306 ------------ ------------ ------------ 466,350 258,346 18,496,045 OTHER INCOME Gain on sale of oil and gas prospects -- -- 556,197 ------------ ------------ ------------ (357,436) (147,218) (15,755,445) INCOME APPLICABLE TO PREDECESSOR LLC (Note 1) -- -- (35,868) ------------ ------------ ------------ NET (LOSS) INCOME (357,436) (147,218) (15,791,313) Less dividends on preferred stock -- -- (292,411) ------------ ------------ ------------ NET (LOSS) TO COMMON STOCKHOLDERS $ (357,436) $ (147,218) $(16,083,724) ============ ============ ============ NET (LOSS) PER COMMON SHARE -BASIC AND DILUTED $ (0.02) $ (0.01) $ (1.28) ============ ============ ============ WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 23,691,357 19,532,027 12,604,544 ============ ============ ============ 4
PYR ENERGY CORPORATION (A Development Stage Company) STATEMENTS OF CASH FLOWS (UNAUDITED) Cumulative Amounts from Inception 11/30/01 11/30/00 Through 11/30/01 CASH FLOWS FROM OPERATING ACTIVITIES Net (loss) $ (357,436) $ (147,218) $(15,755,445) Adjustments to reconcile net (loss) to net cash (used) by operating activities Depreciation and amortization 3,496 4,098 87,492 Contributed services -- -- 36,000 Gain on sale of oil and gas prospects -- -- (556,197) Impairment, dry hole and abandonments 113,544 -- 13,974,824 Common stock issued for interest on debt -- -- 116,822 Common stock issued for services -- -- 20,000 Amortization of financing costs -- -- 26,939 Amortization of marketable securities -- -- (20,263) Changes in assets and liabilities (Increase) decrease in accounts receivable (35,258) (39,996) (1,209,575) (Increase) decrease in prepaids (21,025) (18,537) (100,212) (Decrease) increase in accounts payable (30,797) (99,542) 51,109 Other -- 980 8,195 ------------ ------------ ------------ Net cash (used) by operating activities (327,476) (300,215) (3,320,311) ------------ ------------ ------------ CASH FLOWS FROM INVESTING ACTIVITIES Cash paid for furniture and equipment (3,007) -- (123,919) Cash paid for oil and gas properties (1,809,550) (4,346,773) (24,296,045) Proceeds from sale of oil and gas properties -- -- 1,050,078 Cash paid for marketable securities -- -- (5,090,799) Proceeds from sale of marketable securities -- -- 5,111,062 Cash received (paid) for reimbursable property costs -- -- (28,395) ------------ ------------ ------------ Net cash (used) in investing activities (1,812,557) (4,346,773) (23,378,018) ------------ ------------ ------------ CASH FLOWS FROM FINANCING ACTIVITIES Members capital contributions -- -- 28,000 Distributions to members -- -- (66,000) Cash from short-term borrowings -- -- 285,000 Repayment of short-term borrowings -- -- (285,000) Cash received upon recapitalization and merger -- -- 336 Proceeds from sale of common stock -- -- 30,788,750 Proceeds from sale of convertible debt -- -- 2,500,001 Proceeds from exercise of warrants -- 666,385 2,011,073 Proceeds from exercise of options -- 2,406 189,530 Cash paid for offering costs -- -- (1,036,448) Payments on capital lease -- (920) (5,195) Preferred dividends paid -- -- (50,910) ------------ ------------ ------------ Net cash provided by financing activities -- 667,871 34,359,137 ------------ ------------ ------------ NET (DECREASE) INCREASE IN CASH (2,140,033) (3,979,117) 7,660,808 CASH, BEGINNING OF PERIODS 9,800,841 8,598,016 -- ------------ ------------ ------------ CASH, END OF PERIODS $ 7,660,808 $ 4,618,899 $ 7,660,808 ============ ============ ============ 5
PYR ENERGY CORPORATION (A Development Stage Company) Notes to Financial Statements November 30, 2001 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 period ended November 30, 2001 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-K for the year ended August 31, 2001. 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, the Company was re-incorporated in Maryland through the merger of the Company into a wholly owned subsidiary, PYR Energy Corporation, a Maryland corporation. 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 November 30, 2001, there were no cash equivalents. 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 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 6 reserves. Costs related to undeveloped oil and gas properties may be excluded from depletable costs until such properties are evaluated as either proved or unproved. The net capitalized costs are subject to a ceiling limitation. 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. Unevaluated oil and gas properties consists of ongoing exploratory drilling costs, for which no results have been obtained, and of leases and acreage that we acquire for our exploration and development activities. The cost of these non-producing leases is recorded at the lower of cost or fair market value. We have adopted SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long Lived Assets to Be Disposed of", which requires that long-lived assets to be held and used be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. During the fiscal year ended August 31, 2001, we earned our initial revenues from our oil and gas producing activities. A reserve report prepared as of August 31, 2001 by an independent petroleum engineering firm concluded that based on information available at that time, reserves from our producing properties were not economic to produce. Therefore, at August 31, 2001, we had no proved reserves and recorded an impairment charge against the entire net value of our evaluated properties of $13,339,911 based on the ceiling test limitation. Although properties may be considered as evaluated for purposes of the ceiling test and included in the impairment calculation, until these properties are completely abandoned, we may continue to incur costs associated with these properties. Until we can establish economic reserves, of which there is no assurance, additional costs associated with these properties are charged directly to impairment expense as incurred. During the quarter ended November 30, 2001, we recorded an additional $113,544 for formation evaluation on the ELH #3 well, final drilling related costs for the ELH #2 and ELH #3 wells and for delay rentals that were not included in the impairment calculation at August 31, 2001 and charged this entire amount to impairment expense. Management believes that in the future, any additional costs associated with these properties will be nominal. We continue to own oil and gas production and are recording revenues from the sale of oil and gas. Because we have no costs to amortize, we recorded no depreciation, depletion and amortization expense for the quarter ended November 30, 2001. INCOME TAXES - We have adopted the provisions of SFAS No. 109, "Accounting for Income Taxes". SFAS 109 requires recognition of deferred tax liabilities and assets for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. ACCOUNTS RECEIVABLE AND ACCOUNTS PAYABLE - Accounts receivable at November 30, 2001 includes $1,208,854 of net revenue due from operator for oil and gas sales since commencement of production in February 6, 2001 through November 30, 2001. The Company has not received any payments for production from the operator, and the joint operating agreement underlying the East Lost Hills prospect does not provide for the Company to offset the receivable for oil and gas revenue against amounts due to the operator. The Company believes that the operator is legally responsible to remit payment. Until the Company receives payment, management intends to offset payments due to the operator for cash calls and other liabilities in an amount equal to the revenue due. Although the joint operating agreement provides that the operator can charge interest on past due cash calls and billings, no interest has been charged to the Company. As of November 30, 2001, the Company's liability due to the operator exceeded accounts receivable for oil and gas sales by $1,255,058, including $933,778 for drilling costs not billed as of November 30, 2001. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS We are a development stage independent oil and gas exploration company whose strategic focus is the application of advanced seismic imaging and computer aided exploration technologies in the systematic search for commercial hydrocarbon reserves, primarily in the onshore western United States. We attempt to leverage our technical experience and expertise with seismic data to identify exploration and exploitation projects with significant potential economic return. We intend to participate in selected exploration projects as a working interest owner, sharing both risk and rewards with other participants. We do not 7 currently operate any projects where we own a working interest. We may operate projects in the future. Whether we participate in our projects as operator or non-operator, our financial results depend on our ability to sell prospect interests to outside industry participants. We do not have the ability to commence exploratory drilling operations without outside industry participation. We have pursued, and will continue to pursue, exploration opportunities in regions where we believe significant opportunity for discovery of oil and gas exists. By attempting to reduce drilling risk through seismic technology, we seek to improve the expected return on investment in our oil and gas exploration projects. Our future financial results continue to depend primarily on (1) our ability to discover commercial quantities of hydrocarbons; (2) the market price for oil and gas; (3) our ability to continue to source and screen potential projects; and (4) our ability to fully implement our exploration and development program with respect to these and other matters. There can be no assurance that we will be successful in any of these respects or that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production. We paid approximately $1,810,000 and $4,346,000 during the three months ended November 30, 2001 and November 30, 2000, respectively, for drilling costs, delay rentals, acquisition of acreage, direct geological and geophysical costs, and other related direct costs with respect to our identified exploration and exploitation projects. We currently anticipate that we will participate in the drilling of between three to seven exploration/development wells during the next 12 months, although the number of wells may increase as additional projects are added to our portfolio. However, there can be no assurance that any wells will be drilled and if drilled that any of these wells will be successful. It is anticipated that the future development of our business will require additional, and possibly substantial, capital expenditures. Depending upon the extent of success of our ability to sell additional prospects for cash, the level of industry participation in our exploration projects, and the continuing results at East Lost Hills and the deep Temblor exploration program, we anticipate spending a minimum of approximately $6 million for capital expenditures relating to exploration and development of our projects during calendar 2002. To limit additional capital expenditures, we intend to form industry alliances to exchange a 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 financing, or from sales of interests in our properties although there is no assurance continued funding will be available. At November 30, 2001, we had a working capital amount of approximately $6,122,000. We had no outstanding long-term debt at November 30, 2001 and had not entered into any commodity swap arrangements or hedging transactions. Although we have no current plans to do so, we may enter into commodity swap and/or hedging transactions in the future in conjunction with oil and gas production. The following is a summary of the current status of the East Lost Hills project in the San Joaquin Basin of California operated by Anadarko Petroleum Corporation: During the first quarter ended November 30, 2001, our only producing well, the ELH #1, produced a gross total of approximately 125 mmcfe, averaging approximately 1.5 mmcfe per day. Water production during this period averaged approximately 4,850 barrels per day. The oil and gas production from the ELH #1 well is limited to the amount of production water that is accepted at water disposal facilities owned by ChevronTexaco. The participants are currently in the process of preparing to drill a water disposal well and to build associated pipeline and disposal facilities in order to dispose of water without relying on the ChevronTexaco facility, thereby removing the water disposal constraint that 8 continues to limit the oil and gas production from the ELH #1 well. Although we expect to be able to increase oil and gas production if we can increase the water disposal capability, it is unknown whether removing the water disposal constraint will result in a decrease in the water to gas ratio. The ELH #4 well commenced drilling on November 26, 2000 at a location approximately four miles southeast of the ELH #1 well. This well reached a total depth of 20,800 feet on August 7, 2001. Log and coring analysis was performed and it was determined that in order to maximize potential production, the well bore should be sidetracked and directed to a more crestal position within the lower Temblor. On October 16, 2001, sidetrack drilling operations commenced to drill to a projected depth of 20,500 feet. During late December 2001, an intermediate string of casing was successfully run in the sidetracked well bore to a depth of approximately 19,500 feet. This well is currently drilling at a depth of approximately 20,000 feet. The ELH #9 well commenced drilling on July 17, 2001 approximately six miles southeast of the ELH #1 well. This well has a target total depth in the lower Temblor of 21,000 feet. An intermediate string of casing was recently run to a depth of approximately 17,600 feet. This well is currently drilling in the upper Temblor at a depth of approximately 18,300 feet. We are also participating in a third well currently drilling at East Lost Hills. The Aera Energy LLC NWLH 1-22 well located in Section 22, T25S-R20E commenced drilling on August 23, 2001. This well is approximately three and a half miles northwest of the ELH #1 well and is designed to test the Temblor formation to a projected depth of 20,000 feet. We are participating in this well operated by Aera Energy LLC through a pooling arrangement at a 4.04% working interest. After drilling to a depth of 18,400 feet, it was determined that the well bore could be directed into the Temblor in a more crestal position. As a result, operations have commenced to kick-off a sidetrack well bore from a depth of 14,100 feet. The sidetrack operations are in the open hole portion of the well bore as no casing has been run at this depth. The total target depth of this sidetrack well remains at 20,000 feet. Additional San Joaquin Basin California activities include the following projects: Pyramid Power Prospect. In April 1999, we purchased a working interest in the Pyramid Power deep natural gas exploration project in the San Joaquin Basin. This project is outside the East Lost Hills joint venture area. Our working interest in this project is 3.75% with our interest being carried through the tanks in the initial test well. The initial exploration well, operated by Anadarko and located in Section 9, T25S-R18E, commenced drilling on November 22, 2001. This exploration well is designed to test the Temblor and the Point of Rocks formation to a total depth of 18,500 feet. The participants at Pyramid Power jointly control approximately 20,000 gross and 15,000 net acres over the prospect. This well continues drilling operations at an approximate depth of 14,150 feet. Wedge Prospect. This is a seismic generated 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 that has proven productive at East Lost Hills, extends approximately ten miles further northwest of the East Lost Hills Area of Mutual Interest and can be encountered as much as 3,000 feet higher. We currently control approximately 14,000 gross and approximately 13,000 net acres here. Our approach is to sell down our working interest and retain a 25% to 40% working interest in this prospect. Bulldog Prospect. This project is a 2D seismic generated light oil and natural gas prospect located adjacent to the giant Kettleman North Dome field in the San Joaquin Basin. This prospect can be best characterized as a classic 9 footwall fault trap, similar to the many known footwall fault trap accumulations that have produced significant quantities of hydrocarbons throughout the San Joaquin basin. We currently control approximately 16,000 gross and approximately 15,000 net acres here. We are in the process of securing industry participation to drill a 14,000 foot test well and we expect to retain a 25% to 40% working interest in this prospect. Additional activities located in the Rocky Mountains include the following projects: Montana Foothills Project. This extensive natural gas project, located in northwestern Montana, is part of the southern Alberta basin, and has been classified as the southern extension of the Alberta Foothills producing province. The USGS and numerous Canadian industry sources have estimated extremely significant recoverable reserves for the Montana portion of the Foothills trend. Based on extensive geologic and seismic analysis, we have identified numerous structural culminations of similar size, geometry, and kinematic history as prolific Canadian foothills fields, such as Waterton and Turner Valley. The geologic setting and hydrocarbon potential of this area was not recognized by industry until the early 1980s. At that time, a number of companies initiated exploration efforts, including Exxon, Arco, Chevron, Amoco, Conoco, and Unocal. This initial exploration phase culminated in a deep test by Unocal in 1989. Although this well was unsuccessful, recent improvements in seismic imaging and pre-stack processing have resulted in our belief that this test well was drilled based upon a misleading seismic image and was located significantly off-structure. We currently control approximately 262,000 gross and 224,000 net acres in this project and are currently presenting this project to potential industry participants in order to sell down our working interest and generate exploratory drilling activity. We anticipate retaining a working interest in this project of between 20% to 40%. Wyoming Projects. We have three separate exploration projects in Wyoming, and have acquired an initial land position of approximately 8,000 gross and net acres. We intend to acquire additional land holdings as opportunities arise. We currently are interpreting seismic data and conducting other geophysical activities. Results of Operations The quarter ended November 30, 2001 compared with the quarter ended November 30, 2000. Operations during the quarter ended November 30, 2001 resulted in a net loss of $357,436 compared to a net loss of $147,218 for the quarter ended November 30, 2000. The components that account for the difference are presented below. Oil and Gas Revenues and Expenses. Production commenced at the East Lost Hills #1 well on February 6, 2001. Our ownership share of this production resulted in our recording $20,995 from the sale of 8,985 mcf of natural gas for an average price of $2.34 per mcf and $8,700 from the sale of 485 bbls of hydrocarbon liquids for an average price of $17.94 per barrel during the quarter ended November 30, 2001. In addition, we recorded revenues dating back to commencement of production of the ELH #1 well of $16,561 from overriding royalty interests we own. Operating expenses during this period were $25,167. We recorded no revenues or expenses from oil and gas operations for the quarter ended November 30, 2000. None of our oil or gas properties were producing before February 6, 2001. 10 Depreciation, Depletion and Amortization. We recorded no depreciation, depletion and amortization expense from oil and gas properties for the quarters ended November 30, 2001 and November 30, 2000. Although the East Lost Hills #1 began producing in 2001, we recorded an impairment against our entire amortizable full cost pool through November 30, 2001, and therefore had no costs to amortize. During the quarter ended November 30, 2000, none of our oil and gas properties were producing, and therefore no DD&A expense was recognized. We recorded $3,496 and $4,098 in depreciation expense associated with capitalized office furniture and equipment during the quarters ended November 30, 2001 and November 30, 2000, respectively. Dry Hole, Impairment and Abandonments. During the quarter ended November 30, 2001, we recorded an additional $113,544 for formation evaluation on the ELH #3 well, final drilling related costs for the ELH #2 and ELH #3 wells and for delay rentals that were not included in the impairment calculation at August 31, 2001 and charged this entire amount to impairment expense. Although properties may be considered as evaluated for purposes of the ceiling test and included in the impairment calculation, until these properties are completely abandoned, we may continue to incur costs associated with these properties. Until we can establish economic reserves, of which there is no assurance, additional costs associated with these properties are charged directly to impairment expense as incurred. We recorded no impairment against our oil and gas properties for the quarter ended November 30, 2000. General and Administrative Expense. We incurred $324,143 and $254,248 in general and administrative expenses during the quarters ended November 30, 2001 and November 30, 2000, respectively. The increase results primarily from increases in salary related expenses from increasing personnel and salaries, costs associated with our first independent reserve analysis and an increase in rent expense. ITEM 3. QUANTITIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Not Applicable PART II. OTHER INFORMATION Item 1. Legal Proceedings Not Applicable Item 2. Changes in Securities and Use of Proceeds; Recent Sales Of Unregistered Securities On January 5, 2001, our "shelf" registration statement (SEC file number 333-51764), pertaining to the sale from time to time of up to $75 million of our securities, was declared effective by the Securities and Exchange Commission. The securities that may be offered by the Company pursuant to this registration statement may include shares of common stock, shares of preferred stock, which may be issued in the form of depositary shares evidenced by depositary receipts, warrants to purchase common stock, preferred stock or any combination of those securities, or any combination of any of these securities. On March 9, 2001, we received a total of $11.6 million in gross proceeds from the sale of 1,450,000 shares of our common stock. The common stock was sold pursuant to a prospectus supplement with respect to the shelf registration statement. We incurred offering expenses of $160,470 in this offering, so that we received net proceeds of $11,439,530 from this sale of common stock. These expenses do not include any direct or indirect payments to directors, officers, persons owning 10% or more of any class of equity securities, or affiliates of 11 the Company. Because these securities were sold directly by the Company in an offering that did not involve an underwriter, we did not pay any underwriting discounts or commissions, finder's fees or other expenses to or for underwriters. Through November 30, 2001, $4,772,608 of the proceeds from this sale of common stock have been used as described in the prospectus supplement to fund our planned exploration and development activities, primarily in the San Joaquin Basin of California. Included in the total amount is $1,809,550 which was used during the quarter ended November 30, 2001. 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 None (b) During the Quarter ended November 30, 2001, we filed one report on Form 8-K: A Form 8-K was filed on November 29, 2001 reporting a news release dated November 29, 2001. 12 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 January 11, 2002 ----------------------------- Officer and Chairman D. Scott Singdahlsen Of The Board /s/ Andrew P. Calerich Vice-President and Chief January 11, 2002 ----------------------------- Financial Officer Andrew P. Calerich 13