-----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, N27Bs1W1l4ArRvCTtDAAjUeNzKeKwaLrl/Kw8fvAzZQRbZdmgvp8Vcim/uQMol/S TCKt9tjggcZ9LlFIhf0zMA== 0000837759-02-000010.txt : 20020515 0000837759-02-000010.hdr.sgml : 20020515 20020515135137 ACCESSION NUMBER: 0000837759-02-000010 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20020331 FILED AS OF DATE: 20020515 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MALLON RESOURCES CORP CENTRAL INDEX KEY: 0000837759 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 841095959 STATE OF INCORPORATION: CO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-13124 FILM NUMBER: 02650507 BUSINESS ADDRESS: STREET 1: 999 18TH ST STE 1700 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3032932333 MAIL ADDRESS: STREET 1: 999 18TH STREET STREET 2: STE 1700 CITY: DENVER STATE: CO ZIP: 80202 10-Q 1 edgarq1.txt SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 Form 10-Q (Mark One) [X] Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended March 31, 2002. - - or - [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from _______ to ______. Commission File No. 0-17267 MALLON RESOURCES CORPORATION (Exact name of registrant as specified in its charter) COLORADO 84-1095959 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 999 18th Street, Suite 1700 Denver, Colorado 80202 (Address of principal executive offices) (303) 293-2333 (Registrant's telephone number, including area code) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or such shorter period of time registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ] As of May 10, 2002, 10,867,827 shares of the registrant's common stock, par value $0.01 per share, were outstanding. PART I -- FINANCIAL INFORMATION Item 1. Financial Statements MALLON RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (In thousands) ASSETS
March 31, December 31, 2002 2001 (Unaudited) Current assets: Cash and cash equivalents $ 1,416 $ 1,943 Accounts receivable: Oil and gas sales 727 714 Joint interest participants 54 303 Inventories 151 151 Derivative asset -- 229 Prepaid expense and other 101 38 Total current assets 2,449 3,378 Property and equipment: Oil and gas properties, full cost method 94,464 93,933 Natural gas processing plant 8,659 8,648 Other property and equipment 1,087 1,085 104,210 103,666 Less accumulated depreciation, depletion and amortization (71,513) (70,414) 32,697 33,252 Debt issuance costs, net 882 1,041 Other, net 200 300 Total Assets $ 36,228 $ 37,971 ======== ========
(Continued on next page) The accompanying notes are an integral part of these consolidated financial statements. MALLON RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS - Continued (In thousands, except share amounts) LIABILITIES AND SHAREHOLDERS' EQUITY
March 31, December 31, 2002 2001 (Unaudited) Current liabilities: Trade accounts payable $ 1,973 $ 2,153 Undistributed revenue 420 612 Accrued taxes and expenses 84 42 Derivative liability 1,038 -- Current portion of long-term debt 533 517 Total current liabilities 4,048 3,324 Long-term debt, net of unamortized discount of $1,790 and $1,899, respectively 29,737 28,970 Derivative liability 1,865 1,423 31,602 30,393 Total liabilities 35,650 33,717 Commitments and contingencies Series B Mandatorily Redeemable Convertible Preferred Stock, $0.01 par value, 500,000 shares authorized, -0- shares issued and outstanding -- -- Mandatorily Redeemable Common Stock, $0.01 par value, 490,000 shares authorized, issued and outstanding, mandatory redemption of $6,125 5,017 4,853 Shareholders' equity: Common Stock, $0.01 par value, 25,000,000 shares authorized; 10,377,827 and 10,252,827 shares issued and outstanding, respectively 104 103 Additional paid-in capital 92,652 93,012 Accumulated deficit (94,292) (92,520) Accumulated other comprehensive loss (2,903) (1,194) Total shareholders' equity (4,439) (599) Total Liabilities and Shareholders' Equity $ 36,228 $ 37,971 ======== ========
The accompanying notes are an integral part of these consolidated financial statements. MALLON RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (In thousands, except per share amounts)
For the Three Months Ended March 31, 2002 2001 (Unaudited) Revenues: Oil and gas sales $ 2,683 $7,093 Interest and other 13 237 2,696 7,330 Costs and expenses: Oil and gas production 1,762 2,722 Depreciation, depletion and amortization 1,269 1,959 General and administrative, net 475 1,355 Interest and other 962 1,788 4,468 7,824 Net loss (1,772) (494) Dividends and accretion on preferred stock -- (18) Accretion of mandatorily redeemable common stock (164) (144) Net loss attributable to common shareholders $(1,936) $ (656) ====== ====== Basic: Net loss per share attributable to common shareholders $ (0.18) $(0.06) ======= ====== Weighted average common shares outstanding 10,811 10,627 ======= ======
The accompanying notes are an integral part of these consolidated financial statements. MALLON RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands)
For the Three Months Ended March 31, 2002 2001 (Unaudited) Cash flows from operating activities: Net loss $(1,772) $ (494) Adjustments to reconcile net loss to net cash (used in) provided by operating activities: Depreciation, depletion and amortization 1,269 1,959 Accrued interest expense added to long-term debt -- 1,401 Accrued interest income added to notes receivable from shareholders -- (45) Amortization of discount on long-term debt 296 215 Non-cash stock compensation expense (440) 579 Changes in operating assets and liabilities: Decrease (increase) in: Accounts receivable 236 1,066 Inventory and other assets 94 (1,897) (Decrease) increase in: Trade accounts payable and undistributed revenue (372) (166) Accrued taxes and expenses 42 39 Net cash (used in) provided by operating activities (647) 2,657 Cash flows from investing activities: Additions to property and equipment (554) (6,517) Other -- 7 Net cash used in investing activities (554) (6,510) Cash flows from financing activities: Proceeds from long-term debt 800 837 Payments of long-term debt (126) (110) Payment of preferred dividends -- (16) Net cash provided by financing activities 674 711 Net decrease in cash and cash equivalents (527) (3,142) Cash and cash equivalents, beginning of period 1,943 14,155 Cash and cash equivalents, end of period $ 1,416 $11,013 ======= ======= Supplemental cash flow information: Cash paid for interest $ 666 $ 173 ======= ======= Non-cash transactions: Issuance of common stock in connection with the credit agreement amendment $ 187 $ -- ======= =======
The accompanying notes are an integral part of these consolidated financial statements. MALLON RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited) ___________ NOTE 1. GENERAL Mallon Resources Corporation ("Mallon" or the "Company") engages in oil and gas exploration and production through its wholly-owned subsidiary, Mallon Oil Company ("Mallon Oil"), whose oil and gas operations are conducted primarily in the State of New Mexico. Mallon operates its business and reports its operations as one business segment. All significant inter-company balances and transactions have been eliminated from the consolidated financial statements. These unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, such interim statements reflect all adjustments (consisting of normal recurring adjustments) necessary to present fairly the financial position and the results of operations and cash flows for the interim periods presented. The results of operations for these interim periods are not necessarily indicative of the results to be expected for the full year. These interim statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company's 2001 Form 10-K. Certain prior year amounts in the consolidated financial statements have been reclassified to conform to the presentation used in 2002. NOTE 2. CURRENT OPERATING ISSUES The Company generated net losses of $1.8 million, $31.4 million, $6.5 million and $2.8 million for the three months ended March 31, 2002 and for the years ended December 31, 2001, 2000 and 1999, respectively. The Company's cash flows from operating activities were $(0.6) million, $1.1 million, $4.0 million and $2.4 million for the respective periods. In September 2001, the Company completed the sale of its Delaware Basin oil and gas properties. Consequently, the Company's remaining operations are located primarily in the San Juan Basin of northwest New Mexico. In February 2002, the Company amended its credit facility to provide, among other things, for a $2.5 million increase in the borrowings available under the credit facility. In addition, the Company is currently seeking alternative methods of financing its discretionary capital expenditures for 2002, including joint ventures with industry partners. The Company cannot assure that it will be able to secure financing on terms acceptable to the Company. In addition, because production from the San Juan Basin is predominantly natural gas, the Company is particularly sensitive to changes in the price of natural gas. Historically, natural gas prices have experienced significant fluctuations and have been particularly volatile in recent years. Price fluctuations can result from variations in weather, levels of regional or national production and demand, availability of transportation capacity to other regions of the country and various other factors. Increases or decreases in natural gas prices received could have a significant impact on the Company's future results. If natural gas prices decline significantly from those received by the Company at March 31, 2002, or if the Company is unable to maintain production levels at its San Juan Basin properties, Mallon may have to implement additional cost cutting measures in both its administrative and operating areas. As discussed more fully in Note 3, in conjunction with the February 2002 amendment to the Company's credit agreement, through December 31, 2002, the Company is only required to make interest payments on the credit facility. Management believes that cash on hand, availability under its credit facility and cash generated from operating activities, will be sufficient to meet the Company's cash requirements through March 31, 2003. NOTE 3. LONG-TERM DEBT Long-term debt consists of the following:
March 31, December 31, 2002 2001 Note payable to Aquila Energy Capital Corporation, due 2003 $ 27,511 $ 26,711 Less unamortized discount (1,790) (1,899) 25,721 24,812 Lease obligation to Universal Compression, Inc. 4,446 4,567 8.0% unsecured note payable to Bank One, Colorado, N.A., due 2006 103 108 30,270 29,487 Less current portion (533) (517) Total $ 29,737 $ 28,970 ======== ========
In September 1999, the Company established a credit agreement (the "Aquila Credit Agreement") with Aquila Energy Capital Corporation ("Aquila"). In February 2002, the Company notified Aquila that it would not be in compliance as of December 31, 2001 with one of the covenants under the Aquila Credit Agreement. That covenant requires the Company to maintain projected net revenue attributable to its proved reserves in sufficient amount to fully amortize the balance under the Aquila Credit Agreement by the maturity date of September 9, 2003. As a result, in February 2002, the Aquila Credit Agreement was amended for a second time. The second amendment contains the following provisions: (i) As long as no new event of default occurs subsequent to the date of the second amendment, Aquila has agreed that through December 31, 2002, it will not exercise any of the remedies available to Aquila due to any event of default that occurs and is continuing regarding the amount of projected net revenue required to amortize the amounts outstanding by September 9, 2003. (ii) Interest on amounts outstanding accrues at prime plus 3% starting January 1, 2002, through September 30, 2002, and increases to prime plus 4% after October 1, 2002. The Company is required to pay interest only on the outstanding balance through December 31, 2002. (iii) The amount available under the agreement was increased by $2.5 million, making the total available $55.9 million. Aquila may, at its discretion, advance additional loans up to $2.5 million to be used for development operations and/or working capital needs of the Company. (iv) A "change of control" provision was added, which calls for the prepayment of the entire outstanding balance, together with any accrued and unpaid interest, at the occurrence of a change of control of the Company. (v) The Company has the option to purchase from Aquila 490,000 shares of the Company's common stock previously issued to Aquila for a price of $2.6 million if a sale of the Company is consummated prior to September 30, 2002. (vi) Aquila's one-time right to require the Company to purchase shares of the Company's common stock previously issued to Aquila (the "Put Option") was amended to provide that Aquila has the option to sell to the Company up to 490,000 shares of the Company's common stock at $10.00 per share if a sale of the Company is consummated at any time after September 30, 2002 and prior to September 9, 2003, or at $12.50 per share if the outstanding balance under the Aquila Credit Agreement is paid on the earlier of September 9, 2003 or the date on which Aquila notifies the Company of the acceleration of payment of the outstanding balance because of the occurrence of an event of default. (vii) The Company issued to Aquila 125,000 shares of the Company's common stock as a part of the amendment. If a sale of the Company is not consummated before October 1, 2002, the Company will issue Aquila an additional 150,000 shares. (viii) Upon a change of control of the Company occurring on or before September 30, 2002, the Company will pay Aquila $500,000 and recorded $187,000 as an increase to unamortized discount. If a change of control of the Company occurs after September 30, 2002, the Company will pay Aquila $1,250,000. Through March 31, 2002, the Company had drawn $800,000 under provision (iii) above, and had $1.7 million available for future draws. Principal payment under the Aquila Credit Agreement are based on the Company's cash flow from operations, as defined (the "Defined Cash Flow"), less advances for the Company's development drilling program. Principal payments have been delayed by the second amendment and are to resume in January 2003. The Company estimates that the Defined Cash Flow available for principal payments in first quarter 2003 could range between $0 and $300,000, therefore, at March 31, 2002, no amount has been classified as current. NOTE 4. PER SHARE DATA Basic earnings per share is computed by dividing income available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted earnings per share reflects the potential dilution that could occur if the Company's outstanding stock options and warrants were exercised (calculated using the treasury stock method) or if the Company's Series B Mandatorily Redeemable Convertible Preferred Stock were converted to common stock. The consolidated statements of operations for the three months ended March 31, 2002 and 2001 reflect only basic earnings per share because the Company was in a loss position for all periods presented and all common stock equivalents are anti-dilutive. NOTE 5. HEDGING ACTIVITY Under the Aquila Credit Agreement, the Company may be required to maintain price hedging arrangements in place with respect to up to 65% of its oil and gas production. Accordingly, at March 31, 2002, the Company had price swaps covering 2,949,000 MMBtu of gas related to production for 2002- 2004 at fixed prices ranging between $2.55-$3.38 per MMBtu. In addition, the Company had outstanding at March 31, 2002 basis swaps to fix the differential between the NYMEX (Henry Hub) price and the index price at which the hedged gas is to be sold for 2,949,000 MMBtu for 2002-2004. The following table indicates the Company's outstanding energy swaps at March 31, 2002:
Annual Market Price Product Production Fixed Price Duration Reference Gas (MMBtu) 1,101,000 $2.55-$3.38 4/02-12/02 NYMEX (Henry Hub) Gas (MMBtu) 996,000 $2.55 1/03-12/03 NYMEX (Henry Hub) Gas (MMBtu) 852,000 $2.55 1/04-12/04 NYMEX (Henry Hub)
At March 31, 2002, the Company had recorded a current derivative liability of $1.0 million, a long-term derivative liability of $1.9 million and an unrealized loss of $2.9 million in accumulated other comprehensive loss. No related income tax effects were recorded because of the Company's net operating loss carryforward. During the three months ended March 31, 2002, gains of $0.3 million were transferred from accumulated other comprehensive loss to oil and gas revenues related to settled positions and an unrealized loss of $1.4 million was recorded to other comprehensive income to adjust the fair value of the open positions. The Company expects to reclassify as decreases to earnings during the next twelve months approximately $1.0 million of unrealized hedging losses in accumulated other comprehensive loss at March 31, 2002. For the three months ended March 31, 2002 and 2001, the Company's gains (losses) under its swap agreements were $0.3 million and $(2.9) million, respectively, and are included in oil and gas sales in the Company's consolidated statements of operations. At March 31, 2002, the estimated net amount the Company would have paid to terminate its outstanding energy swaps and basis swaps, described above, was approximately $2.9 million. NOTE 6. COMPREHENSIVE INCOME The Company follows SFAS No. 130, "Reporting Comprehensive Income", which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income includes all changes in equity during a period, except those resulting from investments and distributions to the owners of the Company. The following table illustrates the changes in accumulated other comprehensive loss for the periods presented (in thousands):
For the Three Months Ended March 31, 2002 2001 Accumulated other comprehensive loss - beginning of period $(1,194) $ -- Other comprehensive loss: Cumulative effect of change in accounting principle -- (15,171) Reclassification adjustment for settled hedging contracts (263) 2,914 Changes in fair value of outstanding hedging positions (1,446) 1,159 Other comprehensive loss (1,709) (11,098) Accumulated other comprehensive loss - end of period $(2,903) $(11,098) ======= ========
NOTE 7. CONTINGENCIES As of December 31, 2001, the Revenue and Taxation Department of the Jicarilla Apache Nation (the "Nation") issued to the Company Possessory Interest Tax assessments for 1998, 1999, 2000 and 2001 totaling $3.3 million, as adjusted, including related penalties and interest. The Company paid the assessments, but filed protests with the Nation taking the position that, among other things, certain rules and regulations promulgated in December 2000 by the Nation do not apply to the determination of Possessory Interest Tax for years prior to 2001. The protests were denied. The Company has filed an appeal, which is pending. In March 2002, the Company was assessed an additional $1.5 million for 2002, of which $358,000 has been accrued and expensed at March 31, 2002. The Company has: 1) requested that the Legislative Council of the Nation grant the Company relief, and 2) engaged New Mexico counsel to represent it. The final outcome of this matter cannot yet be predicted. By letter dated October 9, 2001, the Company was advised that the Minerals Management Service will audit the royalties payable on production from certain oil and gas properties in which the Company owns an interest. The audit began in mid-November 2001. The final outcome of this matter cannot yet be predicted. In June 2001, in connection with staff cuts that were part of general corporate reductions, the Company terminated an employee. The employee filed a complaint, in which he claims he was wrongfully terminated. The Company believes the allegations of the suit are wholly without merit, and intends to defend itself vigorously, but cannot predict the outcome of the case. In 1992, the Minerals Management Service commenced an audit of royalties payable on production from certain oil and gas properties in which the Company owns an interest. The audit was initiated against the predecessor operator of the properties, but the Company has since undertaken primary responsibility for resolving matters that arise out of the audit. The Company's liability with respect to the predecessor operator's liability is limited to $100,000. However, the Company may have an additional liability with respect to transactions that have occurred subsequent to its purchase of the oil and gas properties in question. The audit focused on several matters, the most significant of which were the manner in which production is measured and the manner in which royalties are calculated and accounted for. Certain alleged deficiencies preliminarily suggested by the audit were contested. Determinations contrary to several of the Company's positions were rendered in June 1999, which the Company has determined not to appeal. Certain key items relating to the calculation of royalties have yet to be determined. A determination contrary to the Company's position concerning so-called "major portion" issues was recently rendered by the Department of the Interior. The Company's interests in this controversy are represented by outside legal counsel who is appealing the Department of the Interior's rulings. In addition, the Company has recently determined to attempt to negotiate a private protocol addressing the manner in which royalties are calculated and accounted for. The final outcome of these matters cannot yet be predicted. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations The following discussion is intended to assist in understanding our consolidated financial position at March 31, 2002 and December 31, 2001, and results of operations and cash flows for the three months ended March 31, 2002 and 2001. Our consolidated financial statements and notes thereto should be referred to in conjunction with the following discussion. Overview Our revenues, profitability and future growth rates will be substantially dependent upon our drilling success in the San Juan Basin, and prevailing prices for oil and gas, which are in turn dependent upon numerous factors that are beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. The energy markets have historically been volatile, and oil and gas prices can be expected to continue to be subject to wide fluctuations in the future. A substantial or extended decline in oil or gas prices could have a material adverse effect on our financial position, results of operations and access to capital, as well as the quantities of gas reserves that we may produce economically. Liquidity and Capital Resources We have generated net losses of $1.8 million, $31.4 million, $6.5 million and $2.8 million for the three months ended March 31, 2002 and for the years ended December 31, 2001, 2000 and 1999, respectively. Our cash flows from operating activities for the respective periods were $(0.6) million, $1.1 million, $4.0 million and $2.4 million. In September 2001, we completed the sale of our Delaware Basin oil and gas properties. Consequently, our remaining operations are located primarily in the San Juan Basin of northwest New Mexico. We have limited access to the capital necessary to continue to develop our properties. In February 2002, we were able to amend our credit facility to provide, among other things, for a $2.5 million increase in the borrowings available under the credit facility. In addition, we are currently pursuing alternative methods of financing our discretionary capital expenditures for 2002, including joint ventures with industry partners. There is no assurance that we will be able to secure financing on terms acceptable to us. In addition, because production from the San Juan Basin is predominantly natural gas, we are particularly sensitive to changes in the price of natural gas. Historically, natural gas prices have experienced significant fluctuations and have been particularly volatile in recent years. Price fluctuations can result from variations in weather, levels of regional or national production and demand, availability of transportation capacity to other regions of the country and various other factors. Increases or decreases in natural gas prices received could have a significant impact on our future results. If natural gas prices received decline significantly from those received at March 31, 2002, or if we are unable to maintain production levels at our San Juan Basin properties, we may have to implement additional cost cutting measures in both our administrative and operating areas. As discussed more fully below, in conjunction with the February 2002 amendment to the Aquila Credit Agreement, through December 31, 2002, we are only required to make interest payments. We believe that cash on hand, available borrowings under the Aquila Credit Agreement and cash generated from operating activities will be sufficient to meet our cash requirements through March 31, 2003. Our operations are capital intensive. Historically, our principal sources of capital have been cash flow from operations, borrowings and proceeds from sales of stock. Our principal uses of capital have been for the acquisition, exploration and development of oil and gas properties and related facilities. During the three months ended March 31, 2002, our capitalized costs incurred in oil and gas producing activities were $0.6 million, principally relating to the installation of artificial lift equipment. We are currently evaluating the number of wells we will drill during 2002. We plan to fund our capital requirements for the next 12 months with additional financing or joint venture arrangements. In April 2002, Mallon entered into a letter of intent with Smart Exploration, Inc., for the formation of a joint venture to explore and develop Fruitland Formation coal seams that underlie our East Blanco Gas Project in the San Juan Basin of New Mexico. We cannot be sure that any additional financing or joint ventures will be available to us on acceptable terms. In September 1999, we established a credit agreement (the "Aquila Credit Agreement") with Aquila. In February 2002, we notified Aquila that as of December 31, 2001, we would not be in compliance with one of the covenants under the Aquila Credit Agreement. That covenant requires us to maintain projected net revenue attributable to our proved reserves in an amount sufficient to fully amortize the balance under the Aquila Credit Agreement by the maturity date of September 9, 2003. As a result, in February 2002, the Aquila Credit Agreement was amended for a second time, as follows: (i) As long as no new event of default occurs subsequent to the date of the second amendment, Aquila has agreed that through December 31, 2002, it will not exercise any of the remedies available to Aquila due to any event of default that occurs and is continuing regarding the amount of projected net revenue required to amortize the amounts outstanding by September 9, 2003. (ii) Interest on amounts outstanding accrues at prime plus 3% starting January 1, 2002, through September 30, 2002, and increases to prime plus 4% after October 1, 2002. We are required to pay interest only on the outstanding balance through December 31, 2002. (iii) The amount available under the agreement was increased by $2.5 million, making the total available $55.9 million. Aquila may, at its discretion, advance additional loans up to $2.5 million to be used for our development operations and/or working capital needs. (iv) A "change of control" provision was added, which calls for the prepayment of the entire outstanding balance, together with any accrued and unpaid interest, at the occurrence of a change of control of the Company. (v) We have the option to purchase from Aquila 490,000 shares of our common stock previously issued to Aquila for a price of $2.6 million if a sale of the Company is consummated prior to September 30, 2002. (vi) Aquila's one-time right to require us to purchase shares of our common stock previously issued to Aquila (the "Put Option") was amended to provide that Aquila has the option to sell to us up to 490,000 shares of our common stock at $10.00 per share if a sale of the Company is consummated at any time after September 30, 2002 and prior to September 9, 2003, or at $12.50 per share if the outstanding balance under the Aquila Credit Agreement is paid on the earlier of September 9, 2003 or the date on which Aquila notifies us of the acceleration of payment of the outstanding balance because of the occurrence of an event of default. (vii) We issued to Aquila 125,000 shares of the Company's common stock as a part of the amendment and recorded $187,000 as an increase to unamortized discount. If a sale of the Company is not consummated before October 1, 2002, we will issue Aquila an additional 150,000 shares. (viii) Upon a change of control of the Company occurring on or before September 30, 2002, we will pay Aquila $500,000. If a change of control of the Company occurs after September 30, 2002, we will pay Aquila $1,250,000. Through May 10, 2002, we had drawn $1,700,000 under provision (iii) above, and had $800,000 available for future draws. The Aquila Credit Agreement is secured by substantially all of our oil and gas properties and contains various covenants and restrictions, including ones that could limit our ability to incur other debt, dispose of assets, or change management. The weighted average interest rate for borrowings outstanding under the Aquila Credit Agreement at March 31, 2002 was 7.75%. The outstanding loan balance is due in full on September 9, 2003. As part of the transaction, we also entered into an Agency Agreement with Aquila under which we pay Aquila a marketing fee equal to 1% of the net proceeds (as defined) from the sale of our oil and gas production to market our gas and to negotiate our gas purchase contracts. In April 2000, the Government of Costa Rica awarded us a concession to explore for oil and natural gas on approximately 2.3 million acres in the northeast quadrant of Costa Rica. We have completed an environmental assessment of our proposed operations, and are currently in the process of negotiating final concession contracts. Once we sign final contracts, the work program is expected to require the expenditure of $8.8 million (including the drilling of six wells) over a three-year period, with a possible extension of three more years. We will need to secure joint venture or other additional financing in order to complete the work program. Results of Operations
Three Months Ended March 31, 2002 2001 (In thousands, except per unit data) Operating Results from Oil and Gas Operations: Oil and gas sales $2,683 $7,093 Production tax and marketing expenses 474 1,506 Lease operating expenses 1,288 1,216 Depletion 1,017 1,734 Depreciation 92 75 Net Production: Oil (MBbl) 1 45 Natural gas (MMcf) 1,394 1,449 Mmcfe 1,400 1,719 Average Sales Price Realized (1): Oil (per Bbl) $16.88 $25.27 Natural gas (per Mcf) $1.91 $4.11 Per Mcfe $1.92 $4.13 Average Cost Data (per Mcfe): Production tax and marketing expenses $0.34 $0.88 Lease operating expenses $0.92 $0.70 Depletion $0.73 $1.01 Depreciation $0.06 $0.04
_________________ (1) Includes effects of hedging. Three Months Ended March 31, 2002 Compared to March 31, 2001 Revenue. Revenue for first quarter 2002 decreased 63% to $2,696,000 from $7,330,000 for first quarter 2001. Oil and gas sales for first quarter 2002 decreased 62% to $2,683,000 from $7,093,000 for first quarter 2001 due to lower oil production as a result of the sale of the Delaware Basin properties in September 2001 and lower gas prices realized. Average oil prices per barrel for first quarter 2002 decreased 33% to $16.88 from $25.27 for first quarter 2001. Average gas prices per Mcf for first quarter 2002 decreased 54% to $1.91 from $4.11 for first quarter 2001. Oil production for first quarter 2002 decreased 98% to 1,000 barrels from 45,000 barrels for first quarter 2001 as a result of the Delaware Basin sale and gas production for first quarter 2002 decreased 4% to 1,394,000 Mcf from 1,449,000 Mcf for first quarter 2001. Production Tax and Marketing Expenses. Production tax and marketing expenses decreased 69% to $474,000 in first quarter 2002 from $1,506,000 in first quarter 2001, primarily due to lower oil production and lower gas prices. Production taxes are calculated and paid on prices before hedging gains or losses. As a percentage of sales before hedging losses, production tax and marketing expenses were 16% in first quarter 2002 and 15% in first quarter 2001. Production tax and marketing expenses per Mcfe decreased 61% to $0.34 from $0.88. Lease Operating Expenses. Lease operating expenses increased 6% to $1,288,000 in first quarter 2002 from $1,216,000 in first quarter 2001. Lease operating expenses per Mcfe increased 31% to $0.92 in first quarter 2002 from $0.70 per Mcfe in the 2001 quarter due to the accrual of $358,000 for the possessory interest tax in 2002. Depreciation, Depletion and Amortization. First quarter 2002 depreciation, depletion and amortization decreased 36% to $1,244,000 from $1,959,000 in first quarter 2001. Depletion per Mcfe decreased 28% to $0.73 from $1.01, due to the lower capitalized costs subsequent to the September 2001 sale of Delaware Basin properties and provision for impairment. General and Administrative Expenses. Net general and administrative expenses for first quarter 2002 decreased 65% to $475,000 from $1,355,000 in first quarter 2001, primarily due to stock compensation expense. As a result of fluctuations in the market price of the Company's common stock, and employee stock options with a below-market strike price, which require mark-to-market accounting, and issuance of restricted stock, the Company recognized a reduction to general and administrative expense of $440,000 in the first quarter of 2002, whereas the Company recognized $579,000 of expense in the 2001 quarter. Interest and Other Expenses. Interest and other expenses for first quarter 2002 decreased 46% to $962,000 from $1,788,000 for first quarter 2001. The decrease was primarily due to a lower outstanding debt balance in the 2002 quarter as proceeds from the September 2001 Delaware Basin sale were used to pay down debt. Income Taxes. We incurred net operating losses for U.S. Federal income tax purposes in 2002 and 2001, which can be carried forward to offset future taxable income. Statement of Financial Accounting Standards No. 109 requires that a valuation allowance be provided if it is more likely than not that some portion or all of a deferred tax asset will not be realized. Our ability to realize the benefit of our deferred tax asset will depend on the generation of future taxable income through profitable operations and the expansion of our oil and gas producing activities. The market and capital risks associated with achieving the above requirement are considerable, resulting in our decision to provide a valuation allowance equal to the net deferred tax asset. Accordingly, we did not recognize any tax expense or benefit in the consolidated statements of operations for the first quarters of 2002 and 2001. Net Loss. We had a net loss of $1,772,000 for first quarter 2002 compared to net loss of $494,000 for first quarter 2001 as a result of the factors discussed above. We paid the 8% dividend of $16,000 on our $800,000 face amount Series B Mandatorily Redeemable Convertible Preferred Stock in the quarter ended March 31, 2001, and realized accretion of $2,000. In addition, during first quarter 2002 and 2001 we realized accretion of $164,000 and $144,000, respectively, on the Mandatorily Redeemable Common Stock. Net loss attributable to common shareholders for the quarter ended March 31, 2002 was $1,936,000 compared to $656,000 for the quarter ended March 31, 2001. Hedging Activities We use hedging instruments to manage commodity price risks. We have used energy swaps and other financial arrangements to hedge against the effects of fluctuations in the sales prices for oil and natural gas. Gains and losses on such transactions are matched to product sales and charged or credited to oil and gas sales when that product is sold. Management believes that the use of various hedging arrangements can be a prudent means of protecting our financial interests from the volatility of oil and gas prices. Under our Aquila Credit Agreement, we may be required to maintain price hedging arrangements in place with respect to up to 65% of our oil and gas production upon terms satisfactory to us and Aquila. We recognized a hedging gain (loss) of $263,000 and $(2,914,000) in first quarter 2002 and 2001, respectively. These amounts are included in oil and gas sales in our consolidated statements of operations. Miscellaneous Our oil and gas operations are significantly affected by certain provisions of the Internal Revenue Code applicable to the oil and gas industry. Current law permits our intangible drilling and development costs to be deducted currently, or capitalized and amortized over a five-year period. We, as an independent producer, are also entitled to a deduction for percentage depletion with respect to the first 1,000 barrels per day of domestic crude oil (and/or equivalent units of domestic natural gas) produced (if such percentage depletion exceeds cost depletion). Generally, this deduction is 15% of gross income from an oil and gas property, without reference to the taxpayer's basis in the property. The percentage depletion deduction may not exceed 100% of the taxable income from a given property. Further, percentage depletion is limited in the aggregate to 65% of our taxable income. Any depletion disallowed under the 65% limitation, however, may be carried over indefinitely. Inflation has not historically had a material impact on our financial statements, and management does not believe that we will be materially more or less sensitive to the effects of inflation than other companies in the oil and gas industry. The preceding information contains forward-looking statements, the realization of which cannot be assured. Actual results may differ significantly from those forecast. When evaluating us, our operations, or our expectations, the reader should bear in mind that we and our operations are subject to numerous risks and uncertainties. Among these are risks related to the oil and gas business generally (including operating risks and hazards and the regulations imposed thereon), risks and uncertainties related to the volatility of the prices of oil and gas, uncertainties related to the estimation of reserves of oil and gas and the value of such reserves, uncertainties relating to geologic models and evaluations, the effects of competition and extensive environmental regulation, and other factors, many of which are necessarily beyond our control. These and other risk factors that affect our business are discussed in our 2001 Form 10-K. Item 3. Quantitative and Qualitative Disclosures about Market Risk We use commodity derivative financial instruments, including swaps, to reduce the effect of natural gas price volatility on a portion of our natural gas production. Commodity swap agreements are generally used to fix a price at the natural gas market location or to fix a price differential between a benchmark price of natural gas and the price of gas at its market location. Settlements are based on the difference between a fixed and a variable price as specified in the agreement. The following table summarizes our derivative financial instrument position on our natural gas production as of March 31, 2002. The fair value of these instruments reflected below is the estimated amount that we would receive (or pay) to settle the contracts as of March 31, 2002. Actual settlement of these instruments when they mature will differ from these estimates reflected in the table. Gains or losses realized from these instruments hedging our production are expected to be offset by changes in the actual sales price received by us for our natural gas production. See "Hedging Activities" above.
Fixed Price Year MMBtu per MMBtu Fair Value 2002 1,101,000 $2.55-$3.38 $ (810,000) 2003 996,000 $2.55 (1,118,000) 2004 852,000 $2.55 (955,000)
In addition, we entered into a basis swap to fix the differential between the NYMEX price and the index price at which the hedged gas is to be sold for 2,949,000 MMBtu for 2001 - 2004 with a fair value of $(20,000). The table below provides information about our financial instruments sensitive to changes in interest rates, including debt obligations. The table presents principal cash flows and related weighted average interest rates by expected maturity dates.
Expected Maturity (In thousands) 2002 2003 2004 2005 2006 Thereafter Fair Value Long-term debt: Fixed rate $391 $ 586 $3,514 $17 $ 41 $ -- $ 4,549 Average interest rate 12.7% 12.7% 12.8% 8.0% 8.0% -- Variable rate $ -- $27,511 $ -- $ -- $ -- $ -- $27,511 Average interest rate -- 8.75% -- -- -- --
PART II -- OTHER INFORMATION Item 1. Legal Proceedings The information contained in Note 7 to the consolidated financial statements set forth in Part I is hereby incorporated by reference. Item 6. Exhibits and Reports on Form 8-K (a) Exhibits: None. (b) Reports on Form 8-K: During the quarter for which this report is filed, the Company filed a Current Report on Form 8-K dated February 8, 2002 under "Item 5. Other Events", relating to the Second Amendment to Credit Agreement dated September 9, 1999, by and between Mallon Resources Corporation, Mallon Oil Company and Aquila Energy Capital Corporation. The Amendment was attached under Item 7, as Exhibit 10.25. Subsequent to March 31, 2002, the Company also filed Current Reports on Form 8-K, under "Item 5. Other Events", dated April 4, 2002 and May 2, 2002. The April 4, 2002 report related to the execution of a letter of intent to explore and develop the Fruitland Formation coal seam that underlie Mallon's East Blanco Gas Project in the San Juan Basin of New Mexico with Smart Exploration, Inc. The May 2, 2002 report related to the retirement of Frank Douglass from, and the appointment of Christopher H.B. Mills to, the Company's Board of Directors. SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. MALLON RESOURCES CORPORATION Registrant Date: May 15, 2002 By: /s/ Roy K. Ross Roy K. Ross Executive Vice President Date: May 15, 2002 By: /s/ Alfonso R. Lopez Alfonso R. Lopez Vice President, Finance/Treasurer -----END PRIVACY-ENHANCED MESSAGE-----