-----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, JUEev9pOtxPt/Gusu1s+wfmlSM4FbTM4WzeNOcygs5bgvlvJAayICRLD/mrL7LYl kJBRI11gBkQZLi7K9qvy2A== 0000837759-01-500007.txt : 20010516 0000837759-01-500007.hdr.sgml : 20010516 ACCESSION NUMBER: 0000837759-01-500007 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20010331 FILED AS OF DATE: 20010515 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: SEC FILE NUMBER: 001-13124 FILM NUMBER: 1635698 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 q1edgar.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, 2001. - - 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 11, 2001, 10,646,094 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, 2001 2000 (Unaudited) Current assets: Cash and cash equivalents $ 11,013 $ 14,155 Accounts receivable: Oil and gas sales 2,427 3,460 Joint interest participants, net of allowance of $39 and $39, respectively 275 353 Related parties 1 1 Other 63 18 Inventories 193 215 Other 2,042 123 Total current assets 16,014 18,325 Property and equipment: Oil and gas properties, full cost method 127,642 120,972 Natural gas processing plant 8,569 8,560 Other property and equipment 1,117 1,112 137,328 130,644 Less accumulated depreciation, depletion and amortization (60,896) (59,057) 76,432 71,587 Notes receivable-related parties -- 7 Debt issuance costs, net 1,413 1,529 Other, net 260 262 Total Assets $ 94,119 $ 91,710
(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, 2001 2000 (Unaudited) Current liabilities: Trade accounts payable $ 3,511 $ 3,689 Undistributed revenue 2,056 2,045 Accrued taxes and expenses 77 35 Derivative liability 5,117 -- Current portion of long-term debt 10,105 12,179 Total current liabilities 20,866 17,948 Long-term debt, net of unamortized discount of $2,598 and $2,813, respectively 44,597 40,180 Derivative liability 5,981 -- 50,578 40,180 Total liabilities 71,444 58,128 Commitments and contingencies (Note 6) Series B Mandatorily Redeemable Convertible Preferred Stock, $0.01 par value, 500,000 shares authorized, 80,000 shares issued and outstanding, liquidation preference and mandatory redemption of $800 800 798 Mandatorily Redeemable Common Stock, $0.01 par value, 490,000 shares authorized, issued and outstanding, mandatory redemption of $6,125 4,392 4,248 Shareholders' equity: Common Stock, $0.01 par value, 25,000,000 shares authorized; 10,140,093 and 10,115,093 shares issued and outstanding, respectively 101 101 Additional paid-in capital 93,040 92,456 Accumulated deficit (61,649) (61,155) Other comprehensive loss (11,098) -- Notes receivable from shareholders (2,911) (2,866) Total shareholders' equity 17,483 28,536 Total Liabilities and Shareholders' Equity $ 94,119 $ 91,710
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, 2001 2000 (Unaudited) Revenues: Oil and gas sales $ 7,093 $ 3,920 Interest and other 237 62 7,330 3,982 Costs and expenses: Production tax and marketing 1,506 557 Lease operating 1,216 1,106 Depreciation, depletion and amortization 1,959 1,441 General and administrative, net 1,355 1,190 Interest and other 1,788 1,319 7,824 5,613 Net loss (494) (1,631) Dividends and accretion on preferred stock (18) (30) Accretion of mandatorily redeemable common stock (144) (98) Net loss attributable to common shareholders $ (656) $(1,759) Basic: Net loss per share attributable to common shareholders $ (0.06) $ (0.22) Weighted average common shares outstanding 10,627 7,836
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, 2001 2000 (Unaudited) Cash flows from operating activities: Net loss $ (494) $(1,631) Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation, depletion and amortization 1,959 1,441 Accrued interest expense added to long-term debt 1,401 912 Accrued interest income added to notes receivable from shareholders (45) (46) Amortization of discount on long-term debt 215 163 Stock compensation expense 579 366 Changes in operating assets and liabilities: Decrease (increase) in: Accounts receivable 1,066 89 Inventory and other assets (1,897) (168) (Decrease) increase in: Trade accounts payable and undistributed revenue (166) 837 Accrued taxes and expenses 39 17 Net cash provided by operating activities 2,657 1,980 Cash flows from investing activities: Additions to property and equipment (6,517) (4,304) Other 7 70 Net cash used in investing activities (6,510) (4,234) Cash flows from financing activities: Proceeds from long-term debt 837 2,824 Payments of long-term debt (110) (96) Payment of preferred dividends (16) (27) Other -- 4 Net cash provided by financing activities 711 2,705 Net (decrease) increase in cash and cash equivalents (3,142) 451 Cash and cash equivalents, beginning of period 14,155 1,230 Cash and cash equivalents, end of period $11,013 $1,681 Supplemental cash flow information: Cash paid for interest $ 173 $ 206
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 (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. The Company 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 generally accepted accounting principles 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 2000 Form 10-K. Certain prior year amounts in the consolidated financial statements have been reclassified to conform to the presentation used in 2001. NOTE 2. LONG-TERM DEBT Long-term debt consists of the following:
March 31, December 31, 2001 2000 Note payable to Aquila Energy Capital Corporation, due 2003 $ 52,281 $ 50,042 Less unamortized discount (2,598) (2,813) 49,683 47,229 Lease obligation to Universal Compression, Inc. 4,899 5,006 8.5% unsecured note payable to Bank One, Colorado, N.A., due 2002 120 124 54,702 52,359 Less current portion (10,105) (12,179) Total $ 44,597 $ 40,180
In September 1999, the Company established a credit agreement (the "Aquila Credit Agreement") with Aquila Energy Capital Corporation ("Aquila"). The amount available under the agreement, as amended, is $53.4 million. The amount available may be increased to as much as $60 million as new reserves are added through the Company's planned development drilling program. At March 31, 2001, the Company had drawn $52.3 million, including accrued interest, under the Aquila Credit Agreement. Principal payments on the four-year loan are based on the Company's cash flow from operations, as defined ("the Defined Cash Flow"), less advances for the Company's development program. As of March 31, 2001, the advances exceeded cash flow from operations and the Company had not made any principal payments. The Company had expected to begin making principal payments in March 2001 and paid Aquila $1.4 million on April 6, 2001. On March 30, 2001, Aquila agreed to waive the requirement for principal payments equal to the Defined Cash Flow. Instead, the repayment schedule for the twelve months beginning April 30, 2001 is as follows: (i) for the months April 2001 to September 2001, the Company will pay interest only, or approximately $2.5 million, and (ii) from October 2001 to March 2002, the Company will make monthly principal and interest payments of $700,000 or a total of $4.2 million. Aquila will evaluate the loan monthly and, at its sole discretion, can discontinue the repayment schedule described above and revert to the requirement of principal payments equal to Defined Cash Flow. Due to Aquila's unilateral ability to modify the repayment schedule described above, the Company has classified $9.6 million of the Aquila debt as current, based on the Company's best estimate of Defined Cash Flow for the twelve month period ending March 31, 2002. The Company anticipates the Aquila Credit Agreement will be amended during second quarter 2001 to reflect the changes described above. The Company will continue to seek to increase the amount available under the Aquila Credit Agreement and to revise the repayment requirements. However, there can be no assurance that the Company will be successful in its efforts to further amend the Aquila Credit Agreement. During first quarter 2001, the Company repaid $106,000 of lease obligation to Universal Compression and $4,000 of unsecured note payable to Bank One. NOTE 3. 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, 2001 and 2000 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 4. HEDGING ACTIVITY On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS No. 137 and SFAS No. 138. Under SFAS No. 133, all derivative instruments are recorded on the balance sheet at fair value. If the derivative does not meet specific hedge accounting criteria or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings. If the derivative qualifies for hedge accounting, the gain or loss on the derivative is deferred in other comprehensive income/loss, a component of shareholders' equity, to the extent the hedge is effective. The Company periodically enters into derivative commodity instruments to hedge its exposure to price fluctuations on natural gas and crude oil production. 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, 2001, the Company had outstanding agreements to hedge a total of 201,000 barrels of oil related to production for 2001-2004 at fixed prices ranging from $17.38-$18.30 per barrel and to hedge a total of 5,105,000 MMBtu of gas related to production for 2001-2004 at a fixed price ranging between $2.55-$3.94 per MMBtu. In addition, the Company has outstanding at March 31, 2001 basis swaps to fix the differential between the NYMEX price and the index price at which the hedged gas is to be sold for 5,105,000 MMBtu for 2001-2004, and "costless collar" contracts pursuant to which the Company hedged the price of 60,000 MMBtu per month in 2001 based on an El Paso-Permian Index. The Company will receive $3.85 per MMBtu if the settlement price is below $3.85 per MMBtu. If the settlement price is greater than $5.80 per MMBtu, the Company will pay the difference between such settlement price and $5.80 per MMBtu. All hedge transactions are subject to the Company's risk management policy, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. At March 31, 2001, the Company has recorded a current derivative liability of $5.1 million, a long-term derivative liability of $6.0 million and an unrealized loss of $11.1 million in other comprehensive loss. No related income tax effects were recorded because of the Company's net operating loss carryforwards. On January 1, 2001, in accordance with the transition provisions of SFAS No. 133, the Company recorded a loss of $15.2 million in accumulated other comprehensive loss representing the cumulative effect of an accounting change to recognize at fair value all cash flow derivatives. The Company recorded corresponding cash flow hedge derivative liabilities of $15.2 million. During the first quarter of 2001, losses of $2.9 million were transferred from accumulated other comprehensive loss to oil and gas revenues related to settled positions and an unrealized gain of $1.2 million was recorded to other comprehensive income to adjust the fair value of the open positions. The Company expects to reclassify as reductions to earnings during the next twelve months approximately $5.1 million of unrealized hedging losses in accumulated other comprehensive loss at March 31, 2001. NOTE 5. 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 Company recorded other comprehensive loss for the first time in the first quarter of 2001. The following table illustrates the change in accumulated other comprehensive loss for the quarter ended March 31, 2001:
(in thousands) Accumulated other comprehensive loss - December 31, 2000 $ -- Net loss (494) Other comprehensive loss: Cumulative effect of change in accounting principle - January 1, 2001 (15,171) Reclassification adjustment for settled hedging contracts 2,914 Changes in fair value of outstanding hedging positions 1,159 Other comprehensive loss (11,098) Accumulated other comprehensive loss - March 31, 2001 $(11,592)
NOTE 6. CONTINGENCIES In February 2001, the Revenue and Taxation Department of the Jicarilla Apache Nation (the "Nation") issued to the Company Possessory Interest Tax assessments for 1998, 1999 and 2000 totaling $1,651,700. The Company has filed a protest with the Nation and has taken 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. As of March 31, 2001, the Company had paid an adjusted amount of approximately $1.8 million, including approximately $150,000 of accrued interest under protest. This amount is included in the Company's March 31, 2001 consolidated balance sheet under other current assets. Subsequent to March 31, 2001, the Company was assessed an additional $1.9 million of taxes and penalties, of which $1.1 million is related to the assessment for 2001. The Company has paid approximately $700,000 of the additional assessments for 1998, 1999 and 2000 as of May 10, 2001, again under protest, and expects to pay the 2001 assessment, under protest, in May 2001. The Company has: 1) requested that the Legislative Council of the Jicarilla Apache Nation grant the Company relief, and 2) engaged New Mexico counsel to represent it. The final outcome of this matter cannot yet be predicted. In December 1998, Del Mar Drilling Company ("Plaintiff") filed a civil action against Mallon Oil. Plaintiff sought damages for an alleged breach of contract in the amount of $348,100, plus interest, costs and attorney's fees. In March 2001, the Company settled with the Plaintiff by paying the Plaintiff $50,000 in cash, and conveying to Plaintiff certain used drilling materials having an estimated value of $14,000. NOTE 7. SUBSEQUENT EVENT In April 2001, the Company redeemed the remaining 80,000 shares outstanding of its Series B Mandatorily Redeemable Convertible Preferred Stock, at the mandatory redemption price of $10 per share, for $803,000 including accrued dividends. 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, 2001 and December 31, 2000, and results of operations and cash flows for the three months ended March 31, 2001 and 2000. 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 and Delaware Basins, 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 oil and gas reserves that we may produce economically. Liquidity and Capital Resources Our operations are capital intensive. Historically, our principal sources of capital have been cash flow from operations, borrowings and proceeds from the sale of stock. Our principal uses of capital have been for the acquisition, exploration and development of oil and gas properties and related facilities. During first quarter 2001, our capitalized costs incurred in oil and gas producing activities were $6.7 million. Our current 2001 capital expenditure budget is approximately $23 million. During first quarter 2001, we drilled 12 wells, of which 11 were successful, and recompleted one well. Through May 10, 2001, we have drilled an additional six wells. We are currently planning on drilling a total of 33 wells in 2001. We expect to fund our capital requirements for the next 12 months out of the proceeds from our October 2000 equity offering, cash flow from operations, and possible additional financing. In September 1999, the Company established a credit agreement (the "Aquila Credit Agreement") with Aquila Energy Capital Corporation ("Aquila"). The amount available under the agreement, as amended, is $53.4 million. By its current terms, the amount available may be increased to as much as $60 million as new reserves are added through the Company's planned development drilling program. At March 31, 2001, the Company had drawn $52.3 million, including accrued interest, under the Aquila Credit Agreement. However, under the current terms of the Aquila Credit Agreement, the remaining $1.1 million nominally available may not be drawn for capital expenditures. Principal payments on the four-year loan are based on the Company's cash flow from operations, as defined ("the Defined Cash Flow"), less advances for the Company's development program. As of March 31, 2001, the advances exceeded cash flow from operations and the Company had not made any principal payments. The Company had expected to begin making principal payments in March 2001 and paid Aquila $1.4 million on April 6, 2001. On March 30, 2001, Aquila agreed to waive the requirement for principal payments equal to the Defined Cash Flow. Instead, the repayment schedule for the twelve months beginning April 30, 2001 is as follows: (i) for the months April 2001 to September 2001, the Company will pay interest only, or approximately $2.5 million, and (ii) from October 2001 to March 2002, the Company will make monthly principal and interest payments of $700,000 or a total of $4.2 million. Aquila will evaluate the loan monthly and, at its sole discretion, can discontinue the repayment schedule described above and revert to the requirement of principal payments equal to Defined Cash Flow. The Company anticipates the Aquila Credit Agreement will be amended during second quarter 2001 to reflect the changes described above. The Company will continue to seek to increase the amount available under the Aquila Credit Agreement and to revise the repayment requirements. However, there can be no assurance that the Company will be successful in its efforts to further amend the Aquila Credit Agreement. The Aquila Credit Agreement is secured by substantially all of our oil and gas properties. Interest on the Aquila Credit Agreement accrues at prime plus 2% and was added to the loan balance through March 31, 2001. The outstanding loan balance is due in full on September 9, 2003. As part of the Aquila financing, we also entered into a four year agency agreement with Aquila under which we pay a marketing fee equal to 1% of the net proceeds (as defined) from the sale of all of our oil and gas production to market our gas and to negotiate our gas purchase contracts. In addition, we also issued to Aquila 490,000 shares of common stock. Aquila also has a one-time right to require us to purchase 490,000 of our common shares from Aquila at $12.50 per share during the 30-day period beginning September 9, 2003. We are currently considering options to secure additional capital to continue our active drilling and development program through 2001. The options include the issuance of preferred or other equity securities. However, there is no assurance that we will be able to obtain additional funding. In September 1999 we also entered into a five-year, $5.5 million master rental contract with Universal Compression, Inc. to refinance our East Blanco gas sweetening plant. The proceeds from that financing were used to repay a term loan from Bank One, Texas, N.A. that was secured by the plant. The master rental contract bears interest at an imputed rate of 12.8%. We made principal payments totaling $106,000 to Universal Compression during first quarter 2001. In July 1998, we negotiated an unsecured term loan for up to $205,000 with Bank One, Colorado, N.A. to finance the purchase of land and a building for our field office. We drew $155,000 on this loan during 1998. We repaid $4,000 of this loan during first quarter 2001. Under the mandatory redemption feature of our Series B Mandatorily Redeemable Convertible Preferred Stock we were required to, and did, redeem the remaining 80,000 shares in April 2001 at the mandatory redemption price of $10.00 per share. In April 2000, the Government of Costa Rica awarded the Company a concession to explore for oil and natural gas on approximately 2.3 million acres in the northeast quadrant of Costa Rica. The Company has completed an environmental assessment of its proposed operations, and is currently in the process of negotiating final concession contracts. Once the Company signs final contracts, the work program is expected to require the expenditure of approximately $8.8 million (including the drilling of six wells) over a three-year period, with a possible extension of three more years.
Results of Operations Three Months Ended March 31, 2001 2000 (In thousands, except per unit data) Operating Results from Oil and Gas Operations: Oil and gas sales $7,093 $3,920 Production tax and marketing expenses 1,506 557 Lease operating expenses 1,216 1,106 Depletion 1,734 1,251 Depreciation 75 44 Net Production: Oil (MBbl) 45 43 Natural gas (MMcf) 1,449 1,444 Mmcfe 1,719 1,702 Average Sales Price Realized (1): Oil (per Bbl) $25.27 $23.84 Natural gas (per Mcf) $4.11 $2.00 Per Mcfe $4.13 $2.30 Average Cost Data (per Mcfe): Production tax and marketing expenses $0.88 $0.33 Lease operating expenses $0.70 $0.65 Depletion $1.01 $0.74 Depreciation $0.04 $0.03
_________________ (1) Includes effects of hedging. Three Months Ended March 31, 2001 Compared to March 31, 2000 Revenues. Total revenues for first quarter 2001 increased 84% to $7,330,000 from $3,982,000 for first quarter 2000. Oil and gas sales for first quarter 2001 increased 81% to $7,093,000 from $3,920,000 for first quarter 2000 primarily due to higher oil and gas prices realized. Average oil prices per barrel for first quarter 2001 increased 6% to $25.27 from $23.84 for first quarter 2000. Average gas prices per Mcf for first quarter 2001 increased 106% to $4.11 from $2.00 for first quarter 2000. Oil production for first quarter 2001 increased 5% to 45,000 barrels from 43,000 barrels for first quarter 2000 and gas production for first quarter 2001 remained flat at 1,449,000 Mcf from 1,444,000 Mcf for first quarter 2000. During first quarter 2001, the Company drilled 11 successful wells and recompleted one well. Two wells were put on production at the end of March and the remainder are expected to be put on production in second quarter 2001. Production Tax and Marketing Expenses. Production tax and marketing expenses increased 170% to $1,506,000 in first quarter 2001 from $557,000 in first quarter 2000, primarily due to higher oil and gas prices and higher tax rates in 2001. 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 15% in first quarter 2001 and 13% in first quarter 2000. Production tax and marketing expenses per Mcfe increased 167% to $0.88 from $0.33. Lease Operating Expenses. Lease operating expenses increased 10% to $1,216,000 in first quarter 2001 from $1,106,000 in first quarter 2000. Lease operating expenses per Mcfe increased 8% to $0.70 in first quarter 2001 from $0.65 per Mcfe in the 2000 quarter due to increased surface maintenance and waste water disposal costs. Depreciation, Depletion and Amortization. First quarter 2001 depreciation, depletion and amortization increased 36% to $1,959,000 from $1,441,000 in first quarter 2000. Depletion per Mcfe increased 36% to $1.01 from $0.74, due to a higher ratio of increases in capital expenditures relative to increases in reserves. General and Administrative Expenses. Net general and administrative expenses for first quarter 2001 increased 14% to $1,355,000 from $1,190,000 in first quarter 2000, primarily due to higher stock compensation expense in the 2001 quarter, as a result of the issuance of employee stock options with a below-market strike price and issuance of restricted stock. Interest and Other Expenses. Interest and other expenses for first quarter 2001 increased 36% to $1,788,000 from $1,319,000 for first quarter 2000. The increase was primarily due to a higher outstanding debt balance in the 2001 quarter. Income Taxes. We incurred net operating losses for U.S. Federal income tax purposes in 2001 and 2000, 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 2001 and 2000. Net Loss. We had a net loss of $494,000 for first quarter 2001 compared to net loss of $1,631,000 for first quarter 2000 as a result of the factors discussed above. We paid the 8% dividend of $16,000 and $27,000 on our $800,000 face amount Series B Mandatorily Redeemable Convertible Preferred Stock in the quarters ended March 31, 2001 and 2000, respectively, and realized accretion of $2,000 and $3,000, respectively. In addition, during first quarter 2001 and 2000 we realized accretion of $144,000 and $98,000, respectively, on the Mandatorily Redeemable Common Stock. Net loss attributable to common shareholders for the quarter ended March 31, 2001 was $656,000 compared to $1,759,000 for the quarter ended March 31, 2000. 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 hedging losses of $2,914,000 and $527,000 in first quarter 2001 and 2000, 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 2000 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 and crude oil price volatility on a portion of our natural gas and crude oil production. Commodity swap agreements are generally used to fix a price at the natural gas or crude oil market location or to fix a price differential between a benchmark price of natural gas and crude oil and the price of gas or crude oil 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 and crude oil production as of March 31, 2001. 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, 2001. 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 and crude oil production. See "Hedging Activities" above.
Natural Gas: Fixed Price Year MMBtu per MMBtu Fair Value 2001 1,699,000 $2.55-$3.94 $(3,696,000) 2002 1,558,000 $2.55-$3.91 (2,900,000) 2003 996,000 $2.55 (1,593,000) 2004 852,000 $2.55 (1,324,000) Crude Oil: Fixed Price Year Bbls per Bbl Fair Value 2001 45,000 $17.38-$18.30 $(374,000) 2002 60,000 $17.40 (431,000) 2003 48,000 $17.40 (266,000) 2004 48,000 $17.40 (238,000)
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 5,105,000 MMBtu for 2001 - 2004 with a fair value of $(88,000). We also entered into "costless collar" contracts pursuant to which we hedged the price of 60,000 MMBtu per month in 2001 based on an El Paso- Permian Index. We will receive $3.85 per MMBtu if the settlement price is below $3.85 per MMBtu. If the settlement price is greater than $5.80 per MMBtu, we will pay the difference between such settlement price and $5.80 per MMBtu. At March 31, 2001, the fair value of the put and call contracts was a loss of $(188,000). PART II -- OTHER INFORMATION Item 1. Legal Proceedings The information contained in Note 6 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 first quarter 2001, the Company filed two Periodic Reports on Form 8-K dated March 13, 2001 and March 19, 2001, each related to an "Item 5. Other Events" matter. 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, 2001 By: /s/ Roy K. Ross Roy K. Ross Executive Vice President Date: May 15, 2001 By: /s/ Alfonso R. Lopez Alfonso R. Lopez Vice President, Finance/Treasurer -----END PRIVACY-ENHANCED MESSAGE-----