> SECURITIES AND EXCHANGE COMMISSIONWashington, 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 June 30, 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
> 0-17267
> 84-1095959(State or other
> jurisdiction
> of incorporation)
> (Commission
> File Number)
> (I.R.S. Employer
> Identification No.)
> 
> 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 August 7, 2002, 11,119,052 shares of 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
> June 30,
> December 31,2002
> 2001(Unaudited)Current assets:Cash and cash equivalents
> 
> $  2,062
> $  1,943Accounts receivable:Oil and gas sales
> 
> 621
> 714Joint interest participants
> 
> 61
> 303Inventories
> 
> 151
> 151Derivative asset
> 
> --
> 229Prepaid expense and other
> 
> 118
> 38Total current assets
> 
> 3,013
> 3,378Property and equipment:Oil and gas properties, full cost method
> 
> 94,705
> 93,933Natural gas processing plant
> 
> 8,659
> 8,648Other property and equipment
> 
> 1,088
> 1,085104,452
> 103,666Less accumulated depreciation, depletion and amortization
> 
> (72,681)
> (70,414)31,771
> 33,252Debt issuance costs, net
> 
> 687
> 1,041Other, net
> 
> 347
> 300Total Assets
> 
> $ 35,818
> $ 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
> 
> June 30,
> December 31,2002
> 2001(Unaudited)Current liabilities:Trade accounts payable
> 
> $  1,846
> $  2,153Undistributed revenue
> 
> 528
> 612Accrued taxes and expenses
> 
> 188
> 42Derivative liability
> 
> 878
> --Current portion of long-term debt, net of unamortizeddiscount of $1,428 and $0, respectively
> 
> 28,375
> 517Total current liabilities
> 
> 31,815
> 3,324Long-term debt, net of unamortized discount of $0 and$1,899, respectively
> 
> 3,872
> 28,970Derivative liability
> 
> 1,861
> 1,4235,733
> 30,393Total liabilities
> 
> 37,548
> 33,717Commitments and contingenciesSeries B Mandatorily Redeemable Convertible Preferred Stock,$0.01 par value, 500,000 shares authorized, -0- sharesissued and outstanding
> 
> --
> --Mandatorily Redeemable Common Stock, $0.01 par value, 490,000shares authorized, issued and outstanding, mandatoryredemption of $6,125
> 
> 5,187
> 4,853Shareholders' equity:Common Stock, $0.01 par value, 25,000,000 sharesauthorized; 10,378,827 and 10,252,827 shares issuedand outstanding, respectively
> 
> 104
> 103Additional paid-in capital
> 
> 92,673
> 93,012Accumulated deficit
> 
> (96,955)
> (92,520)Accumulated other comprehensive loss
> 
> (2,739)
> (1,194)Total shareholders' equity
> 
> (6,917)
> (599)Total Liabilities and Shareholders' Equity
> 
> $ 35,818
> $ 37,971The accompanying notes are an integral part of these consolidated financial statements.
> 
> 
> 
> 
> MALLON RESOURCES CORPORATION
> CONSOLIDATED STATEMENTS OF OPERATIONS(In thousands, except per share amounts)
> (Unaudited)
> 
> For the Three Months Ended June 30,
> 
> For the Six Months Ended June 30,2002
> 2001
> 
> 2002
> 2001Revenues:Oil and gas sales
> 
> $ 2,728
> $ 5,283
> 
> $ 5,411
> $12,376Interest and other
> 
> 5
> 120
> 
> 18
> 3572,733
> 5,403
> 
> 5,429
> 12,733Costs and expenses:Oil and gas production
> 
> 1,788
> 2,349
> 
> 3,550
> 5,071Depreciation, depletion and amortization
> 
> 1,364
> 2,125
> 
> 2,633
> 4,084General and administrative, net
> 
> 1,116
> 3,627
> 
> 1,591
> 4,982Interest and other
> 
> 1,128
> 1,613
> 
> 2,090
> 3,4015,396
> 9,714
> 
> 9,864
> 17,538Net loss
> 
> (2,663)
> (4,311)
> 
> (4,435)
> (4,805)Dividends and accretion on preferred stock
> 
> --
> (3)
> 
> --
> (21)Accretion of mandatorily redeemable common stock
> 
> (170)
> (148)
> 
> (334)
> (292)Net loss attributable to common shareholders
> 
> $(2,833)
> $(4,462)
> 
> $(4,769)
> $(5,118)Basic:Net loss attributable to common shareholders
> 
> $ (0.26)
> $ (0.42)
> 
> $ (0.44)
> $ (0.48)Weighted average shares outstanding
> 
> 10,868
> 10,653
> 
> 10,840
> 10,640The accompanying notes are an integral part of these consolidated financial statements.MALLON RESOURCES CORPORATION
> CONSOLIDATED STATEMENTS OF CASH FLOWS(In thousands)
> (Unaudited)
> 
> For the Six Months Ended June 30,2002
> 2001Cash flows from operating activities:Net loss
> 
> $(4,435)
> $ (4,805)Adjustments to reconcile net loss to net cash provided by (used in)operating activities:Depreciation, depletion and amortization
> 
> 2,633
> 4,084Accrued interest expense added to long-term debt
> 
> --
> 1,407Accrued interest income added to notes receivable fromrelated party shareholders
> 
> --
> (87)Amortization of discount on long-term debt
> 
> 658
> 440Non-cash stock compensation expense
> 
> (285)
> 2,510Partial forgiveness of notes receivable from related party shareholders
> 
> --
> 907Changes in operating assets and liabilities:(Increase) decrease in:Accounts receivable
> 
> 335
> 1,569Inventory and other assets
> 
> (72)
> (3,615)Increase (decrease) in:Trade accounts payable and undistributed revenue
> 
> (391)
> 379Accrued taxes and expenses
> 
> 146
> 554Drilling advances
> 
> --
> 41Net cash (used in) provided by operating activities
> 
> (1,411)
> 3,384Cash flows from investing activities:Additions to property and equipment
> 
> (759)
> (12,486)Other
> 
> --
> 7Net cash used in investing activities
> 
> (759)
> (12,479)Cash flows from financing activities:Proceeds from long-term debt
> 
> 2,500
> 858Payments of long-term debt
> 
> (211)
> (1,679)Redemption of preferred stock
> 
> --
> (800)Proceeds from stock option and warrants exercises
> 
> --
> 1Payment of preferred dividends
> 
> --
> (19)Other
> 
> --
> (2)Net cash provided by (used in) financing activities
> 
> 2,289
> (1,641)Net increase (decrease) in cash and cash equivalents
> 
> 119
> (10,736)Cash and cash equivalents, beginning of period
> 
> 1,943
> 14,155Cash and cash equivalents, end of period
> 
> $ 2,062
> $  3,419(Continued)
> 
> The accompanying notes are an integral part of these consolidated financial statements.MALLON RESOURCES CORPORATION
> CONSOLIDATED STATEMENTS OF CASH FLOWS(In thousands)
> (Unaudited)
> (Continued)
> For the Six MonthsEnded June 30,2002
> 2001Supplemental cash flow information:Cash paid for interest
> 
> $1,343
> $1,176Non-cash transactions:Receipt of oil and gas and real property in exchange fornotes receivable from executive officers
> 
> $     93
> $      --Issuance of common stock in connection with the Aquila CreditAgreement 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 (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 2001 Form 10-K.
> Certain prior year amounts in the consolidated financial statements have been reclassified to conform to the presentation used in 2002.
> The accompanying financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business.  As more fully discussed in Notes 2 and 3, the Company has suffered net losses since 1997 and has significant borrowings that require, among other things, repayment in 2003 and compliance with certain restrictive covenants.
> NOTE 2. CURRENT OPERATING ISSUES
> The Company generated net losses of $4.4 million, $31.4 million, $6.5 million and $2.8 million for the six months ended June 30, 2002 and for the years ended December 31, 2001, 2000 and 1999, respectively.  The Company's cash flows from operating activities were $(1.4) million, $1.1 million, $4.0 million and $2.4 million for the respective periods.
> The Company is currently in non-compliance with of a number of provisions of its credit agreement (the "Aquila Credit Agreement") with Aquila Energy Capital Corporation ("Aquila"), including provisions requiring the Company to maintain projected net revenue attributable to its proved reserves in an amount sufficient to fully amortize the outstanding loan balance by its maturity date, to satisfy or discharge liens filed against its properties within 30 days of their filing, and to pay its trade debt within 90 days of its due date.  As a result of these events of default, Aquila may, at its election, declare an acceleration of the debt to be currently due and payable, in full.  The Company has therefore classified all amounts owed under the Aquila Credit Agreement as current at June 30, 2002 in the accompanying consolidated balance sheets.  The Company is currently in negotiations with Aquila to address this situation, but is unable to predict the outcome of those discussions.  If the Company's debt is accelerated, the Company may not be able to repay the debt or borrow sufficient funds to refinance it.  Even if new financing is available, it may not be on terms that are acceptable to the Company.  Provided that Aquila does not seek immediate repayment under the Aquila Credit Agreement, management believes that cash on hand and cash generated from operating activities, will be sufficient to meet the Company's cash requirements through December 31, 2002.
> Responding to its financial challenges and lack of capital, the Company is actively exploring strategic alternatives including, but not limited to, potential asset divestitures, joint ventures, mergers, and other arrangements.  No assessment can be made of the likelihood that any transactions of this sort can be effectively implemented.  The Company's ability to operate as a going concern is dependent on its ability to successfully negotiate an extension of indebtedness with its lender or a successor lender.
> Because the Company's production 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 June 30, 2002, or if the Company is unable to maintain production levels at its San Juan Basin properties, the Company may have to implement additional cost cutting measures in both its administrative and operating areas.
> NOTE 3. LONG-TERM DEBT
> Long-term debt consists of the following:
> June 30,2002
> December 31,2001Note payable to Aquila Energy Capital Corporation, due 2003
> $ 29,211
> $26,711Less unamortized discount
> (1,428)
> (1,899)27,783
> 24,812Lease obligation to Universal Compression, Inc.
> 4,337
> 4,5678.0% unsecured note payable to Bank One, Colorado, N.A., due 2006
> 99
> 108Notes payable to officers
> 28
> --32,247
> 29,487Less current portion
> (28,375)
> (517)Total
> $  3,872
> $28,970
> 
> In September 1999, the Company established the Aquila Credit Agreement with Aquila.  In February 2002, the Company notified Aquila that, as of December 31, 2001, it had not been in compliance with the covenant under the Aquila Credit Agreement that requires the Company to maintain projected net revenue attributable to its proved reserves in an amount sufficient to fully amortize the outstanding balance under the Aquila Credit Agreement by its maturity date.  As a result, in February 2002, the Aquila Credit Agreement was amended for a second time.  The second amendment contains the following provisions:
> 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.
> 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.
> The amount available under the agreement was increased by $2.5 million.
> 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.
> 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.
> 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.
> The Company 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, the Company will issue Aquila an additional 150,000 shares.
> Upon a change of control of the Company occurring on or before September 30, 2002, the Company will pay Aquila $500,000.  If a change of control of the Company occurs after September 30, 2002, the Company will pay Aquila $1,250,000.
> Through June 30, 2002, the Company had drawn all $2,500,000 under provision (iii) above.
> The Aquila Credit Agreement requires the Company to satisfy or discharge liens filed against its properties within 30 days of their filing.  The failure to satisfy or discharge a lien claiming in excess of $250,000 within 30 days is an event of default under the Aquila Credit Agreement.  Upon such an event of default, Aquila may declare any or all obligations under the Aquila Credit Agreement to be immediately due and payable.  As more fully discussed in Note 9, on July 16, 2002, The Jicarilla Apache Indian Nation filed a lien against the Company's property located on the Jicarilla Reservation to secure the Company's payment of approximately $1.56 million of assessed possessory interest tax, including penalties and interest.  As of August 12, 2002, that lien has not been satisfied or discharged.  As more fully discussed in Note 2, the Company has classified all amounts owed under the Aquila Credit Agreement as current at June 30, 2002 in the accompanying consolidated balance sheets.
> Provided that Aquila does not seek immediate repayment under the Aquila Credit Agreement, principal payments 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 the first half of 2003 could range between $0 and $100,000.
> NOTE 4.  OIL AND GAS PROPERTIES
> Under the full cost accounting rules of the Securities and Exchange Commission, the Company reviews the carrying value of its oil and gas properties each quarter on a country-by-country basis.  Under full cost accounting rules, net capitalized costs of oil and gas properties, less related deferred income taxes, may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of cost or fair market value of unproved properties, as adjusted for related tax effects.  Application of these rules generally requires pricing future production at the unescalated oil and gas prices in effect at the end of each fiscal quarter and requires a write-down if the "ceiling" is exceeded, unless the prices recover subsequent to the balance sheet date but before the financial statements for the quarter are issued.  If a smaller write-down is calculated using the subsequent pricing, then the smaller amount may be recorded.  Using natural gas prices on August 13, 2002, no write-down was required.  Had the Company used the prices in effect at June 30, 2002, the write-down would have been $2,050,000.
> NOTE 5.  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).  The consolidated statements of operations for the six months ended June 30, 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 6. 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 June 30, 2002, the Company had price swaps covering 2,542,000 MMBtu of gas related to production for 2002-2004 at fixed prices ranging between $2.55-$3.28 per MMBtu.  In addition, the Company had outstanding at June 30, 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 2,542,000 MMBtu for 2002-2004.
> The following table indicates the Company's outstanding energy swaps at June 30, 2002:
> Product
> AnnualProduction
> Fixed Price
> Duration
> Market Price ReferenceGas (MMBtu)
> 694,000
> $2.55-$3.28
> 7/02-12/02
> 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 June 30, 2002, the Company had recorded a current derivative liability of $878,000, a long-term derivative liability of $1,861,000 and an unrealized loss of $2,739,000 in accumulated other comprehensive loss.  No related income tax effects were recorded because of the Company's net operating loss carryforward.
> During the six months ended June 30, 2002, gains of $217,000 were transferred from accumulated other comprehensive loss to oil and gas revenues related to settled positions and an unrealized loss of $1,328,000 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 $878,000 of unrealized hedging losses in accumulated other comprehensive loss at June 30, 2002.
> For the six months ended June 30, 2002 and 2001, the Company's gains (losses) under its swap agreements were $217,000 and $(3,875,000), respectively, and are included in oil and gas sales in the Company's consolidated statements of operations.  At June 30, 2002, the estimated net amount the Company would have paid to terminate its outstanding energy swaps and basis swaps, described above, was approximately $2,739,000.
> NOTE 7. 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 Six Months  Ended June 30,2002
> 2001Accumulated 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
> (217)
> 3,875Changes in fair value of outstanding hedging positions
> (1,328)
> 6,912Other comprehensive loss
> (1,545)
> (4,384)Accumulated other comprehensive loss - end of period
> $(2,739)
> $ (4,384)
> 
> NOTE 8. RELATED PARTY TRANSACTIONS
> Under the Company's "Stock Ownership Encouragement Program," in August 1999, two executive officers of the Company borrowed $1,585,018 and $391,284, respectively, from the Company that they used to exercise certain options owned by them.  The officers issued promissory notes to the Company in the noted amounts, which bore interest at the rate of 7% per annum, and were due August 31, 2004.  In June 2001, the Company's compensation committee reduced the amounts due under the notes to $230,548 and $56,914, respectively.  For accounting purposes, the Company treated this transaction as a repurchase of the common stock underlying the notes receivable, a cancellation of the notes receivable and the grant of options to purchase 287,462 shares of common stock at $1.00 per share.  In March 2002, one of the executive officers conveyed to the Company his interest in certain Costa Rica real property in exchange for his promissory note.  In April 2002, the other executive officer conveyed to the Company an undivided interest in Deep Gas, LLC in exchange for his promissory note.  These transactions were approved by the Company's compensation committee and have been recorded as $56,914 of other assets, $36,500 of oil and gas properties, and as $93,414 in additional paid in capital.
> NOTE 9. 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 $1.56 million, including penalties and interest, for 2002, of which $731,000 has been accrued and expensed at June 30, 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.  During July 2002, the Nation filed a lien against the Company's oil and gas properties located on the Jicarilla Reservation to secure the Company's payment of the 2002 assessment and related penalties and interest.  The final outcome of this matter cannot yet be predicted.
> In mid-November 2001, the Minerals Management Service began an audit of the royalties payable by the Company on production from certain oil and gas properties in which the Company owns an interest.  The audit is expected to cover, among other things, product valuation issues, including the point of royalty settlement, transportation and processing allowances, and accounting for comparison (dual accounting).  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 an interest in the resolution of the matters that arise out of the audit.  In December 2000, administrative decisions were rendered in the case relating to so-called "dual-accounting" and "major portion" matters.  The administrative rulings have been appealed to the United States District Court for the District of Columbia.  The primary issue in dispute is the manner in which so-called "major portion" prices are determined for purposes of the applicable dual accounting requirement.  The producers argue that the regulatory protocol requires evaluation of actual data gleaned from actual transactions.  Such information is not readily available and will require a concerted effort to accumulate.  By contrast, the Minerals Management Service suggests that, in the absence of a data base, the highest possible price allowed under the old Natural Gas Pricing Act should be used, even if (as is most generally the case) no gas was sold for those prices.  If the Minerals Management Service's proposal is upheld, the Company will be liable for additional unpaid royalties, interest and (perhaps) penalties.  If the producer's collection of actual data results in regulation-compliant numbers or a more reasonable compromise protocol is established, the Company's exposure for such items should be immaterial.  The final outcome of this matter cannot yet be predicted.
> NOTE 10. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
> In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets".  SFAS No. 142 addresses financial accounting and reporting for goodwill and other intangible assets.  The adoption of SFAS No. 144 by the Company on January 1, 2002, did not have any material impact on its financial position or results of operations.
> In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations".  SFAS No. 143 requires entities to record the fair value of liabilities for retirement obligations of acquired assets.  SFAS No. 143 is effective for fiscal years beginning after June 15, 2002.  The Company will adopt SFAS No. 143 on January 1, 2003, but has not yet quantified the effects of adopting SFAS No. 143 on its financial position or results of operations.
> In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets".  SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets to be Disposed Of".  SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale and requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations.  The adoption of SFAS No. 144 by the Company on January 1, 2002, did not have any material impact on its financial position or results of operations.
> In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections". SFAS No. 145 updates, clarifies and simplifies existing accounting pronouncements.  SFAS No. 4 required all gains or losses from extinguishments of debt to be classified as extraordinary items net of income taxes.  SFAS No. 145 requires that gains and losses from extinguishment of debt be evaluated under the provisions of APB Opinion No. 30, and be classified as ordinary items unless they are unusual or infrequent or meet the specific criteria for treatment as an extraordinary item.  SFAS No. 145 is effective for fiscal years beginning after May 15, 2002.  The Company does not expect the adoption of SFAS No. 145 to have a material impact on the Company's financial position or results of operations.
> In July 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities". SFAS No. 146 requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. The provisions of SFAS No. 146 are to be applied prospectively to exit or disposal activities initiated after December 31, 2002. The Company does not expect the adoption of SFAS No. 146 to have a material impact on the Company's financial position or results of operations.Item 2.  Management's Discussion and Analysis of Financial Condition and Results of OperationsThe following discussion is intended to assist in understanding our consolidated financial position at June 30, 2002 and December 31, 2001, results of operations for the three and six months ended June 30, 2002 and 2001 and cash flows for the six months ended June 30, 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 oil and gas reserves that we may produce economically.
> Liquidity and Capital Resources
> We have generated net losses of $4.4 million, $31.4 million, $6.5 million and $2.8 million for the six months ended June 30, 2002 and for the years ended December 31, 2001, 2000 and 1999, respectively.  Our cash flows from operating activities for the respective periods were $(1.4) million, $1.1 million, $4.0 million and $2.4 million.
> We are currently in non-compliance with of a number of provisions of our credit agreement (the "Aquila Credit Agreement") with Aquila Energy Capital Corporation ("Aquila"), including provisions requiring the Company to maintain projected net revenue attributable to its proved reserves in an amount sufficient to fully amortize the outstanding loan balance by its maturity date, to satisfy or discharge liens filed against its properties within 30 days of their filing, and to pay its trade debt within 90 days of its due date.  As a result of these events of default, Aquila may, at its election, declare an acceleration of the debt to be currently due and payable, in full. We have therefore classified all amounts owed under the Aquila Credit Agreement as current at June 30, 2002 in the accompanying consolidated balance sheets.  We are currently in negotiations with Aquila to address this situation, but we are unable to predict the outcome of those discussions.  If our debt is accelerated, we may not be able to repay the debt or borrow sufficient funds to refinance it.  Even if new financing is available, it may not be on terms that are acceptable to us.  Provided that Aquila does not seek immediate repayment under the Aquila Credit Agreement, management believes that cash on hand and cash generated from operating activities, will be sufficient to meet the Company's cash requirements through December 31, 2002.
> Responding to our financial challenges and lack of capital, we are actively exploring strategic alternatives including, but not limited to, potential asset divestitures, joint ventures, mergers, and other arrangements.  No assessment can be made of the likelihood that any transactions of this sort can be effectively implemented.  Our ability to operate as a going concern is dependent on our ability to successfully negotiate an extension of indebtedness with our lender or a successor lender.
> Because our production 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 decline significantly from those received by us at June 30, 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.
> 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 the six months ended June 30, 2002, our capitalized costs incurred in oil and gas producing activities were $0.8 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.  We cannot be sure that any additional financing or joint ventures will be available to us on acceptable terms.
> In September 1999, we established the Aquila Credit Agreement with Aquila.  In February 2002, we notified Aquila that, as of December 31, 2001, we were not in compliance with the covenant under the Aquila Credit Agreement that requires the Company to maintain projected net revenue attributable to its proved reserves in an amount sufficient to fully amortize the outstanding balance under the Aquila Credit Agreement by its maturity date.  As a result, in February 2002, the Aquila Credit Agreement was amended for a second time.  The second amendment contains the following provisions:
> 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.
> 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.
> The amount available under the agreement was increased by $2.5 million.
> 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.
> 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.
> 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.
> We issued to Aquila 125,000 shares of our 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.
> 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 June 30, 2002, we had drawn all $2.5 million under provision (iii) above.
> The Aquila Credit Agreement requires us to satisfy or discharge liens filed against our properties within 30 days of their filing.  The failure to satisfy or discharge a lien claiming in excess of $250,000 within 30 days is an event of default under the Aquila Credit Agreement.  Upon such an event of default, Aquila may declare any or all obligations under the Aquila Credit Agreement to be immediately due and payable.  As more fully discussed in Note 9, on July 16, 2002, The Jicarilla Apache Indian Nation filed a lien against our property located on the Jicarilla Reservation to secure our payment of approximately $1.56 million of assessed possessory interest tax, including penalties and interest.  As of August 12, 2002, that lien has not been satisfied or discharged.   See the discussion above regarding the classification of the amounts due under the Aquila Credit Agreement as current at June 30, 2002.
> 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 June 30, 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.  In April 2002, a new president was elected in Costa Rica.  Initial indications are that the new government is more sensitive to environmental matters than its predecessors and may restrict future exploration activities.  We have retained legal counsel in order to preserve our rights under the concession or recover our costs incurred to date.
> Results of Operations
> 
> For the Three Months Ended June 30,
> 
> For the Six Months Ended June 30,(In thousands, except per unit data)
> 
> 2002
> 2001
> 
> 2002
> 2001Results of Operations from Oil and Gas Producing Activities:Oil and gas sales
> 
> $2,728
> $5,283
> 
> $5,411
> $12,376Production tax and marketing expense
> 
> 493
> 935
> 
> 967
> 2,441Lease operating expense
> 
> 1,295
> 1,414
> 
> 2,583
> 2,630Depletion
> 
> 1,079
> 1,895
> 
> 2,096
> 3,629Depreciation
> 
> 88
> 75
> 
> 180
> 150Net Production:Oil (MBbl)
> 
> 1
> 44
> 
> 2
> 89Natural gas (MMcf)
> 
> 1,260
> 1,413
> 
> 2,654
> 2,862Mmcfe
> 
> 1,266
> 1,677
> 
> 2,666
> 3,396Average Sales Price Realized (1):Oil (per Bbl)
> 
> $18.55
> $22.23
> 
> $17.56
> $23.76Natural gas (per Mcf)
> 
> 2.15
> 3.05
> 
> 2.03
> 3.59Per Mcfe
> 
> 2.16
> 3.15
> 
> 2.03
> 3.64Average Cost Data (per Mcfe):Production tax and marketing expense
> 
> $0.39
> $0.56
> 
> $0.36
> $0.72Lease operating expense
> 
> 1.02
> 0.84
> 
> 0.97
> 0.77Depletion
> 
> 0.85
> 1.13
> 
> 0.79
> 1.07Depreciation
> 
> 0.07
> 0.04
> 
> 0.07
> 0.04_________________
> 1)  Includes effects of hedging.Three and Six Months Ended June 30, 2002 Compared to June 30, 2001Revenue.  Revenue for the three months ended June 30, 2002 decreased 49% to $2,733,000 from $5,403,000 for the three months ended June 30, 2001 and decreased 57% to $5,429,000 for the six months ended June 30, 2002 from $12,733,000 for the six months ended June 30, 2001.
> Oil and gas sales for the three months ended June 30, 2002 decreased 48% to $2,728,000 from $5,283,000 for the three months ended June 30, 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 the three months ended June 30, 2002 decreased 17% to $18.55 from $22.23 for the three months ended June 30, 2001. Average gas prices per Mcf for the three months ended June 30, 2002 decreased 30% to $2.15 from $3.05 for the three months ended June 30, 2001.  Oil production for the three months ended June 30, 2002 decreased 98% to 1,000 barrels from 44,000 barrels for the three months ended June 30, 2001 as a result of the Delaware Basin sale and gas production for the three months ended June 30, 2002 decreased 11% to 1,260,000 Mcf from 1,413,000 Mcf for the three months ended June 30, 2001.
> Oil and gas sales for the six months ended June 30, 2002 decreased 56% to $5,411,000 from $12,376,000 for the six months ended June 30, 2002 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 the six months ended June 30, 2002 decreased 26% to $17.56 from $23.76 for the six months ended June 30, 2001.  Average gas prices per Mcf for the six months ended June 30, 2002 decreased 43% to $2.03 from $3.59 for the six months ended June 30, 2001.  Oil production for the six months ended June 30, 2002 decreased 98% to 2,000 barrels from 89,000 barrels for the six months ended June 30, 2001 as a result of the Delaware Basin sale and gas production for the six months ended June 30, 2002 decreased 7% to 2,654,000 Mcf from 2,862,000 Mcf for the six months ended June 30, 2001.
> Production Tax and Marketing Expenses.  Production tax and marketing expenses decreased 47% to $493,000 in the three months ended June 30, 2002 from $935,000 in the three months ended June 30, 2001, and decreased 60% to $967,000 in the six months ended June 30, 2002 from $2,441,000 in the six months ended June 30, 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, production tax and marketing expenses were 18% and 19% in the three and six months ended June 30, 2002 as compared to 15% in the three and six months ended June 30, 2001.  Production tax and marketing expenses per Mcfe decreased 30% to $0.39 in the three months ended June 30, 2002 from $0.56 in the three months ended June 30, 2001 and decreased 50% to $0.36 in the six months ended June 30, 2002 from $0.72 in the six months ended June 30, 2001.
> Lease Operating Expenses.  Lease operating expenses decreased 8% to $1,295,000 in the three months ended June 30, 2002 from $1,414,000 in the three months ended June 30, 2001 and decreased 2% to $2,583,000 in the six months ended June 30, 2002 from $2,630,000 in the six months ended June 30, 2001.  Lease operating expenses decreased as a result of the sale of the Delaware Basin properties in September 2001.  Lease operating expenses per Mcfe increased 21% to $1.02 in the three months ended June 30, 2002 from $0.84 per Mcfe in the three months ended June 30, 2001 and increased 26% to $0.97 in the six months ended June 30, 2002 from $0.77 in the six months ended June 30, 2001, due to the accrual of $373,000 and $731,000 for the possessory interest tax in the three and six months ended June 30, 2002, respectively.
> Depreciation, Depletion and Amortization.  Depreciation, depletion and amortization for the three months ended June 30, 2002 decreased 36% to $1,364,000 from $2,125,000 in the three months ended June 30, 2001.  Depreciation, depletion and amortization for the six months ended June 30, 2002 decreased 36% to $2,633,000 from $4,084,000 in the six months ended June 30, 2001.  Depletion per Mcfe decreased 25% to $0.85 for the three months ended June 30, 2002 from $1.13 for the three months ended June 30, 2001 and decreased 26% to $0.79 for the six months ended June 30, 2002 from $1.07 for the six months ended June 30, 2001, 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 the three months ended June 30, 2002 decreased 69% to $1,116,000 from $3,627,000 in the three months ended June 30, 2001 and decreased 68% to $1,591,000 in the six months ended June 30, 2002 from $4,982,000 in the six months ended June 30, 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 $285,000, whereas the Company recognized $2,510,000 of expense in the six months ended June 30, 2001.
> Interest and Other Expenses. Interest and other expenses for the three months ended June 30, 2002 decreased 30% to $1,128,000 from $1,613,000 for the three months ended June 30, 2001 and decreased 39% to $2,090,000 for the six months ended June 30, 2002 from $3,401,000 for the six months ended June 30, 2001.  The decreases were primarily due to lower interest rates and lower outstanding debt balances in 2002 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 three and six months ended June 30, 2002 and 2001.
> Net Loss. We had a net loss of $2,663,000 for the three months ended June 30, 2002 compared to net loss of $4,311,000 for the three months ended June 30, 2001 and a net loss of $4,435,000 for the six months ended June 30, 2002 compared to a net loss of $4,805,000 for the six months ended June 30, 2001, as a result of the factors discussed above.  We paid the 8% dividend of $3,000 and $19,000 on our $800,000 face amount Series B Mandatorily Redeemable Convertible Preferred Stock in the three and six months ended June 30, 2001, and realized accretion of $0 and $2,000.  In addition, during the three months ended 2002 and 2001 and the six months ended June 30, 2002 and 2001, we realized accretion of $170,000, $148,000, $334,000 and $292,000, respectively, on the Mandatorily Redeemable Common Stock.  Net loss attributable to common shareholders for the three and six months ended June 30, 2002 were $2,833,000 and $4,769,000 compared to $4,462,000 and $5,118,000 for the three and six months ended June 30, 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 agreed 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 gains (losses) of $217,000 and $(3,875,000) in the six months ended June 30, 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 business.
> 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 June 30, 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 June 30, 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.
> Year
> MMBtu
> Fixed Priceper MMBtu
> Fair Value2002
> 694,000
> $	2.55-$3.28
> $(521,000)2003
> 996,000
> $	2.55
> (1,316,000)2004
> 852,000
> $	2.55
> (1,208,000)
> 
> In addition, we entered into basis swaps to fix the differential between the NYMEX price and the index price at which the hedged gas is to be sold for 2,542,000 MMBtu for 2002 - 2004 with a fair value of $306,000.
> 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 ValueLong-term debt:Fixed rate
> $306
> $     586
> $3,514
> $17
> $ 41
> $ --
> $  4,464Average interest rate
> 12.7%
> 12.7%
> 12.8%
> 8.0%
> 8.0%
> --Variable rate
> $  --
> $29,211
> $    --
> $   --
> $  --
> $ --
> $29,211Average interest rate
> --
> 8.75%
> --
> --
> --
> --
> 
> 
> PART II - OTHER INFORMATION
> Item 1.  Legal Proceedings
> The information contained in Note 9 to the consolidated financial statements set forth in Part 1 is hereby incorporated by reference.
> **Item 5: Other Information**The information contained in Note 8 to the consolidated financial statements set forth in Part 1 is hereby incorporated by reference.
> During July 2002, The Nasdaq Stock Market, Inc. notified the Company that it was not in compliance with certain requirements for continued listing of the Company's securities on the Nasdaq National Market, including the following (the "Staff Determination"):
> 
> for 30 consecutive trading days, the bid price for the Company's common stock closed below $1.00 per share,
> the Company's net tangible assets were less than $4 million and its stockholders' equity was less than $10 million, and
> the Company's audit committee had fewer than three independent directors.Accordingly, the Company's securities may be delisted from The Nasdaq National Market.  The Company has scheduled a hearing before a Nasdaq Listing Qualifications Panel on August 29, 2002, to review the Staff Determination.  There can be no assurance the Panel will grant the Company's request for continued listing.
> 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 Current Reports on Form 8-K, under "Item 5. Other Events", dated April 4, 2002, May 2, 2002 and June 19, 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.  The June 19, 2002 report related to the expiration of the letter of intent with Smart Exploration, Inc.
> 
> Subsequent to June 30, 2002, the Company filed two Current Reports on Form 8-K dated July 17, 2002.  The report filed under "Item 4. Changes to Registrant's Certifying Accountant", related to the appointment of HEIN + ASSOCIATES LLP as independent accountants for the fiscal year ending December 31, 2002 and the dismissal of Arthur Andersen LLP.  The report filed under "Item 5. Other Events", related to the lien filed by The Jicarilla Apache Indian Nation against the Company's oil and gas properties on the Jicarilla Reservation to secure the Company's payment of approximately $1.56 million of Possessory Interest Tax (including penalties and interest).  Additionally, the Company filed a Current Report on Form 8-K dated July 29, 2002 under "Item 5. Other Events", relating to the Company being out of compliance with Nasdaq's Continued Listing Requirements.SIGNATURESPursuant 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 CORPORATIONRegistrantDate:  August 14, 2002
> By:
> /s/ George O. Mallon, Jr.George O. Mallon, Jr.Chief Executive OfficerDate:  August 14, 2002
> By:
> /s/ Alfonso R. LopezAlfonso R. LopezVice President, Finance/Corporate Treasurer
> CERTIFICATIONS
> PURSUANT TO 18 U.S.C. SECTION 1350
> I, George O. Mallon, Jr., Chief Executive Officer of Mallon Resources Corporation (the "Company"), hereby certify that the accompanying report on Form 10-Q for the period ending June 30, 2002 and filed with the Securities and Exchange Commission on the date hereof pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the "Report") by the Company fully complies with the requirements of that section.  I further certify that the information contained in the Report fairly presents, in all material aspects, the financial condition and results of operations of the Company.
> 
> /s/ George O. Mallon, Jr._________________________Name:  George O. Mallon, Jr.
> Date:  August 14, 2002I, Alfonso R. Lopez, Vice President, Finance/Corporate Treasurer of Mallon Resources Corporation (the "Company"), hereby certify that the accompanying report on Form 10-Q for the period ending June 30, 2002 and filed with the Securities and Exchange Commission on the date hereof pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the "Report") by the Company fully complies with the requirements of that section.  I further certify that the information contained in the Report fairly presents, in all material aspects, the financial condition and results of operations of the Company.
> 
> /s/ Alfonso R. Lopez___________________________Name:  Alfonso R. Lopez
> Date:  August 14, 2002