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 September 30, 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 November 6, 2001, 10,742,827 shares of registrant's common stock, par
value $0.01 per share, were outstanding.

<PAGE>

PART I - FINANCIAL INFORMATION

Item 1 -- Financial Statements


                          MALLON RESOURCES CORPORATION

                          CONSOLIDATED BALANCE SHEETS
                                (In thousands)


                                     ASSETS

<TABLE>
<CAPTION>
                                                  September 30,   December 31,
                                                      2001            2000
                                                  (Unaudited)
<S>                                                 <C>            <C>
Current assets:
    Cash and cash equivalents                       $  5,944       $ 14,155
    Accounts receivable:
       Oil and gas sales                               1,072          3,460
       Joint interest participants, net of allowance of $39 and
          $39, respectively                              102            353
       Related parties                                     1              1
       Other                                               3             18
    Inventories                                          151            215
    Derivative asset                                     476             --
    Prepaid expenses                                   3,571             15
    Other                                                115            108
          Total current assets                        11,435         18,325

Property and equipment:
    Oil and gas properties, full cost method          92,421        120,972
    Natural gas processing plant                       8,624          8,560
    Other property and equipment                       1,106          1,112
                                                     102,151        130,644
    Less accumulated depreciation, depletion and
       amortization                                  (69,280)       (59,057)
                                                      32,871         71,587

Notes receivable-related parties                          --              7

Debt issuance costs, net                               1,169          1,529

Other, net                                               302            262

Total Assets                                        $ 45,777       $ 91,710
                                                    ========       ========
</TABLE>

                          (Continued on following page)



The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE>


                          MALLON RESOURCES CORPORATION

                    CONSOLIDATED BALANCE SHEETS - Continued
                      (In thousands, except share amounts)



                      LIABILITIES AND SHAREHOLDERS' EQUITY

<TABLE>
<CAPTION>
                                                  September 30,   December 31,
                                                      2001            2000
                                                  (Unaudited)
<S>                                                 <C>            <C>
Current liabilities:
    Trade accounts payable                          $  4,362       $  3,689
    Undistributed revenue                                950          2,045
    Drilling advances                                     12             --
    Accrued taxes and expenses                            42             35
    Current portion of long-term debt                  1,235         12,179
          Total current liabilities                    6,601         17,948

Long-term debt, net of unamortized discount of
    $2,139 and $2,813, respectively                   28,130         40,180
Derivative liability                                   1,480             --
                                                      29,610         40,180

Total liabilities                                     36,211         58,128

Contingencies (Note 7)

Series B Mandatorily Redeemable Convertible Preferred
    Stock, $0.01 par value, 500,000 shares authorized,
    -0- and 80,000 shares issued and outstanding,
    respectively                                          --            798

Mandatorily Redeemable Common Stock, $0.01 par value,
    490,000 shares authorized, issued and outstanding,
    mandatory redemption of $6,125                     4,694          4,248

Shareholders' equity:
    Common Stock, $0.01 par value, 25,000,000
        shares authorized; 10,234,827 and 10,115,093
        shares issued and outstanding, respectively      102            101
    Additional paid-in capital                        92,683         92,456
    Accumulated deficit                              (87,006)       (61,155)
    Accumulated other comprehensive loss                (907)            --
    Notes receivable from related party shareholders       --         (2,866)
          Total shareholders' equity                   4,872         28,536

Total Liabilities and Shareholders' Equity          $ 45,777       $ 91,710
                                                    ========       ========
</TABLE>

The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE>


                          MALLON RESOURCES CORPORATION

                     CONSOLIDATED STATEMENTS OF OPERATIONS
                    (In thousands, except per share amounts)
                                   (Unaudited)



<TABLE>
<CAPTION>
                                                              For the Three Months    For the Nine Months
                                                              Ended September 30,     Ended September 30,
                                                                2001        2000        2001        2000
                                                              <C>         <C>          <C>         <C>
Revenues:
    Oil and gas sales                                         $  4,120    $ 4,730     $ 16,496    $ 11,830
    Interest and other                                              41         78          397         211
                                                                 4,161      4,808       16,893      12,041

Costs and expenses:
    Oil and gas production                                       1,898      1,913        6,969       5,119
    Depreciation, depletion and amortization                     2,036      1,604        6,120       4,323
    Impairment of oil and gas properties                        16,418         --       16,418          --
    Loss on sale of oil and gas properties                       3,220         --        3,220          --
    General and administrative                                     225        724        5,207       2,770
    Interest and other                                           1,409      1,671        4,810       4,460
                                                                25,206      5,912       42,744      16,672

Net loss                                                       (21,045)    (1,104)     (25,851)     (4,631)

Dividends on preferred stock and accretion                          --        (17)         (21)        (67)

Accretion of mandatorily redeemable common stock                  (154)      (105)        (446)       (304)

Net loss attributable to common shareholders                  $(21,199)   $(1,226)    $(26,318)   $ (5,002)
                                                              ========    =======     ========    ========

Basic:
    Net loss attributable to common shareholders              $  (1.98)   $ (0.16)    $  (2.47)   $  (0.64)
                                                              ========    =======     ========    ========

    Weighted average common shares outstanding                  10,722      7,881       10,668       7,854
                                                              ========    =======     ========    ========
</TABLE>














The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE>


                          MALLON RESOURCES CORPORATION

                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (In thousands)
                                  (Unaudited)

<TABLE>
<CAPTION>
                                                                                        For the Nine Months
                                                                                        Ended September 30,
                                                                                          2001        2000
<S>                                                                                     <C>         <C>
Cash flows from operating activities:
    Net loss                                                                            $(25,851)   $
(4,631)
    Adjustments to reconcile net loss to net cash provided by operating activities:
       Depreciation, depletion and amortization                                            6,120       4,323
       Impairment of oil and gas properties                                               16,418          --
       Loss on sale of oil and gas properties                                              3,220          --
       Amortization of discount on long-term debt                                            674         507
       Accrued interest expense added to long-term debt                                    1,401       3,325
       Accrued interest income added to notes receivable from related
          party shareholders                                                                 (87)
(140)
       Stock compensation expense                                                          2,097         452
       Partial forgiveness of notes receivable from related-party shareholders               907          --
       Changes in operating assets and liabilities:
          Decrease (increase) in:
             Accounts receivable                                                           2,654
(250)
             Inventory and other assets                                                   (3,591)
(193)
          (Decrease) increase in:
             Trade accounts payable and undistributed revenue                               (420)
(1,082)
             Accrued taxes and expenses                                                        3          47
             Deferred revenue                                                                 97          --
             Drilling advances                                                                12          24
Net cash provided by operating activities                                                  3,654       2,382

Cash flows from investing activities:
    Additions to property and equipment                                                  (15,309)
(13,156)
    Proceeds from sale of oil and gas properties, net                                     29,326          --
    Decrease in notes receivable-related parties                                               7          77
Net cash provided by (used in) investing activities                                       14,024
(13,079)

Cash flows from financing activities:
    Proceeds from long-term debt                                                             858      11,173
    Payments of long-term debt                                                           (25,927)
(296)
    Redemption of preferred stock                                                           (800)         --
    Payment of preferred dividends                                                           (19)
(61)
    Proceeds from stock option and warrants exercises                                          1          68
    Other                                                                                     (2)          2
Net cash (used in) provided by financing activities                                      (25,889)     10,886

Net (decrease) increase in cash and cash equivalents                                      (8,211)        189

Cash and cash equivalents, beginning of period                                            14,155       1,230

Cash and cash equivalents, end of period                                                $  5,944    $  1,419
                                                                                        ========    ========

Supplemental cash flow information:
    Cash paid for interest                                                              $  2,735    $    592
                                                                                        ========    ========

    Non-cash transactions:
        Issuance of common stock in exchange for oil and gas properties
            purchased from officers and directors                                       $     --    $    119
                                                                                        ========    ========

        Issuance of common stock in exchange for accounts receivable from
            shareholder                                                                 $     --    $     98
                                                                                        ========    ========
</TABLE>


The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE>

                          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. OIL AND GAS PROPERTIES

    On September 14, 2001, the Company completed the sale of its Delaware
Basin oil and gas properties, effective July 1, 2001, for an adjusted purchase
price of approximately $31.3 million.  After paying approximately $2.0 million
of additional costs which included approximately $1.3 million resulting from
the early settlement of the Company's oil swap associated with the Delaware
Basin properties, the Company received net proceeds of $29.3 million.  Of
those net proceeds, the Company used $24.1 million to repay a portion of the
note payable to Aquila Energy Capital Corporation ("Aquila") (see Note 3).
The Company accounts for its oil and gas properties using the full cost method
of accounting, under which sales of properties are generally treated as
adjustments of capitalized costs and no gains and losses are recorded, unless
they are significant.  The Company's interests in the Delaware Basin
properties constituted approximately 38% of the Company's total reserve
quantities at June 30, 2001.  Because the sale significantly altered the
relationship between the Company's capitalized costs and its proved oil and
gas reserves, the Company recognized a loss on the sale of oil and gas
properties of $3.2 million for the quarter and nine months ended September 30,
2001.  The loss included costs from an allocation of the Company's total
undepleted full cost pool at June 30, 2001, between the properties sold and
the properties retained, based on the relative estimated fair value of the
properties sold and retained.  The estimated fair value of the Delaware Basin
properties at June 30, 2001 represented approximately 46% of the estimated
fair value of the Company's total oil and gas properties, resulting in an
allocation of the Company's full cost pool of approximately $32.5 million.

    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 price increases subsequent to September 30, 2001, the Company
recorded a charge in third quarter 2001 to write-down its oil and gas
properties by $16.4 million.  Had the Company used the prices in effect at
September 30, 2001, the write-down would have been $25.3 million.

NOTE 3. LONG-TERM DEBT

    Long-term debt consists of the following:

<TABLE>
<CAPTION>
                                                   September 30,  December 31,
                                                       2001             2000
<S>                                                  <C>             <C>
Note payable to Aquila Energy Capital Corporation,
    due 2003                                         $26,711         $ 50,042
Less unamortized discount                             (2,139)          (2,813)
                                                      24,572           47,229
Lease obligation to Universal Compression, Inc.        4,681            5,006
8% unsecured note payable to Bank One, Colorado,
    N.A., due 2006                                       112              124
                                                      29,365           52,359
Less current portion                                  (1,235)         (12,179)

         Total                                       $28,130         $ 40,180
                                                     =======         ========
</TABLE>

    In September 1999, the Company established a credit agreement (the "Aquila
Credit Agreement") with Aquila.  The amount available under the agreement, as
amended, was $53.4 million.  Through September 30, 2001, the Company had drawn
$52.3 million, including accrued interest, and repaid $25.6 million 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 was as follows:  (i) for the months April 2001 to September
2001, the Company paid interest only, or approximately $2.2 million, and (ii)
from October 2001 to March 2002, the Company was to make monthly principal and
interest payments of $700,000 or a total of $4.2 million.  In October 2001,
Aquila allowed the Company to make an interest only payment and the Company is
in the process of negotiating with Aquila to make interest only payments
during the next 12 months totaling approximately $2.1 million.  Aquila has the
right to evaluate the loan monthly and, at its sole discretion, can revert to
the requirement of principal payments equal to Defined Cash Flow.  Due to
Aquila's unilateral ability to modify the repayment schedule, the Company has
classified $734,000 of the Aquila debt as current, based on the Company's best
estimate of Defined Cash Flow for the twelve month period ending September 30,
2002. 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 the first nine months of 2001, the Company repaid $325,000 of lease
obligation to Universal Compression and $12,000 of unsecured note payable to
Bank One.  In May 2001, the due date of the unsecured note payable was
extended from April 2002 to July 2006, and the interest rate was reduced from
8.5% to 8% per annum.

NOTE 4.  PER SHARE DATA

    Basic earnings per share is computed by dividing income available to
common shareholders by the weighted average number of common shares
outstanding for the period. Diluted earnings per share reflects the potential
dilution that could occur if the Company's outstanding stock options and
warrants were exercised (calculated using the treasury stock method) or if the
Company's Series B Mandatorily Redeemable Convertible Preferred Stock were
converted to common stock.  The consolidated statements of operations for the
three and nine months ended September 30, 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 5. HEDGING ACTIVITY

    On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards ("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 September 30, 2001, the Company had
price swaps covering 3,909,000 MMBtu of gas related to production for 2001-
2004 at fixed prices ranging between $2.55-$3.94 per MMBtu.  In addition, the
Company had outstanding at September 30, 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 3,909,000 MMBtu for 2001-2004.

    The Company had "costless collar" contracts covering 60,000 MMBtu per
month in 2001 at a floor price of $3.85 per MMBtu and a ceiling price of $5.80
per MMBtu.  In July 2001, the Company settled early the collar for cash
proceeds of $162,000, which was deferred and will be recognized as revenue
over the remaining term of the original contract.  The amount deferred at
September 30, 2001 was $97,000 and was included in accumulated other
comprehensive loss.  The Company had price swaps covering 171,000 barrels of
oil related to production from its Delaware Basin properties for 2001-2004 at
fixed prices ranging from $17.38-$17.81 per barrel.  In September 2001, in
conjunction with the sale of the Delaware Basin properties (see Note 2), the
Company settled early the crude oil swaps for a total cost of $1,325,000.  At
September 30, 2001, this transaction is reflected as a part of the loss on the
sale of oil and gas properties and as a trade account payable.

    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 September 30, 2001, the Company had recorded a current derivative asset
of $476,000, a long-term derivative liability of $1.5 million and an
unrealized loss of $1.0 million in other comprehensive loss.  No related
income tax effects were recorded because of the Company's net operating loss
carryforward.

    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 nine months of 2001, losses of $3.7 million were
transferred from accumulated other comprehensive loss to oil and gas revenues
related to settled positions and an unrealized gain of $10.5 million was
recorded to other comprehensive income to adjust the fair value of the open
positions.  The Company expects to reclassify as increases to earnings during
the next twelve months approximately $476,000 of unrealized hedging gains in
accumulated other comprehensive loss at September 30, 2001.

NOTE 6. COMPREHENSIVE INCOME

    The Company follows SFAS No. 130, "Reporting Comprehensive Income", which
establishes standards for reporting comprehensive income. In addition to net
income, comprehensive income includes all changes in equity during a period,
except those resulting from investments and distributions to the owners of the
Company.  The 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 nine months ended September 30,
2001:

<TABLE>
<CAPTION>
                                                                (In thousands)
<S>                                                               <C>
Accumulated other comprehensive loss - December 31, 2000          $     --

Net loss                                                           (26,318)

Accumulated other comprehensive loss:
   Cumulative effect of change in accounting principle -
      January 1, 2001                                              (15,171)
   Reclassification adjustment for settled hedging contracts         3,781
   Changes in fair value of outstanding hedging positions           10,483
Accumulated other comprehensive loss                                  (907)

Comprehensive loss - September 30, 2001                           $(27,225)
                                                                  ========
</TABLE>

NOTE 7. CONTINGENCIES

    As of September 30, 2001, the Revenue and Taxation Department (the
"Department") of the Jicarilla Apache Nation (the "Nation") had issued to the
Company Possessory Interest Tax assessments for 1998, 1999, 2000 and 2001
totaling $3.5 million, including related penalties and interest.  The Company
has paid the assessments under protest.  This amount is included in the
Company's September 30, 2001 consolidated balance sheet under prepaid
expenses.  The Company has 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 first protest covering
approximately $1.6 million for the periods prior to 2001 was denied in July
2001.  The Company has filed an appeal.  In October and November 2001, two
additional protests covering $850,000 were denied.  The Company intends to
file appeals relating to the denial of these two protests.  In connection with
the decisions relating to the denial of these two protests, the Department
recalculated the late payment charges in the original assessments and has
refunded $168,000, including interest, to the Company. The Company has: 1)
requested that the Legislative Council of the Nation grant the Company relief,
and 2) engaged New Mexico counsel to represent it.  The final outcome of this
matter cannot yet be predicted.

    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 8. MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED STOCK

    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.

NOTE 9. SHAREHOLDER RIGHTS PLAN

    As discussed in the Company's 2000 Form 10-K, in April 1997, the Company's
Board of Directors declared a dividend on its shares of common stock (the
"Common Shares") of preferred share purchase rights (the "Rights") as part of
a Shareholder Rights Plan (the "Plan").  The Plan is designed to insure that
all shareholders of the Company receive fair value for their Common Shares in
the event of a proposed takeover of the Company and to guard against the use
of partial tender offers or other coercive tactics to gain control of the
Company without offering fair value to the Company's shareholders.  The Rights
expired on April 22, 2001.  In June 2001, the Company's Board of Directors
reinstated the Rights which now will expire on June 30, 2006.

NOTE 10. RELATED PARTY TRANSACTIONS

    In September 1999, certain officers of the Company exercised options to
purchase 381,360 shares of common stock with an exercise price of $6.88 per
share, and borrowed funds from the Company utilizing recourse notes to do so.
Interest on the notes accrued at 7%, payable along with the principal in
August 2002.  In October 2000, the Company amended the notes to extend the due
date of the principal and accrued interest from August 2002 to August 2004 and
to provide for the cancellation of the notes upon the occurrence of a "Change
of Control" of the Company as defined in the Company's bylaws.

    In May 2001, in connection with a termination settlement reached with a
former officer of the Company, the Company purchased certain interests in an
oil and gas limited liability company from the officer valued at $350,000.
The proceeds were used to reduce the balance of the note receivable from the
officer.  The remaining principal and accrued interest on the note of $364,000
was forgiven and is reflected as a non-cash charge to general and
administrative expense for the nine months ended September 30, 2001 in the
accompanying consolidated statements of operations.  In addition, because
76,066 unvested options to purchase shares of the Company's common stock
vested upon his termination and became immediately exercisable, the Company
recorded a non-cash charge of $195,000 to general and administrative expense
for the nine months ended September 30, 2001 in the accompanying consolidated
statements of operations.

    In June 2001, the Company's Board of Directors approved a measure to
forgive a portion of the interest and principal on the notes receivable from
the remaining officers.  For accounting purposes, the Company has treated the
partial forgiveness 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 connection
with the assumed repurchase of common stock and the cancellation of the notes
receivable, the Company recorded a non-cash charge of $533,000, which is
reflected in general and administrative expense for the nine months ended
September 30, 2001 in the accompanying consolidated statements of operations.
The options to purchase 287,462 shares of common stock discussed above are
treated as variable awards for accounting purposes.  Compensation expense will
be recognized for the amount of any increases in the stock price above the
exercise price of $1.00 until the options are exercised, forfeited or expire
unexercised.  Any decreases in the stock price will be recognized as a
decrease in compensation expense, limited to the amount of compensation
expense previously recognized as a result of increases in the stock price.  As
a result of the variable nature of the options discussed above, the Company
recorded a non-cash credit of $906,000 for the third quarter of 2001 and a
non-cash charge of $503,000 for the nine months ended September 30, 2001,
which is reflected in general and administrative expense and is based on the
change in the stock price from the exercise price of $1.00.

NOTE 11. STOCK COMPENSATION

    In June 2001, the Compensation Committee of Mallon's Board of Directors
adopted a policy that, upon a change of control of the Company, the exercise
price on outstanding stock options held by then current employees of the
Company will be reduced to $0.01 from an average exercise price of $6.88.  At
September 30, 2001, 218,364 outstanding stock options were affected by this
new policy.  Under the provisions of Financial Accounting Standards Board
("FASB") Interpretation No. 44, "Accounting for Certain Transactions Involving
Stock Compensation," the Company will be required to account for the options
as variable awards from the modification date until the date the options are
exercised, forfeited or expire unexercised.  Compensation expense will be
recognized for the amount of any increases in the stock price above the
original exercise price per share until the options are exercised, forfeited
or expire unexercised, or until a change of control event occurs.  Any
decreases in the stock price will be recognized as a decrease in compensation
expense, limited to the amount of compensation expense previously recognized
as a result of increases in the stock price.  If and when the change of
control event occurs, compensation expense will be measured for the difference
between the stock price on that date and $0.01 per share and will be
recognized as a non-cash charge to general and administrative expense.  As of
September 30, 2001, no compensation expense had been recorded related to the
options discussed above.

NOTE 12. RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

    In June 2001, the FASB issued SFAS No. 141, "Business Combinations," which
addresses financial accounting and reporting for business combinations.  SFAS
No. 141 is effective for all business combinations initiated after June 30,
2001 and for all business combinations accounted for under the purchase method
initiated before but completed after June 30, 2001.  The adoption of SFAS No.
141 is not expected to have a material impact on the Company's financial
position or results of operations.

    In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets," which addresses financial accounting and reporting for goodwill and
other intangible assets.  SFAS No. 142 is effective for fiscal years beginning
after December 15, 2001, and applies to all goodwill and other intangibles
recognized in the financial statements at that date.  The adoption of SFAS No.
142 is not expected to have a material impact on the Company's 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 of Disposal of Long-Lived Assets".  SFAS No. 144 supersedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for 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.  SFAS No. 144 is effective for fiscal years beginning
after December 15, 2001.  The Company will adopt SFSA No. 144 on January 1,
2002, but has not yet quantified the effects of adopting SFAS No. 144 on its
financial position or results of operations.

<PAGE>

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 September 30, 2001 and December 31, 2000,
results of operations for the three and nine months ended September 30, 2001
and 2000 and cash flows for the nine months ended September 30, 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 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

    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 first nine months of 2001, our capitalized costs incurred in
oil and gas producing activities were $15.9 million. Our current 2001 capital
expenditure budget is approximately $16.1 million.  During the first nine
months of 2001, we drilled 19 wells, of which 17 were successful, and
recompleted two wells.  We are currently evaluating the number of wells we
will drill during the remainder of 2001.  We expect to fund our capital
requirements for the next 12 months through possible additional financing.

    On September 14, 2001, we completed the sale of our Delaware Basin
properties, effective July 1, 2001 for an adjusted purchase price of
approximately $31.3 million.  After paying approximately $2.0 million of
additional costs related to the sale, we received net proceeds of
approximately $29.3 million, of which we used approximately $24.1 million to
repay a portion of our note payable to Aquila Energy Capital Corporation
("Aquila").  The remaining $5.2 million will be used for operations.

    In September 1999, we established a credit agreement (the "Aquila Credit
Agreement") with Aquila.  The amount available under the agreement, as
amended, was $53.4 million.  At September 30, 2001, we had drawn $52.3
million, including accrued interest, under the Aquila Credit Agreement.
However, under the terms of the Aquila Credit Agreement, the remaining $1.1
million nominally available could not be drawn for capital expenditures.
Principal payments on the four-year loan are based on our cash flow from
operations, as defined ("the Defined Cash Flow"), less advances for our
development program.  As of March 31, 2001, the advances exceeded cash flow
from operations and we had not made any principal payments.  We 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 was as follows:  (i)
for the months April 2001 to September 2001, we paid interest only, or
approximately $2.2 million, and (ii) from October 2001 to March 2002, we were
to make monthly principal and interest payments of $700,000 or a total of $4.2
million.  In September 2001, we repaid approximately $24.1 million of the note
to Aquila with the proceeds from the sale of our Delaware Basin properties, as
described above.  In October 2001, Aquila allowed us to make an interest only
payment and we are in the process of negotiating with Aquila to make interest
only payments for the next 12 months, totaling approximately $2.1 million.
Aquila has the right to evaluate the loan monthly and, at its sole discretion,
revert to the requirement of principal payments equal to Defined Cash Flow.
We 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 we will be successful in our 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 $325,000 to Universal Compression during the first nine
months of 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
$12,000 of this loan during the first nine months of 2001.  In May 2001, the
due date of the unsecured note payable was extended from April 2002 to July
2006, and the interest rate was reduced from 8.5% to 8% per annum.

    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 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 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

<TABLE>
<CAPTION>
                                                               For the Three Months    For the Nine Months
                                                               Ended September 30,     Ended September 30,
                                                                 2001        2000       2001        2000
                                                                    (In thousands, except per unit data)
<S>                                                            <C>         <C>        <C>         <C>
Results of Operations from Oil and Gas Producing Activities:
    Oil and gas sales                                          $4,120      $4,730     $16,496    $11,830
    Production tax and marketing expense                          702       1,022       3,143      2,153
    Lease operating expense                                     1,196         891       3,826      2,966
    Depletion                                                   1,802       1,408       5,431      3,719
    Depreciation                                                   75          69         225        191

Net Production:
    Oil (MBbl)                                                     20          42         109        126
    Natural gas (MMcf)                                          1,689       1,696       4,551      4,358
    Total (MMcfe)                                               1,809       1,948       5,205      5,114

Average Sales Price Realized: (1)
    Oil (per Bbl)                                              $19.85      $24.17      $23.05     $24.09
    Natural gas (per Mcf)                                        2.20        2.19        3.07       2.02
    Per Mcfe                                                     2.28        2.43        3.17       2.31

Average Cost Data (per Mcfe):
    Production tax and marketing expense                        $0.39       $0.52       $0.60      $0.42
    Lease operating expense                                      0.66        0.46        0.74       0.58
    Depletion                                                    1.00        0.72        1.04       0.73
    Depreciation                                                 0.04        0.04        0.04       0.04
_________________
1) Includes effects of hedging.
</TABLE>


Three and Nine Months Ended September 30, 2001 Compared to September 30, 2000

    Revenues.  Total revenues decreased 13% to $4,161,000 for the three months
ended September 30, 2001 from $4,808,000 for the three months ended
September 30, 2000 and increased 40% to $16,893,000 for the nine months ended
September 30, 2001 from $12,041,000 for the nine months ended September 30,
2000.  Oil and gas sales decreased 13% to $4,120,000 for the 2001 quarter from
$4,730,000 for the 2000 quarter due primarily to lower oil production and
lower oil prices in the 2001 quarter.  Oil and gas sales increased 39% to
$16,496,000 for the nine months ended September 30, 2001 from $11,830,000 for
the nine months ended September 30, 2000, due to higher gas prices and gas
production in the 2001 period offset slightly by lower oil prices and oil
production.  Average oil prices realized per barrel decreased 18% to $19.85 in
the fiscal 2001 quarter, from $24.17 in the fiscal 2000 quarter; and average
gas prices realized per Mcf stayed flat at $2.20 in the 2001 quarter compared
to $2.19 in the 2000 quarter.  Average oil prices realized per barrel
decreased 4% to $23.05 for the nine months ended September 30, 2001, from
$24.09 for the comparable 2000 period, and average gas prices realized per Mcf
increased 52% to $3.07 in the 2001 period from $2.02 for the nine months ended
September 30, 2000.  Oil production decreased 52% to 20,000 barrels in the
2001 quarter from 42,000 barrels in the 2000 quarter and gas production stayed
flat at 1,689,000 per Mcf in the 2001 quarter compared to 1,696,000 Mcf in the
2000 quarter.  Oil production decreased 13% to 109,000 barrels for the nine
months ended September 30, 2001 from 126,000 barrels for the nine months ended
September 30, 2000; and gas production increased 4% to 4,551,000 Mcf for the
nine months ended September 30, 2001 from 4,358,000 Mcf for the same period a
year ago.  As discussed in Note 2 to the consolidated financial statements, we
sold our Delaware Basin properties, which produce primarily oil, in September
2001.

    Production Tax and Marketing.  Production tax and marketing expenses,
decreased 31% to $702,000 for the three months ended September 30, 2001 from
$1,022,000 for the 2000 quarter, and increased 46% to $3,143,000 for the nine
months ended September 30, 2001 from $2,153,000 for the comparable 2000
period.  Production taxes are calculated and paid on prices before hedging
gains or losses.  As a percentage of sales before hedging gains or losses,
production taxes and marketing expenses were 18% and 19% in third quarter 2001
and 2000, respectively, and 16% and 13% for the first nine months of 2001 and
2000, respectively.  Production tax and marketing expense per Mcfe decreased
$0.13 to $0.39 per Mcfe, or 25%, for the 2001 quarter from $0.52 for the 2000
quarter because of lower oil prices in the 2001 quarter.  Production tax and
marketing expense increased $0.18 per Mcfe, or 43%, during the nine months
ended September 30, 2001 as a result of higher gas prices.

    Lease Operating Expense.  LOE per Mcfe increased 43% to $0.66 for the 2001
quarter from $0.46 for the 2000 quarter and increased $0.16, or 28%, to $0.74
for the nine months ended September 30, 2001 from to $0.58 for the same period
a year ago due to higher plant operation, salt water disposal, compression and
dehydration and surface maintenance costs in the 2001 periods relative to
increases in production.

    Depreciation, Depletion and Amortization.  Depreciation, depletion and
amortization for the three months ended September 30, 2001 increased 27% to
$2,036,000 from $1,604,000 in the 2000 quarter, and increased 42% to
$6,120,000 for the nine months ended September 30, 2001 from $4,323,000 for
the nine months ended September 30, 2000.  Depletion per Mcfe increased 39% to
$1.00 for the fiscal 2001 quarter from $0.72 for the fiscal 2000 quarter and
increased 42% to $1.04 for the nine months ended September 30, 2001 from $0.73
for the nine months ended September 30, 2000, primarily due to a higher ratio
of increases in capital expenditures to increases in reserves.

    Impairment of Oil & Gas Properties.  Impairment of oil and gas properties
was $16,418,000 for the quarter and nine months ended September 30, 2001.
Under the full cost accounting rules of the Securities and Exchange
Commission, we review the carrying value of our 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 price
increases subsequent to September 30, 2001, we recorded a charge in third
quarter 2001 to write-down our oil and gas properties by $16.4 million.  Had
we used the prices in effect at September 30, 2001, the write-down would have
been $25.3 million.

    Loss on Sale of Oil and Gas Properties.  On September 14, 2001, we
completed the sale of our Delaware Basin oil and gas properties, effective
July 1, 2001, for an adjusted purchase price of approximately $31.3 million.
After paying approximately $2.0 million of additional costs which included
approximately $1.3 million resulting from the early settlement of our oil swap
associated with the Delaware Basin properties, we received net proceeds of
$29.3 million.  Of those net proceeds, we used $24.1 million to repay a
portion of the note payable to Aquila Energy Capital Corporation ("Aquila")
(see Note 3).  We account for our oil and gas properties using the full cost
method of accounting, under which sales of properties are generally treated as
adjustments of capitalized costs and no gains and losses are recorded, unless
they are significant.  Our interests in the Delaware Basin properties
constituted approximately 38% of our total reserve quantities at June 30,
2001.  Because the sale significantly altered the relationship between our
capitalized costs and our proved oil and gas reserves, we recognized a loss on
the sale of oil and gas properties of $3.2 million for the quarter and nine
months ended September 30, 2001.  The loss included costs from an allocation
of our total undepleted full cost pool at June 30, 2001, between the
properties sold and the properties retained, based on the relative estimated
fair value of the properties sold and retained.  The estimated fair value of
the Delaware Basin properties at June 30, 2001 represented approximately 46%
of the estimated fair value of our total oil and gas properties, resulting in
an allocation of our full cost pool of approximately $32.5 million.

    General and Administrative Expenses.  Total general and administrative
expenses for the three months ended September 30, 2001 decreased 69% to
$225,000 from $724,000 in the 2000 quarter, due to a variable stock
compensation award credit in the 2001 quarter of $906,000 as discussed in Note
10 to the accompanying consolidated financial statements.  General and
administrative expenses increased 88% to $5,207,000 for the nine months ended
September 30, 2001 from $2,770,000 for the same period in 2000, as a result of
unusual non-cash expenses in the 2001 period related to a termination
settlement reached with one of our former officers and a partial forgiveness
of certain notes receivable from related party shareholders.  These unusual
expenses totaled approximately $2,500,000.

    Interest and Other Expenses.  Interest and other expenses for the three
months ended September 30, 2001 decreased 16% to $1,409,000 from $1,671,000
for the three months ended September 30, 2000 and increased 8% to $4,810,000
for the nine months ended September 30, 2001 from $4,460,000 for the nine
months ended September 30, 2000.  Interest rates in the 2001 quarter were
lower than in the year ago period and interest rates and the outstanding debt
balance was higher during the nine months ended September 30, 2001 than in the
year ago period.

    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.  SFAS 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 benefit in the consolidated statements of operations for the
three and nine months ended September 30, 2001 and 2000.

    Net Loss.  Net loss for the three months ended September 30, 2001 was
$21,045,000 compared to $1,104,000 for the three months ended September 30,
2000, and $25,851,000 for the nine months ended September 30, 2001 compared to
$4,631,000 for the same period a year ago, as a result of the factors
discussed above. We paid the 8% dividend of $-0- and $16,000 on our Series B
Mandatorily Redeemable Convertible Preferred Stock ("Series B Preferred
Stock"), and realized accretion of $-0- and $1,000, in the three months ended
September 30, 2001 and 2000, respectively.  We paid dividends of $19,000 and
$61,000 and realized accretion of $2,000 and $6,000 in the nine-month periods
ended September 30, 2001 and 2000, respectively.  Net loss attributable to
common shareholders for the three months ended September 30, 2001 was
$21,199,000 compared to $1,226,000 for the three months ended September 30,
2000, and $26,318,000 for the nine months ended September 30, 2001 compared to
$5,002,000 for the nine months ended September 30, 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 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
$192,000 and ($2,510,000) in third quarter 2001 and 2000, respectively and
recognized hedging (losses) of $(3,684,000) and $(4,696,000) in the nine
months ended September 30, 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 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 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 September 30, 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 September 30, 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.

<TABLE>
<CAPTION>
Natural Gas:

                                   Fixed Price
    Year               MMBtu       per MMBtu        Fair Value
<S>                   <C>          <C>              <C>
    2001              503,000      $2.55-$3.94      $ 357,000
    2002            1,558,000      $2.55-$3.91       (167,000)
    2003              996,000      $2.55             (644,000)
    2004              852,000      $2.55             (628,000)
</TABLE>

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
3,909,000 MMBtu for 2001 - 2004 with a fair value of $78,000.

    In September 2001, in conjunction with the sale of our Delaware Basin
properties, we settled early our crude oil swaps for a total cost of
$1,325,000.  At September 30, 2001, this transaction is reflected in the loss
on sale of oil and gas properties and as an other current liability.

    We had also entered into "costless collar" contracts covering 60,000 MMBtu
per month in 2001 at an El Paso-Permian Index floor price of $3.85 per MMBtu
and a ceiling price of $5.80 per MMBtu.  In July 2001, we settled early the
collar for cash proceeds of $162,000, which was deferred and will be
recognized as revenue over the remaining term of the original contract.  The
amount deferred at September 30, 2001 was $97,000 and was included in other
comprehensive loss.

PART II - OTHER INFORMATION

Item 6.  Exhibits and Reports on Form 8-K

(a)  Exhibits:

     10.23  Employment Contract with Executive Vice President

(b)  Reports on Form 8-K:

     During third quarter 2001 the Company filed Periodic Reports of Form 8-K
dated August 13, 2001 and September 18, 2001 both related to an "Item 5. Other
Events" matter.

<PAGE>


                                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:  November 14, 2001        By:  /s/ Roy K. Ross
                                   Roy K. Ross
                                   Executive Vice President


Date:  November 14, 2001         By: /s/ Alfonso R. Lopez
                                   Alfonso R. Lopez
                                   Vice President, Finance/Corporate Treasurer

<PAGE>