SECURITIES AND EXCHANGE COMMISSION
                            Washington, D. C. 20549

                                   Form 10-Q


(Mark One)
[X]  Quarterly report pursuant to Section 13 or 15(d) of the Securities
     Exchange Act of 1934 for the quarterly period ended March 31, 2001.

- or -

[  ]  Transition report pursuant to Section 13 or 15(d) of the Securities
      Exchange Act of 1934 for the transition period from _____________ to
      _________________.


Commission File No. 0-17267


MALLON RESOURCES CORPORATION
(Exact name of registrant as specified in its charter)


     COLORADO                                     84-1095959
(State or other jurisdiction of        (I.R.S. Employer Identification No.)
incorporation or organization)


999 18th Street, Suite 1700
Denver, Colorado  80202
(Address of principal executive offices)


(303) 293-2333
(Registrant's telephone number, including area code)


Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or such shorter period of time
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days.

        YES [X]                               NO [  ]



As of May 11, 2001, 10,646,094 shares of the registrant's common stock, par
value $0.01 per share, were outstanding.
<PAGE>

                     PART I  --  FINANCIAL INFORMATION

Item 1.  Financial Statements




                      MALLON RESOURCES CORPORATION

                      CONSOLIDATED BALANCE SHEETS
                            (In thousands)


                                ASSETS
<TABLE>
<CAPTION>
                                                  March 31,    December 31,
                                                    2001          2000
                                                 (Unaudited)
<S>                                               <C>          <C>
Current assets:
    Cash and cash equivalents                     $ 11,013     $ 14,155
    Accounts receivable:
       Oil and gas sales                             2,427        3,460
       Joint interest participants, net of allowance
          of $39 and $39, respectively                 275          353
       Related parties                                   1            1
       Other                                            63           18
    Inventories                                        193          215
    Other                                            2,042          123
          Total current assets                      16,014       18,325

Property and equipment:
    Oil and gas properties, full cost method       127,642      120,972
    Natural gas processing plant                     8,569        8,560
    Other property and equipment                     1,117        1,112
                                                   137,328      130,644
    Less accumulated depreciation, depletion and
       amortization                                (60,896)    (59,057)
                                                    76,432      71,587

Notes receivable-related parties                        --           7
Debt issuance costs, net                             1,413       1,529
Other, net                                             260         262

Total Assets                                      $ 94,119    $ 91,710
</TABLE>



                          (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

<TABLE>
<CAPTION>
                                                  March 31,    December 31,
                                                    2001          2000
                                                 (Unaudited)
<S>                                               <C>          <C>
Current liabilities:
    Trade accounts payable                        $  3,511     $  3,689
    Undistributed revenue                            2,056        2,045
    Accrued taxes and expenses                          77           35
    Derivative liability                             5,117           --
    Current portion of long-term debt               10,105       12,179
          Total current liabilities                 20,866       17,948

Long-term debt, net of unamortized discount of
    $2,598 and $2,813, respectively                 44,597       40,180
Derivative liability                                 5,981           --
                                                    50,578       40,180

Total liabilities                                   71,444       58,128

Commitments and contingencies (Note 6)

Series B Mandatorily Redeemable Convertible Preferred
    Stock, $0.01 par value, 500,000 shares authorized,
    80,000 shares issued and outstanding, liquidation
    preference and mandatory redemption of $800        800          798

Mandatorily Redeemable Common Stock, $0.01 par value,
   490,000 shares authorized, issued and outstanding,
   mandatory redemption of $6,125                    4,392        4,248

Shareholders' equity:
    Common Stock, $0.01 par value, 25,000,000
       shares authorized; 10,140,093 and 10,115,093
       shares issued and outstanding, respectively     101          101
    Additional paid-in capital                      93,040       92,456
    Accumulated deficit                            (61,649)     (61,155)
    Other comprehensive loss                       (11,098)          --
    Notes receivable from shareholders              (2,911)      (2,866)
          Total shareholders' equity                17,483       28,536

Total Liabilities and Shareholders' Equity        $ 94,119     $ 91,710
</TABLE>





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


                        MALLON RESOURCES CORPORATION

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


<TABLE>
<CAPTION>
                                                        For the Three Months
                                                          Ended March 31,
                                                        2001           2000
                                                        (Unaudited)
<S>                                                      <C>        <C>
Revenues:
    Oil and gas sales                                    $ 7,093    $ 3,920
    Interest and other                                       237         62
                                                           7,330      3,982

Costs and expenses:
    Production tax and marketing                           1,506        557
    Lease operating                                        1,216      1,106
    Depreciation, depletion and amortization               1,959      1,441
    General and administrative, net                        1,355      1,190
    Interest and other                                     1,788      1,319
                                                           7,824      5,613

Net loss                                                    (494)    (1,631)

Dividends and accretion on preferred stock                   (18)       (30)

Accretion of mandatorily redeemable common stock            (144)       (98)

Net loss attributable to common shareholders             $  (656)   $(1,759)


Basic:
  Net loss per share attributable to common shareholders $ (0.06)   $ (0.22)

    Weighted average common shares outstanding            10,627      7,836
</TABLE>
















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


                        MALLON RESOURCES CORPORATION

                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                               (In thousands)



<TABLE>
<CAPTION>
                                                        For the Three Months
                                                          Ended March 31,
                                                        2001           2000
                                                        (Unaudited)
<S>                                                     <C>        <C>
Cash flows from operating activities:
    Net loss                                            $  (494)   $(1,631)
    Adjustments to reconcile net loss to net cash provided
    by operating activities:
       Depreciation, depletion and amortization           1,959      1,441
       Accrued interest expense added to long-term debt   1,401        912
       Accrued interest income added to notes receivable
         from shareholders                                  (45)       (46)
       Amortization of discount on long-term debt           215        163
       Stock compensation expense                           579        366
       Changes in operating assets and liabilities:
          Decrease (increase) in:
            Accounts receivable                           1,066         89
            Inventory and other assets                   (1,897)      (168)
          (Decrease) increase in:
            Trade accounts payable and undistributed
              revenue                                      (166)      837
            Accrued taxes and expenses                       39        17
Net cash provided by operating activities                 2,657     1,980

Cash flows from investing activities:
    Additions to property and equipment                  (6,517)   (4,304)
    Other                                                     7        70
Net cash used in investing activities                    (6,510)   (4,234)

Cash flows from financing activities:
    Proceeds from long-term debt                            837     2,824
    Payments of long-term debt                             (110)      (96)
    Payment of preferred dividends                          (16)      (27)
    Other                                                    --         4
Net cash provided by financing activities                   711     2,705

Net (decrease) increase in cash and cash equivalents     (3,142)      451

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

Cash and cash equivalents, end of period                $11,013    $1,681


Supplemental cash flow information:
    Cash paid for interest                              $   173   $   206
</TABLE>




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


                         MALLON RESOURCES CORPORATION

                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                                 (Unaudited)
                                 ___________


NOTE 1. GENERAL

    Mallon Resources Corporation (the "Company") engages in oil and gas
exploration and production through its wholly-owned subsidiary, Mallon Oil
Company ("Mallon Oil"), whose oil and gas operations are conducted primarily
in the State of New Mexico. The Company operates its business and reports
its operations as one business segment. All significant inter-company
balances and transactions have been eliminated from the consolidated
financial statements.

    These unaudited consolidated financial statements have been prepared in
accordance with generally accepted accounting principles for interim
financial information and with the instructions to Form 10-Q and Article 10
of Regulation S-X. Accordingly, they do not include all of the information
and footnotes required by generally accepted accounting principles for
complete financial statements. In the opinion of management, such interim
statements reflect all adjustments (consisting of normal recurring
adjustments) necessary to present fairly the financial position and the
results of operations and cash flows for the interim periods presented. The
results of operations for these interim periods are not necessarily
indicative of the results to be expected for the full year. These interim
statements should be read in conjunction with the consolidated financial
statements and notes thereto included in the Company's 2000 Form 10-K.

    Certain prior year amounts in the consolidated financial statements have
been reclassified to conform to the presentation used in 2001.

NOTE 2. LONG-TERM DEBT

    Long-term debt consists of the following:

<TABLE>
<CAPTION>
                                                    March 31,   December 31,
                                                    2001        2000
<S>                                                 <C>         <C>
Note payable to Aquila Energy Capital Corporation,
   due 2003                                         $ 52,281    $ 50,042
Less unamortized discount                             (2,598)     (2,813)
                                                      49,683      47,229
Lease obligation to Universal Compression, Inc.        4,899       5,006
8.5% unsecured note payable to Bank One, Colorado,
   N.A., due 2002                                        120         124
                                                      54,702      52,359
Less current portion                                 (10,105)    (12,179)

         Total                                      $ 44,597    $ 40,180
</TABLE>

    In September 1999, the Company established a credit agreement (the
"Aquila Credit Agreement") with Aquila Energy Capital Corporation
("Aquila").  The amount available under the agreement, as amended, is $53.4
million. The amount available may be increased to as much as $60 million as
new reserves are added through the Company's planned development drilling
program. At March 31, 2001, the Company had drawn $52.3 million, including
accrued interest, under the Aquila Credit Agreement.

    Principal payments on the four-year loan are based on the Company's cash
flow from operations, as defined ("the Defined Cash Flow"), less advances
for the Company's development program. As of March 31, 2001, the advances
exceeded cash flow from operations and the Company had not made any
principal payments.  The Company had expected to begin making principal
payments in March 2001 and paid Aquila $1.4 million on April 6, 2001.  On
March 30, 2001, Aquila agreed to waive the requirement for principal
payments equal to the Defined Cash Flow.  Instead, the repayment schedule
for the twelve months beginning April 30, 2001 is as follows:  (i) for the
months April 2001 to September 2001, the Company will pay interest only, or
approximately $2.5 million, and (ii) from October 2001 to March 2002, the
Company will make monthly principal and interest payments of $700,000 or a
total of $4.2 million.  Aquila will evaluate the loan monthly and, at its
sole discretion, can discontinue the repayment schedule described above and
revert to the requirement of principal payments equal to Defined Cash Flow.
Due to Aquila's unilateral ability to modify the repayment schedule
described above, the Company has classified $9.6 million of the Aquila debt
as current, based on the Company's best estimate of Defined Cash Flow for
the twelve month period ending March 31, 2002.  The Company anticipates the
Aquila Credit Agreement will be amended during second quarter 2001 to
reflect the changes described above.  The Company will continue to seek to
increase the amount available under the Aquila Credit Agreement and to
revise the repayment requirements.  However, there can be no assurance that
the Company will be successful in its efforts to further amend the Aquila
Credit Agreement.

    During first quarter 2001, the Company repaid $106,000 of lease
obligation to Universal Compression and $4,000 of unsecured note payable to
Bank One.

NOTE 3.  PER SHARE DATA

    Basic earnings per share is computed by dividing income available to
common shareholders by the weighted average number of common shares
outstanding for the period. Diluted earnings per share reflects the
potential dilution that could occur if the Company's outstanding stock
options and warrants were exercised (calculated using the treasury stock
method) or if the Company's Series B Mandatorily Redeemable Convertible
Preferred Stock were converted to common stock.  The consolidated statements
of operations for the three months ended March 31, 2001 and 2000 reflect
only basic earnings per share because the Company was in a loss position for
all periods presented and all common stock equivalents are anti-dilutive.

NOTE 4. HEDGING ACTIVITY

    On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" as amended by SFAS No. 137
and SFAS No. 138.  Under SFAS No. 133, all derivative instruments are
recorded on the balance sheet at fair value.  If the derivative does not
meet specific hedge accounting criteria or is not designated as a hedge, the
gain or loss on the derivative is recognized currently in earnings. If the
derivative qualifies for hedge accounting, the gain or loss on the
derivative is deferred in other comprehensive income/loss, a component of
shareholders' equity, to the extent the hedge is effective.

    The Company periodically enters into derivative commodity instruments to
hedge its exposure to price fluctuations on natural gas and crude oil
production.  Under the Aquila Credit Agreement, the Company may be required
to maintain price hedging arrangements in place with respect to up to 65% of
its oil and gas production.  Accordingly, at March 31, 2001, the Company had
outstanding agreements to hedge a total of 201,000 barrels of oil related to
production for 2001-2004 at fixed prices ranging from $17.38-$18.30 per
barrel and to hedge a total of 5,105,000 MMBtu of gas related to production
for 2001-2004 at a fixed price ranging between $2.55-$3.94 per MMBtu.

    In addition, the Company has outstanding at March 31, 2001 basis swaps
to fix the differential between the NYMEX price and the index price at which
the hedged gas is to be sold for 5,105,000 MMBtu for 2001-2004, and
"costless collar" contracts pursuant to which the Company hedged the price
of 60,000 MMBtu per month in 2001 based on an El Paso-Permian Index.  The
Company will receive $3.85 per MMBtu if the settlement price is below $3.85
per MMBtu.  If the settlement price is greater than $5.80 per MMBtu, the
Company will pay the difference between such settlement price and $5.80 per
MMBtu.

    All hedge transactions are subject to the Company's risk management
policy, which does not permit speculative positions.  The Company formally
documents all relationships between hedging instruments and hedged items, as
well as its risk management objectives and strategy for undertaking the
hedge.  This process includes specific identification of the hedging
instrument and the hedge transaction, the nature of the risk being hedged
and how the hedging instrument's effectiveness will be assessed.  Both at
the inception of the hedge and on an ongoing basis, the Company assesses
whether the derivatives that are used in hedging transactions are highly
effective in offsetting changes in cash flows of hedged items.

    At March 31, 2001, the Company has recorded a current derivative
liability of $5.1 million, a long-term derivative liability of $6.0 million
and an unrealized loss of $11.1 million in other comprehensive loss.  No
related income tax effects were recorded because of the Company's net
operating loss carryforwards.

    On January 1, 2001, in accordance with the transition provisions of SFAS
No. 133, the Company recorded a loss of $15.2 million in accumulated other
comprehensive loss representing the cumulative effect of an accounting
change to recognize at fair value all cash flow derivatives.  The Company
recorded corresponding cash flow hedge derivative liabilities of $15.2
million.

    During the first quarter of 2001, losses of $2.9 million were
transferred from accumulated other comprehensive loss to oil and gas
revenues related to settled positions and an unrealized gain of $1.2 million
was recorded to other comprehensive income to adjust the fair value of the
open positions.  The Company expects to reclassify as reductions to earnings
during the next twelve months approximately $5.1 million of unrealized
hedging losses in accumulated other comprehensive loss at March 31, 2001.

NOTE 5. COMPREHENSIVE INCOME

    The Company follows SFAS No. 130, "Reporting Comprehensive Income",
which establishes standards for reporting comprehensive income. In addition
to net income, comprehensive income includes all changes in equity during a
period, except those resulting from investments and distributions to the
owners of the Company.  The Company recorded other comprehensive loss for
the first time in the first quarter of 2001.  The following table
illustrates the change in accumulated other comprehensive loss for the
quarter ended March 31, 2001:

<TABLE>
<CAPTION>
                                                              (in thousands)
<S>                                                            <C>
Accumulated other comprehensive loss - December 31, 2000       $     --
Net loss                                                           (494)

Other comprehensive loss:
   Cumulative effect of change in accounting principle -
      January 1, 2001                                           (15,171)
   Reclassification adjustment for settled hedging contracts      2,914
   Changes in fair value of outstanding hedging positions         1,159

Other comprehensive loss                                        (11,098)

Accumulated other comprehensive loss - March 31, 2001          $(11,592)
</TABLE>

NOTE 6. CONTINGENCIES

    In February 2001, the Revenue and Taxation Department of the Jicarilla
Apache Nation (the "Nation") issued to the Company Possessory Interest Tax
assessments for 1998, 1999 and 2000 totaling $1,651,700.  The Company has
filed a protest with the Nation and has taken the position that, among other
things, certain rules and regulations promulgated in December 2000 by the
Nation do not apply to the determination of Possessory Interest Tax for
years prior to 2001.  As of March 31, 2001, the Company had paid an adjusted
amount of approximately $1.8 million, including approximately $150,000 of
accrued interest under protest.  This amount is included in the Company's
March 31, 2001 consolidated balance sheet under other current assets.
Subsequent to March 31, 2001, the Company was assessed an additional $1.9
million of taxes and penalties, of which $1.1 million is related to the
assessment for 2001.  The Company has paid approximately $700,000 of the
additional assessments for 1998, 1999 and 2000 as of May 10, 2001, again
under protest, and expects to pay the 2001 assessment, under protest, in May
2001.  The Company has: 1) requested that the Legislative Council of the
Jicarilla Apache Nation grant the Company relief, and 2) engaged New Mexico
counsel to represent it.  The final outcome of this matter cannot yet be
predicted.

    In December 1998, Del Mar Drilling Company ("Plaintiff") filed a civil
action against Mallon Oil.   Plaintiff sought damages for an alleged breach
of contract in the amount of $348,100, plus interest, costs and attorney's
fees.  In March 2001, the Company settled with the Plaintiff by paying the
Plaintiff $50,000 in cash, and conveying to Plaintiff certain used drilling
materials having an estimated value of $14,000.

NOTE 7. SUBSEQUENT EVENT

    In April 2001, the Company redeemed the remaining 80,000 shares
outstanding of its Series B Mandatorily Redeemable Convertible Preferred
Stock, at the mandatory redemption price of $10 per share, for $803,000
including accrued dividends.
<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 March 31, 2001 and December 31, 2000, and
results of operations and cash flows for the three months ended March 31,
2001 and 2000. Our consolidated financial statements and notes thereto
should be referred to in conjunction with the following discussion.

                                   Overview

    Our revenues, profitability and future growth rates will be
substantially dependent upon our drilling success in the San Juan and
Delaware Basins, and prevailing prices for oil and gas, which are in turn
dependent upon numerous factors that are beyond our control, such as
economic, political and regulatory developments and competition from other
sources of energy. The energy markets have historically been volatile, and
oil and gas prices can be expected to continue to be subject to wide
fluctuations in the future. A substantial or extended decline in oil or gas
prices could have a material adverse effect on our financial position,
results of operations and access to capital, as well as the quantities of
oil and gas reserves that we may produce economically.

                       Liquidity and Capital Resources

    Our operations are capital intensive. Historically, our principal
sources of capital have been cash flow from operations, borrowings and
proceeds from the sale of stock. Our principal uses of capital have been for
the acquisition, exploration and development of oil and gas properties and
related facilities.

    During first quarter 2001, our capitalized costs incurred in oil and gas
producing activities were $6.7 million. Our current 2001 capital expenditure
budget is approximately $23 million.  During first quarter 2001, we drilled
12 wells, of which 11 were successful, and recompleted one well.  Through
May 10, 2001, we have drilled an additional six wells.  We are currently
planning on drilling a total of 33 wells in 2001.  We expect to fund our
capital requirements for the next 12 months out of the proceeds from our
October 2000 equity offering, cash flow from operations, and possible
additional financing.

    In September 1999, the Company established a credit agreement (the
"Aquila Credit Agreement") with Aquila Energy Capital Corporation
("Aquila").  The amount available under the agreement, as amended, is $53.4
million.  By its current terms, the amount available may be increased to as
much as $60 million as new reserves are added through the Company's planned
development drilling program. At March 31, 2001, the Company had drawn $52.3
million, including accrued interest, under the Aquila Credit Agreement.
However, under the current terms of the Aquila Credit Agreement, the
remaining $1.1 million nominally available may not be drawn for capital
expenditures.  Principal payments on the four-year loan are based on the
Company's cash flow from operations, as defined ("the Defined Cash Flow"),
less advances for the Company's development program. As of March 31, 2001,
the advances exceeded cash flow from operations and the Company had not made
any principal payments.  The Company had expected to begin making principal
payments in March 2001 and paid Aquila $1.4 million on April 6, 2001.  On
March 30, 2001, Aquila agreed to waive the requirement for principal
payments equal to the Defined Cash Flow.  Instead, the repayment schedule
for the twelve months beginning April 30, 2001 is as follows:  (i) for the
months April 2001 to September 2001, the Company will pay interest only, or
approximately $2.5 million, and (ii) from October 2001 to March 2002, the
Company will make monthly principal and interest payments of $700,000 or a
total of $4.2 million.  Aquila will evaluate the loan monthly and, at its
sole discretion, can discontinue the repayment schedule described above and
revert to the requirement of principal payments equal to Defined Cash Flow.
The Company anticipates the Aquila Credit Agreement will be amended during
second quarter 2001 to reflect the changes described above.  The Company
will continue to seek to increase the amount available under the Aquila
Credit Agreement and to revise the repayment requirements.  However, there
can be no assurance that the Company will be successful in its efforts to
further amend the Aquila Credit Agreement.  The Aquila Credit Agreement is
secured by substantially all of our oil and gas properties.  Interest on the
Aquila Credit Agreement accrues at prime plus 2% and was added to the loan
balance through March 31, 2001. The outstanding loan balance is due in full
on September 9, 2003. As part of the Aquila financing, we also entered into
a four year agency agreement with Aquila under which we pay a marketing fee
equal to 1% of the net proceeds (as defined) from the sale of all of our oil
and gas production to market our gas and to negotiate our gas purchase
contracts.  In addition, we also issued to Aquila 490,000 shares of common
stock. Aquila also has a one-time right to require us to purchase 490,000 of
our common shares from Aquila at $12.50 per share during the 30-day period
beginning September 9, 2003.

    We are currently considering options to secure additional capital to
continue our active drilling and development program through 2001.  The
options include the issuance of preferred or other equity securities.
However, there is no assurance that we will be able to obtain additional
funding.

    In September 1999 we also entered into a five-year, $5.5 million master
rental contract with Universal Compression, Inc. to refinance our East
Blanco gas sweetening plant. The proceeds from that financing were used to
repay a term loan from Bank One, Texas, N.A. that was secured by the plant.
The master rental contract bears interest at an imputed rate of 12.8%. We
made principal payments totaling $106,000 to Universal Compression during
first quarter 2001.

    In July 1998, we negotiated an unsecured term loan for up to $205,000
with Bank One, Colorado, N.A. to finance the purchase of land and a building
for our field office. We drew $155,000 on this loan during 1998.  We repaid
$4,000 of this loan during first quarter 2001.

    Under the mandatory redemption feature of our Series B Mandatorily
Redeemable Convertible Preferred Stock we were required to, and did, redeem
the remaining 80,000 shares in April 2001 at the mandatory redemption price
of $10.00 per share.

    In April 2000, the Government of Costa Rica awarded the Company a
concession to explore for oil and natural gas on approximately 2.3 million
acres in the northeast quadrant of Costa Rica.  The Company has completed an
environmental assessment of its proposed operations, and is currently in the
process of negotiating final concession contracts.  Once the Company signs
final contracts, the work program is expected to require the expenditure of
approximately $8.8 million (including the drilling of six wells) over a
three-year period, with a possible extension of three more years.

<TABLE>
<CAPTION>
                            Results of Operations

                                               Three Months Ended March 31,
                                                         2001        2000
                                        (In thousands, except per unit data)
<S>                                                    <C>         <C>
Operating Results from Oil and Gas Operations:
    Oil and gas sales                                  $7,093      $3,920
    Production tax and marketing expenses               1,506         557
    Lease operating expenses                            1,216       1,106
    Depletion                                           1,734       1,251
    Depreciation                                           75          44

Net Production:
    Oil (MBbl)                                             45          43
    Natural gas (MMcf)                                  1,449       1,444
    Mmcfe                                               1,719       1,702

Average Sales Price Realized (1):
    Oil (per Bbl)                                      $25.27      $23.84
    Natural gas (per Mcf)                               $4.11       $2.00
    Per Mcfe                                            $4.13       $2.30

Average Cost Data (per Mcfe):
    Production tax and marketing expenses               $0.88       $0.33
    Lease operating expenses                            $0.70       $0.65
    Depletion                                           $1.01       $0.74
    Depreciation                                        $0.04       $0.03
</TABLE>
_________________
(1)   Includes effects of hedging.

       Three Months Ended March 31, 2001 Compared to March 31, 2000

    Revenues. Total revenues for first quarter 2001 increased 84% to
$7,330,000 from $3,982,000 for first quarter 2000.  Oil and gas sales for
first quarter 2001 increased 81% to $7,093,000 from $3,920,000 for first
quarter 2000 primarily due to higher oil and gas prices realized.  Average
oil prices per barrel for first quarter 2001 increased 6% to $25.27 from
$23.84 for first quarter 2000. Average gas prices per Mcf for first quarter
2001 increased 106% to $4.11 from $2.00 for first quarter 2000.  Oil
production for first quarter 2001 increased 5% to 45,000 barrels from 43,000
barrels for first quarter 2000 and gas production for first quarter 2001
remained flat at 1,449,000 Mcf from 1,444,000 Mcf for first quarter 2000.
During first quarter 2001, the Company drilled 11 successful wells and
recompleted one well.  Two wells were put on production at the end of March
and the remainder are expected to be put on production in second quarter
2001.

    Production Tax and Marketing Expenses.  Production tax and marketing
expenses increased 170% to $1,506,000 in first quarter 2001 from $557,000 in
first quarter 2000, primarily due to higher oil and gas prices and higher
tax rates in 2001.  Production taxes are calculated and paid on prices
before hedging gains or losses.  As a percentage of sales before hedging
losses, production tax and marketing expenses were 15% in first quarter 2001
and 13% in first quarter 2000.  Production tax and marketing expenses per
Mcfe increased 167% to $0.88 from $0.33.

    Lease Operating Expenses.  Lease operating expenses increased 10% to
$1,216,000 in first quarter 2001 from $1,106,000 in first quarter 2000.
Lease operating expenses per Mcfe increased 8% to $0.70 in first quarter
2001 from $0.65 per Mcfe in the 2000 quarter due to increased surface
maintenance and waste water disposal costs.

    Depreciation, Depletion and Amortization. First quarter 2001
depreciation, depletion and amortization increased 36% to $1,959,000 from
$1,441,000 in first quarter 2000.  Depletion per Mcfe increased 36% to $1.01
from $0.74, due to a higher ratio of increases in capital expenditures
relative to increases in reserves.

    General and Administrative Expenses. Net general and administrative
expenses for first quarter 2001 increased 14% to $1,355,000 from $1,190,000
in first quarter 2000, primarily due to higher stock compensation expense in
the 2001 quarter, as a result of the issuance of employee stock options with
a below-market strike price and issuance of restricted stock.

    Interest and Other Expenses. Interest and other expenses for first
quarter 2001 increased 36% to $1,788,000 from $1,319,000 for first quarter
2000.  The increase was primarily due to a higher outstanding debt balance
in the 2001 quarter.

    Income Taxes. We incurred net operating losses for U.S. Federal income
tax purposes in 2001 and 2000, which can be carried forward to offset future
taxable income. Statement of Financial Accounting Standards No. 109 requires
that a valuation allowance be provided if it is more likely than not that
some portion or all of a deferred tax asset will not be realized. Our
ability to realize the benefit of our deferred tax asset will depend on the
generation of future taxable income through profitable operations and the
expansion of our oil and gas producing activities. The market and capital
risks associated with achieving the above requirement are considerable,
resulting in our decision to provide a valuation allowance equal to the net
deferred tax asset. Accordingly, we did not recognize any tax expense or
benefit in the consolidated statements of operations for the first quarters
of 2001 and 2000.

    Net Loss. We had a net loss of $494,000 for first quarter 2001 compared
to net loss of $1,631,000 for first quarter 2000 as a result of the factors
discussed above.  We paid the 8% dividend of $16,000 and $27,000 on our
$800,000 face amount Series B Mandatorily Redeemable Convertible Preferred
Stock in the quarters ended March 31, 2001 and 2000, respectively, and
realized accretion of $2,000 and $3,000, respectively.  In addition, during
first quarter 2001 and 2000 we realized accretion of $144,000 and $98,000,
respectively, on the Mandatorily Redeemable Common Stock.  Net loss
attributable to common shareholders for the quarter ended March 31, 2001 was
$656,000 compared to $1,759,000 for the quarter ended March 31, 2000.

                             Hedging Activities

    We use hedging instruments to manage commodity price risks. We have used
energy swaps and other financial arrangements to hedge against the effects
of fluctuations in the sales prices for oil and natural gas. Gains and
losses on such transactions are matched to product sales and charged or
credited to oil and gas sales when that product is sold. Management believes
that the use of various hedging arrangements can be a prudent means of
protecting our financial interests from the volatility of oil and gas
prices. Under our Aquila Credit Agreement, we may be required to maintain
price hedging arrangements in place with respect to up to 65% of our oil and
gas production upon terms satisfactory to us and Aquila. We recognized
hedging losses of $2,914,000 and $527,000 in first quarter 2001 and 2000,
respectively. These amounts are included in oil and gas sales in our
consolidated statements of operations.

                                Miscellaneous

    Our oil and gas operations are significantly affected by certain
provisions of the Internal Revenue Code applicable to the oil and gas
industry. Current law permits our intangible drilling and development costs
to be deducted currently, or capitalized and amortized over a five-year
period. We, as an independent producer, are also entitled to a deduction for
percentage depletion with respect to the first 1,000 barrels per day of
domestic crude oil (and/or equivalent units of domestic natural gas)
produced (if such percentage depletion exceeds cost depletion). Generally,
this deduction is 15% of gross income from an oil and gas property, without
reference to the taxpayer's basis in the property. The percentage depletion
deduction may not exceed 100% of the taxable income from a given property.
Further, percentage depletion is limited in the aggregate to 65% of our
taxable income. Any depletion disallowed under the 65% limitation, however,
may be carried over indefinitely.

    Inflation has not historically had a material impact on our financial
statements, and management does not believe that we will be materially more
or less sensitive to the effects of inflation than other companies in the
oil and gas industry.

    The preceding information contains forward-looking statements, the
realization of which cannot be assured. Actual results may differ
significantly from those forecast. When evaluating us, our operations, or
our expectations, the reader should bear in mind that we and our operations
are subject to numerous risks and uncertainties. Among these are risks
related to the oil and gas business generally (including operating risks and
hazards and the regulations imposed thereon), risks and uncertainties
related to the volatility of the prices of oil and gas, uncertainties
related to the estimation of reserves of oil and gas and the value of such
reserves, uncertainties relating to geologic models and evaluations, the
effects of competition and extensive environmental regulation, and other
factors, many of which are necessarily beyond our control. These and other
risk factors that affect our business are discussed in our 2000 Form 10-K.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

    We use commodity derivative financial instruments, including swaps, to
reduce the effect of natural gas and crude oil price volatility on a portion
of our natural gas and crude oil production. Commodity swap agreements are
generally used to fix a price at the natural gas or crude oil market
location or to fix a price differential between a benchmark price of natural
gas and crude oil and the price of gas or crude oil at its market location.
Settlements are based on the difference between a fixed and a variable price
as specified in the agreement. The following table summarizes our derivative
financial instrument position on our natural gas and crude oil production as
of March 31, 2001.  The fair value of these instruments reflected below is
the estimated amount that we would receive (or pay) to settle the contracts
as of March 31, 2001.  Actual settlement of these instruments when they
mature will differ from these estimates reflected in the table. Gains or
losses realized from these instruments hedging our production are expected
to be offset by changes in the actual sales price received by us for our
natural gas and crude oil production. See "Hedging Activities" above.

<TABLE>
<CAPTION>
Natural Gas:

                                 Fixed Price
    Year            MMBtu        per MMBtu          Fair Value
    <S>             <C>          <C>                <C>
    2001            1,699,000    $2.55-$3.94        $(3,696,000)
    2002            1,558,000    $2.55-$3.91         (2,900,000)
    2003              996,000    $2.55               (1,593,000)
    2004              852,000    $2.55               (1,324,000)

Crude Oil:

                                 Fixed Price
    Year            Bbls         per Bbl            Fair Value
    <S>             <C>          <C>                <C>
    2001               45,000    $17.38-$18.30      $(374,000)
    2002               60,000    $17.40              (431,000)
    2003               48,000    $17.40              (266,000)
    2004               48,000    $17.40              (238,000)
</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 5,105,000 MMBtu for 2001 - 2004 with a fair value of $(88,000).

    We also entered into "costless collar" contracts pursuant to which we
hedged the price of 60,000 MMBtu per month in 2001 based on an El Paso-
Permian Index.  We will receive $3.85 per MMBtu if the settlement price is
below $3.85 per MMBtu.  If the settlement price is greater than $5.80 per
MMBtu, we will pay the difference between such settlement price and $5.80
per MMBtu.  At March 31, 2001, the fair value of the put and call contracts
was a loss of $(188,000).

                        PART II  --  OTHER INFORMATION

Item 1.  Legal Proceedings

     The information contained in Note 6 to the consolidated financial
statements set forth in Part I is hereby incorporated by reference.

Item 6.  Exhibits and Reports on Form 8-K

(a)  Exhibits:

     None.

(b)  Reports on Form 8-K:

     During first quarter 2001, the Company filed two Periodic Reports on
Form 8-K dated March 13, 2001 and March 19, 2001, each related to an "Item
5. Other Events" matter.


                                    SIGNATURES

    Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.

                                    MALLON RESOURCES CORPORATION
                                    Registrant


Date:  May 15, 2001                 By:  /s/ Roy K. Ross
                                          Roy K. Ross
                                          Executive Vice President


Date:  May 15, 2001                 By:  /s/ Alfonso R. Lopez
                                          Alfonso R. Lopez
                                          Vice President, Finance/Treasurer