__________________________________________________

                     Securities and Exchange Commission
                          Washington, D.C.  20549
                                  Form 10-K

(mark one)

[X]  Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
     Act of 1934

For the fiscal year ended December 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 number 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)               (zip code)

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

Securities registered pursuant to Section 12(b) of the Act:   None

Securities registered pursuant to Section 12(g) of the Act:
                                      Common Stock, par value $0.01 per share
                                                (Title of Class)

    Indicate by check mark whether the registrant (l) 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 for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days:

     [X] Yes     [   ] No

    As of the close of business on March 15, 2002, the aggregate market value
of the shares of voting stock held by non-affiliates of the registrant, based
upon the sales price for a share of the registrant's Common Stock as reported
on the Nasdaq National Market tier of the Nasdaq Stock Market, was
approximately $14,114,000.

    As of March 15, 2002, 10,867,827 shares of the registrant's Common Stock,
par value $0.01 per share, were outstanding.

    Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment hereto.     [X]


             __________________________________________________
<PAGE>


                          Mallon Resources Corporation

                                  Form 10-K
                           for the fiscal year ended
                               December 31, 2001

                               Table of Contents

PART I                                                                    Page
Items 1- 2  Business and Properties. . . . . . . . . . . . . . . . . . . . . 1
             General History  . . . . . . . . . . . . . . . . . . . . . . .  1
             Business Strategies. . . . . . . . . . . . . . . . . . . . . .  1
             Historical Highlights . . . . . . . . . . . . . . . . . . . .   1
             Our Oil and Gas Properties . . . . . . . . . . . . . . . . . .  2
             Gas Sweetening Plant. . . . . . . . . . . . . . . . . . . . .   3
             Acreage. . . . . . . . . . . . . . . . . . . . . . . . . . . .  3
             Summary Oil and Gas Reserve Data. . . . . . . . . . . . . . .   3
             Drilling Activity. . . . . . . . . . . . . . . . . . . . . . .  3
             Recompletion Activity. . . . . . . . . . . . . . . . . . . . .  4
             Productive Wells. . . . . . . . . . . . . . . . . . . . . . .   4
             Production and Sales. . . . . . . . . . . . . . . . . . . . . . 4
             Marketing. . . . . . . . . . . . . . . . . . . . . . . . . . .  4
             Corporate Offices; Officers, Directors and Key Employees. . . . 5
             Cautionary Statement Regarding Forward-Looking Statements. . .  6
             Risk Factors. . . . . . . . . . . . . . . . . . . . . . . . .   6
Item 3      Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . .  12
Item 4      Submission of Matters to a Vote of Security Holders. . . . . .  12
PART II
Item 5      Market for Registrant's Common Equity and Related Stockholder
               Matters. . . . . . . . . . . . . . . . . . . . . . . . . .   13
             Price Range of Common Stock. . . . . . . . . . . . . . . . .   13
             Holders. . . . . . . . . . . . . . . . . . . . . . . . . . .   13
             Dividend Policy. . . . . . . . . . . . . . . . . . . . . . .   13
Item 6      Selected Financial Data. . . . . . . . . . . . . . . . . . . .  14
Item 7      Management's Discussion and Analysis of Financial Condition
               and Results of Operations. . . . . . . . . . . . . . . . .   15
             Overview. . . . . . . . . . . . . . . . . . . . . . . . . . .  15
             Critical Accounting Policies. . . . . . . . . . . . . . . .    15
             Contractual Commitments and Obligations. . . . . . . . . . .   16
             Liquidity and Capital Resources. . . . . . . . . . . . . . .   17
             Results of Operations. . . . . . . . . . . . . . . . . . . .   20
             Hedging Activities. . . . . . . . . . . . . . . . . . . . .    23
             Miscellaneous. . . . . . . . . . . . . . . . . . . . . . . .   23
Item 7A     Quantitative and Qualitative Disclosure about Market Risk. . .  24
             Commodity Price Risk. . . . . . . . . . . . . . . . . . . . .  24
             Interest Rate Risk. . . . . . . . . . . . . . . . . . . . . .  24
Item 8      Financial Statements and Supplementary Data. . . . . . . . . .  24
Item 9      Changes in and Disagreements with Accountants on Accounting
               and Financial Disclosure. . . . . . . . . . . . . . . . . .  24
PART III
Item 10     Directors and Executive Officers of the Registrant. . . . . .  .25
Item 11     Executive Compensation
Item 12     Security Ownership of Certain Beneficial Owners and Management. 26
Item 13     Certain Relationships and Related Transactions. . . . . . . .  .27
PART IV
Item 14     Exhibits, Financial Statement Schedules and Reports
              on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . .  28
SIGNATURES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  .29
EXHIBIT INDEX. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  30
GLOSSARY OF CERTAIN INDUSTRY TERMS. . . . . . . . . . . . . . . . . . . . . 31
CONSOLIDATED FINANCIAL STATEMENTS
Index to Consolidated Financial Statements . . . . . . . . . . . . . . . . F-1
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . F-2
Consolidated Balance Sheets . . . . . . . . . . . . . . . . . . . . . . .  F-3
Consolidated Statements of Operations . . . . . . . . . . . . . . . . . .  F-4
Consolidated Statements of Shareholders' Equity . . . . . . . . . . . . . .F-5
Consolidated Statements of Cash Flows . . . . . . . . . . . . . . . . . .  F-7
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . F-8
<PAGE>


                                    PART I

ITEMS 1 AND 2:  BUSINESS AND PROPERTIES

General History

    As used in this report, any reference to "Mallon," "we," "our" or the
"Company" means Mallon Resources Corporation and its subsidiaries, unless the
context suggests otherwise. We have included definitions of technical terms
and abbreviations important to an understanding of our business under
"Glossary of Certain Industry Terms."

    We are an independent energy company engaged in oil and natural gas
exploration, development and production. We conduct our operations through our
wholly-owned subsidiary, Mallon Oil Company. We operate primarily in the State
of New Mexico, where all of our estimated proved reserves are located in the
San Juan Basin, where we have been active since 1984. As of December 31, 2001,
our proved reserves consisted of 53.1 billion cubic feet of natural gas and
27,800 barrels of crude oil, with a pre-tax PV-10 of $25.6 million. At
December 31, 2001, we owned interests in 166 gross (134 net) producing wells
and operated 145, or 87%, of them.

    Our common stock is traded on the Nasdaq National Market tier of the
Nasdaq Stock Market under the symbol "MLRC." Our executive offices are at 999
18th Street, Suite 1700, Denver, Colorado 80202 (telephone 303/293-2333). Our
transfer agent is Securities Transfer Corporation, Frisco, Texas.

Business Strategies

    Our primary business objective is to increase our proved oil and gas
reserves and cash flows. We pursue this objective by:

    -  Conducting Exploration through Exploitation. Our primary operating
strategy is to increase our proved reserves through relatively low-risk
activities such as development drilling, recompletions, multi-zone completions
and enhanced recovery activities. Numerous potentially productive geologic
formations tend to be stacked atop one another in the San Juan Basin. This
allows us to target multiple potential pay zones in most wells, thus reducing
drilling risks, and to conduct exploration operations in conjunction with our
development drilling. Wells drilled to one horizon offer opportunities to
examine up-hole zones or can be drilled to deeper prospective formations for
relatively little additional cost.

    -  Controlling Our Operations. For the year ended December 31, 2001,
approximately 95% of our production was from properties that we operate. We
believe that this level of operating control, combined with our operating
experience in the San Juan Basin, allows us to better control ongoing
operations and costs, field development decisions, and the timing and nature
of capital expenditures.

    -  Developing and Controlling Our Infrastructure. By owning and
controlling our critical infrastructure, such as gas gathering systems, gas
sweetening plants and produced water disposal facilities, we believe that we
can better manage our costs.

Historical Highlights

    In September 1993, we purchased a group of Delaware Basin properties from
Pennzoil Exploration and Production Company. In January 1997, we acquired
additional interests in our key San Juan Basin gas property, East Blanco
Field, and became operator of the field. In October 1996, December 1997, and
September 2000, we completed public financings in which we sold an aggregate
of 7.3 million shares of common stock for combined net proceeds of $48.1
million. These financings, together with our debt financing from Aquila Energy
Capital Corporation ("Aquila"), enabled us to develop our inventory of oil and
gas properties.

    In May 1998, we significantly increased our acreage in East Blanco Field
in the San Juan Basin by entering into a Minerals Development Agreement
("MDA") with the Jicarilla Apache Nation. This acreage is adjacent to our
original East Blanco acreage.  Portions of this MDA, consisting of undeveloped
wildcat acreage, were allowed to expire in September 2001, resulting in
current holdings in the field of approximately 51,300 acres.

    In April 2000, we received permission to commingle the gas produced from
different zones in our East Blanco wells. Prior to this approval, wells in the
field were limited to producing from not more than two zones at a time.
Commingling, which permits us to produce gas from multiple producing
formations at the same time, results in improvements in well economics. We
plan to commingle the production from most new wells that we drill at East
Blanco, and to recomplete selected older wells in order to commingle their
production.

    In September 2001, we completed the sale of all of our oil and gas
properties located in the Delaware Basin in southeast New Mexico. The sale
included our interests in 23 fields, consisting of interests in 141 producing
wells and 13,742 net mineral acres. The adjusted purchase price received was
approximately $31.5 million. We applied approximately $24.1 million of the
proceeds to reduce our debt to Aquila by approximately 47%.

Our Oil and Gas Properties

    We are active in the San Juan Basin of northwestern New Mexico. At
December 31, 2001, this area accounted for substantially all of our
approximately 53.3 Bcfe of estimated proved reserves. We have been active in
the San Juan Basin since 1984, where our primary area of interest is our East
Blanco natural gas field. At December 31, 2001, we owned interests in
approximately 58,400 gross (55,000 net) acres of oil and gas properties in the
San Juan Basin. Wells on this acreage produce from a variety of zones in the
San Jose, Nacimiento, Ojo Alamo, Pictured Cliffs, Mesaverde, Mancos and Dakota
formations.  We plan to commence pilot programs to test the Fruitland Coal
Formation and Lewis Shale, which are present throughout much of our East
Blanco acreage.  We will need to obtain additional capital or joint venture
partners in order to undertake these projects.

East Blanco Field, Rio Arriba County, New Mexico

    We own interests in approximately 51,300 gross (50,000 net) acres in the
East Blanco natural gas field on the eastern flank of the San Juan Basin. We
have been involved in the development of East Blanco Field since 1986. All
production in the field has been natural gas. East Blanco wells typically
contain reserves in one or more of the following productive zones: the
Pictured Cliffs Sandstone at approximately 3,600 feet, the Ojo Alamo Sandstone
at approximately 3,000 feet, the Nacimiento Formation at approximately 2,000
feet and the San Jose Formation at approximately 1,500 feet. The wells also
penetrate the Fruitland Coal Formation at approximately 3,800 feet, which is
productive in fields adjacent to East Blanco. The Lewis Shale, at
approximately 5,500 feet, also underlies most of our East Blanco acreage. We
operate all 134 of our East Blanco Field wells, in which we have an average
working interest of approximately 94% and an average net revenue interest of
approximately 75%. As of December 31, 2001, our estimated proved reserves in
East Blanco Field were approximately 52.3 Bcfe, or approximately 98% of our
total estimated proved reserves.

    During 2001, we drilled 21 wells and recompleted 1 well at East Blanco.
This drilling and recompletion work was done primarily to put Pictured Cliffs,
Ojo Alamo, Nacimiento and San Jose gas on production. Based on our operations
to date, we have identified more than 200 remaining drilling and recompletion
opportunities on our East Blanco acreage.

Other San Juan Basin Fields

    Gavilan Field, Rio Arriba County, New Mexico. We own and operate seven
wells in this field, in which our average working interest is approximately
44%. We have leasehold interests in approximately 2,400 gross (1,260 net)
acres in this field. Current production is primarily natural gas from the
Mancos Shale at approximately 6,900 feet and from the Mesaverde Formation at
approximately 5,400 feet. As of December 31, 2001, Gavilan Field contained
approximately 0.7 Bcfe or approximately 1% of our total estimated proved
reserves.

    Otero Field, Rio Arriba County, New Mexico. We own and operate three wells
in this field, in which our average working interest is approximately 95%. We
have leasehold interests in approximately 4,600 gross (3,700 net) acres in
this field. The wells produce oil from the Mancos Shale at approximately 4,700
feet. As of December 31, 2001, Otero Field contained only a nominal portion of
our total estimated proved reserves.

                                  Other Areas

    All of our oil and gas operations are currently conducted on-shore in the
United States. In addition to the properties described above, we have
interests in properties in the states of Colorado, Oklahoma, North Dakota and
Alabama. While we intend to continue to produce our existing wells in those
states, we currently do not expect to engage in any development activities in
those areas.  In 1999, we bid to obtain certain oil and gas concession rights
in Costa Rica. We have been advised that our bids, for concessions covering a
total of approximately 2.35 million acres, have been accepted, but concession
contracts have yet to be signed.

Gas Sweetening Plant

    We designed, constructed, own and operate an amine plant to remove the
hydrogen sulfide from the gas produced at East Blanco. This plant treats the
majority of the natural gas we produce at East Blanco. The plant's current
capacity is 32 MMcf per day. With added compression, the plant's capacity can
be increased to approximately 60 MMcf per day, without requiring substantial
expansion.

Acreage

    We believe we have satisfactory title to our oil and gas properties based
on standards prevalent in the oil and gas industry, subject to exceptions that
do not detract materially from the value of the properties. The following
table summarizes our oil and gas acreage holdings as of December 31, 2001:
<TABLE>
<CAPTION>
                      Developed          Undeveloped
    Area              Gross    Net       Gross    Net
<S>                   <C>      <C>       <C>      <C>
    San Juan Basin    25,077   22,057    33,281   32,917
    Other              6,440      930     1,688      156

          Total       31,517   22,987    34,969   33,073
                      ======   ======    ======   ======
</TABLE>

Summary Oil and Gas Reserve Data

    The following table sets forth summary information concerning our
estimated proved oil and gas reserves as of December 31, 2001, based on a
report prepared by Netherland, Sewell & Associates, Inc., independent
petroleum engineers.  Netherland, Sewell & Associates, Inc. is sometimes
referred to herein as the "Independent Engineer," and its report is sometimes
referred to herein as the "Reserve Report." All calculations in the Reserve
Report have been made in accordance with the rules and regulations of the
Securities and Exchange Commission and give no effect to federal or state
income taxes otherwise attributable to estimated future net revenues from the
sale of oil and gas. The present value of estimated future net revenues has
been calculated using a discount factor of 10%. The commodity prices used in
this calculation were $1.92 per Mcf for natural gas and $16.50 per barrel for
oil.

<TABLE>
<CAPTION>
                                  December 31, 2001
     <S>                             <C>
     Proved Reserves:
       Natural gas (MMcf)            53,139
       Oil (MBbl)                        28
       Total (MMcfe)                 53,307
     Proved Developed Reserves:
       Natural gas (MMcf)            37,635
       Oil (MBbl)                        16
       Total (MMcfe)                 37,731
     PV-10 (in thousands):          $25,657
</TABLE>

Drilling Activity

    The following table reflects our drilling activities for each of the last
three years:

<TABLE>
<CAPTION>
            Gross Wells                    Net Wells
            Productive   Dry   Total       Productive   Dry    Total
    <S>     <C>          <C>   <C>         <C>          <C>    <C>
    1999    21           1     22          18.05        1.00   19.05
    2000    27           1     28          26.72        1.00   27.72
    2001    19           2     21          19.00        2.00   21.00
</TABLE>


Recompletion Activity

    The following table contains information concerning our well recompletion
activities for each of the last three years:

<TABLE>
<CAPTION>
            Gross Wells                    Net Wells
            Productive   Dry   Total       Productive   Dry    Total
    <S>     <C>          <C>   <C>         <C>          <C>    <C>
    1999     6           1      7          5.67         0.92   6.59
    2000    10           0     10          8.42         0      8.42
    2001     2           0      2           .73         0       .73
</TABLE>

Productive Wells

   The following table summarizes our gross and net interests in productive
wells at December 31, 2001. Net interests represented in the table are net
"working interests," which bear the cost of operations.

<TABLE>
<CAPTION>
                     Gross Wells                 Net Wells
                     Oil   Natural Gas   Total   Oil   Natural Gas   Total
    <S>              <C>   <C>           <C>     <C>   <C>           <C>
    San Juan Basin    4    139           143     3.39   127.54       130.93
    Other            12     11            23      .74     2.63         3.37

        Total        16    150           166     4.13   130.17       134.30
                     ==    ===           ===     ====   ======       ======
</TABLE>

Production and Sales
    The following table sets forth information concerning our total oil and
gas production and sales for each of the last three fiscal years:
<TABLE>
<CAPTION>
                                               Year Ended December 31,
                                               2001     2000     1999
    <S>                                        <C>      <C>      <C>
    Net Production:
        Natural gas (MMcf)                      5,954    6,022    5,600
        Oil (MBbl)                                105      171      172
        Total (MMcfe)                           6,584    7,048    6,632
    Average Sales Price Realized (1):
        Natural gas (per Mcf)                  $ 2.83   $ 2.10   $ 1.81
        Oil (per Bbl)                          $23.97   $24.43   $17.38
        Per Mcfe                               $ 2.94   $ 2.38   $ 1.98
    Average Cost (per Mcfe):
        Production tax and marketing expense   $ 0.56   $ 0.49   $ 0.25
        Lease operating expense (2)            $ 1.27   $ 0.59   $ 0.52
        Depletion                              $ 0.98   $ 0.79   $ 0.65
</TABLE>
___________________
(1) Includes effects of hedging.
(2) Lease operating expense in 2001 includes assessments for possessory
interest taxes, interest and penalties of $2.2 million for 1998-2000 and $1.1
million for 2001 which we are protesting.

Marketing

    Our natural gas is generally sold on the spot market or pursuant to short-
term contracts. Oil and liquids are generally sold on the open market to
unaffiliated purchasers, generally pursuant to purchase contracts that are
cancelable on 30 days notice. The price paid for this production is generally
an established or posted price that is offered to all producers in the field,
plus any applicable differentials. Prices paid for crude oil and natural gas
fluctuate substantially.

    Because future prices are difficult to predict, we hedge a portion of our
oil and gas sales to protect against market downturns. The nature of hedging
transactions is such that producers forego the benefit of some price increases
that may occur after the hedging arrangement is in place. We nevertheless
believe that hedging is prudent in certain circumstances in order to minimize
the risk of falling prices. Under our credit agreement with Aquila, we are
required to maintain price hedging arrangements in place with respect to up to
65% of our oil and gas production. In addition, we also entered into an agency
agreement with Aquila under which we pay a marketing fee equal to 1% of the
net proceeds (as defined) from the sale of our oil and gas production to
market our gas and to negotiate our gas purchase contracts.

Corporate Offices; Officers, Directors and Key Employees

    Our executive offices are located at 999 18th Street, Suite 1700, Denver,
Colorado 80202, where our phone number is (303) 293-2333. We employ 17
employees at this office. We maintain a field operations office in Durango,
Colorado, where we employ a total of 13 individuals.

    The following are the members of our Board of Directors and our executive
officers:

    Name    Age    Title(s)
    George O. Mallon, Jr       57   Director, Chairman of the Board, CEO and
                                      President
    Roy K. Ross                51   Director, Executive Vice President,
                                      Secretary and General Counsel
    Peter H. Blum              44   Director, Executive Vice President
    Frank Douglass             68   Director
    Roger R. Mitchell          69   Director
    Francis J. Reinhardt, Jr.  72   Director
    Alfonso R. Lopez           53   Vice President - Finance and Treasurer

    The directors serve until the next annual meeting of shareholders.
Following are brief descriptions of the business experience of our directors
and executive officers:

    George O. Mallon, Jr. has been our President and Chairman of the Board
since December 1988, when we were organized. He formed Mallon Oil in 1979. Mr.
Mallon earned a B.S. degree in Business from the University of Alabama in 1965
and an M.B.A. degree from the University of Colorado in 1977.

    Roy K. Ross has been Executive Vice President and General Counsel of
Mallon since 1992. He was named Secretary of Mallon in 1997. From June 1976
through September 1992, Mr. Ross was an attorney in private practice with the
Denver-based law firm of Holme Roberts & Owen. Mr. Ross is also Executive Vice
President, Secretary, General Counsel and a director of Mallon Oil. He earned
his B.A. degree in Economics from Michigan State University in 1973 and his
J.D. degree from Brigham Young University in 1976.

    Peter H. Blum became a director of Mallon in January 1998. He became an
Executive Vice President of Mallon in September 2001. Since October 1998, Mr.
Blum, a financial consultant, has been President of Bear Ridge Capital LLC.
From April 1997 to October 1998, Mr. Blum was Senior Managing Director, head
of investment banking, for the investment banking firm Gaines, Berland Inc.
From 1995 to 1997, Mr. Blum held the position of Managing Director, head of
energy banking, with the investment banking firm Rodman & Renshaw, Inc. From
1992 to 1995, Mr. Blum held various positions with the investment banking firm
Mabon Securities, Inc. Mr. Blum earned a B.B.A. degree in accounting from the
University of Wisconsin in 1979.

    Frank Douglass has been a director of Mallon since its formation in 1988.
In 1998, he retired as a Senior Partner in the Texas law firm of Scott,
Douglass & McConnico, LLP, where he had been a partner since 1976. Mr.
Douglass earned a B.B.A. degree from Southwestern University in 1953 and a
L.L.B. degree from the University of Texas School of Law in 1958.

    Roger R. Mitchell has been a director of Mallon since 1990. Prior to 1989,
Mr. Mitchell served as a co-general partner with Mallon of a series of private
oil and gas drilling limited partnerships sponsored by Mallon. Mr. Mitchell
has participated in or managed a number of real estate, insurance and
investment companies, including Mitchell Management Company, which he
currently owns. He earned a B.S. degree in Business from Indiana University in
1954 and an M.B.A. degree from Indiana University in 1956.

    Francis J. Reinhardt, Jr. has been a director of Mallon since 1994. He is
with the New York investment banking firm of Carl H. Pforzheimer & Co., where
he has been a partner since 1966. He is a member and past president of the
National Association of Petroleum Investment Analysts. Mr. Reinhardt is also a
director of The Exploration Company of Louisiana, a public company engaged in
the oil and gas business. Mr. Reinhardt holds a B.S. degree from Seton Hall
University and an M.B.A. from New York University.

    Alfonso R. Lopez joined Mallon in July 1996 as Vice President-Finance and
Treasurer. He was Vice President - Finance for Consolidated Oil & Gas, Inc.
(now Chesapeake Energy Corporation) from 1993 to 1995. Mr. Lopez was a
consultant from 1991 to 1992. From 1981 to 1990, he was Controller for Decalta
International Corporation, a Denver-based exploration and production company.
He served as Controller for Western Crude Oil, Inc. (now Texaco Trading and
Transportation, Inc.) from 1978 to 1981. Mr. Lopez is a certified public
accountant and was with Arthur Young & Company (now Ernst & Young) from 1970
to 1978. Mr. Lopez earned his B.A. degree in Accounting and Business
Administration from Adams State College in Colorado in 1970.

Key Employees

    Employees who are instrumental to our success include the following
individual:

    Donald M. Erickson, Jr. was named Senior Vice President and General
Manager of Mallon Oil in June 2001. Prior to that time he was Vice President -
Operations of Mallon Oil since February 1997. Mr. Erickson has more than 20
years of experience in oil field operations. Prior to joining Mallon, he was
Operations Manager for Presidio Exploration, Inc. (which was merged into Tom
Brown Inc.) from December 1988 to January 1997. Mr. Erickson earned a Heating
and Cooling Technical Degree from Central Technical Community College in
Hastings, Nebraska in 1975 and has studied Mechanical Engineering at the
University of Colorado, Denver.

Cautionary Statement Regarding Forward-Looking Statements

    This report contains forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934, including statements regarding, among other items, our
growth strategies, the potential for the recovery of additional volumes of
hydrocarbons, anticipated trends in our business and our future results of
operations, market conditions in the oil and gas industry, our ability to make
and integrate acquisitions, the outcome of litigation and the impact of
governmental regulation. These forward-looking statements are based largely on
our expectations and are subject to a number of risks and uncertainties, many
of which are beyond our control. Actual results could differ materially from
these forward-looking statements as a result of, among other things:

  -  a decline in natural gas production or natural gas prices,

  -  incorrect estimates of required capital expenditures,

  -  increases in the cost of drilling, completion and gas collection or other
costs of production and operations,

  -  an inability to meet growth projections, and

  -  other risk factors set forth under "Risk Factors" below.

    In addition, the words "believe," "may," "will," "estimate," "continue,"
"anticipate," "intend," "expect" and similar expressions, as they relate to
Mallon, our business or our management, are intended to identify forward-
looking statements. We undertake no obligation to publicly update or revise
any forward-looking statements, whether as a result of new information, future
events or otherwise after the date of this report. In light of these risks and
uncertainties, the forward-looking events and circumstances discussed in this
report may not occur and actual results could differ materially from those
anticipated or implied in the forward-looking statements.

Risk Factors

    In evaluating us and our common stock, readers should consider carefully,
among other things, the following risk factors.

    Oil and gas prices are volatile, and an extended decline in prices could
adversely affect our revenue, cash flows and profitability.

    Our revenues, operating results, profitability, future rate of growth and
the carrying value of our oil and gas properties depend heavily on prevailing
market prices for oil and gas. We expect the markets for oil and gas to
continue to be volatile. Any substantial or extended decline in the price of
oil or gas would have a material adverse effect on our financial condition and
results of operations. It could reduce our cash flow and borrowing capacity,
as well as the value and the amount of our reserves. At December 31, 2001,
substantially all of our estimated proved reserves were natural gas.
Accordingly, we are impacted more directly by volatility in the price of
natural gas.

    We cannot predict future oil and natural gas prices. Various factors
beyond our control that could affect prices of oil and gas include:

  -  worldwide and domestic supplies of oil and gas,

  -  the ability of the members of the Organization of Petroleum Exporting
Countries to agree to and maintain oil price and production controls,

  -  political instability or armed conflict in oil or gas producing regions,

  -  the price and level of foreign imports,

  -  worldwide economic conditions,

  -  marketability of production,

  -  the level of consumer demand,

  -  the price, availability and acceptance of alternative fuels,

  -  the availability of pipeline capacity,

  -  weather conditions, and

  -  actions of federal, state, local and foreign authorities.

    These external factors and the volatile nature of the energy markets make
it difficult to estimate future prices of oil and gas. We enter into energy
swap agreements and other financial arrangements at various times to attempt
to minimize the effect of oil and natural gas price fluctuations. We cannot
assure you that such transactions will reduce risk or minimize the effect of
any decline in oil or natural gas prices. Any substantial or extended decline
in oil or natural gas prices would have a material adverse effect on our
business and financial results. Energy swap arrangements may limit the risk of
declines in prices, but such arrangements may also limit revenues from price
increases.

    Lower oil and gas prices may cause us to record ceiling limitation write-
downs.

   We periodically review the carrying value of our oil and gas properties
under the full cost accounting rules of the Securities and Exchange
Commission. Under these 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 the proved properties, as
adjusted for related tax effects. Application of the ceiling test generally
requires pricing future revenue at the unescalated prices in effect as of the
end of each fiscal quarter and requires a write-down for accounting purposes
if the ceiling is exceeded. We may be required to write down the carrying
value of our oil and gas properties when oil and gas prices are depressed or
unusually volatile. If a write-down is required, it would result in a charge
to earnings, but would not impact cash flow from operating activities. Once
incurred, a write-down of oil and gas properties is not reversible at a later
date. We recorded a $16.4 million write-down of the carrying value of our oil
and gas properties in third quarter 2001 and a $16.8 million write-down in
fourth quarter 1998.

    Our operations require large amounts of capital.

    Our current development plans will require us to make large capital
expenditures for the exploration and development of our properties.
Historically, we have funded our capital expenditures through a combination of
funds generated internally from sales of production, equity offerings, and
long and short-term debt financing arrangements. We currently do not have any
sources of additional financing other than our existing credit agreement with
Aquila and our equipment leases. We cannot be sure that any additional
financing will be available to us on acceptable terms. Future cash flows and
the availability of financing will be subject to a number of variables, such
as:

  -  the level of production from existing wells,

  -  prices of oil and natural gas, and

  -  our results in locating and producing new reserves and the results of our
natural gas development project at East Blanco Field.

    Issuing equity securities to satisfy our financing requirements could
cause substantial dilution to our existing shareholders. Debt financing could
lead to:

  -  a substantial portion of our operating cash flow being dedicated to the
payment of principal and interest,

  -  our being more vulnerable to competitive pressures and economic
downturns, and

  -  restrictions on our operations.

    If our revenues were to decrease due to lower oil and natural gas prices,
decreased production or other reasons, and if we could not obtain capital
through our credit facility or otherwise, our ability to execute our
development plans, replace our reserves or maintain production levels could be
greatly limited.

    Estimates in this report concerning our oil and gas reserves and future
net revenue estimates are uncertain.

    There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and their values, including many factors
beyond our control. Estimates of proved undeveloped reserves, which comprise a
significant portion of our reserves, are by their nature uncertain. The
reserve information included or incorporated by reference in this report are
only estimates and are based upon various assumptions, including assumptions
required by the Securities and Exchange Commission, relating to oil and gas
prices, drilling and operating expenses, capital expenditures, taxes and
availability of funds. Although we believe they are reasonable, actual
production, revenues and expenditures will likely vary from estimates, and
these variances may be material.

    Estimates of oil and natural gas reserves, by necessity, are projections
based on geologic and engineering data, and there are uncertainties inherent
in the interpretation of such data as well as the projection of future rates
of production and the timing of development expenditures. Reserve engineering
is a subjective process of estimating underground accumulations of oil and
natural gas that are difficult to measure. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation and judgment. Estimates of economically recoverable
oil and natural gas reserves and future net cash flows necessarily depend upon
a number of variable factors and assumptions, such as historical production
from the area compared with production from other producing areas, the assumed
effects of regulations by governmental agencies and assumptions governing
future oil and natural gas prices, future operating costs, severance and
excise taxes, development costs and workover and remedial costs, all of which
may in fact vary considerably from actual results. For these reasons,
estimates of the economically recoverable quantities of oil and natural gas
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
expected therefrom may vary substantially. Any significant variance in the
assumptions could materially affect the estimated quantity and value of the
reserves. Actual production, revenues and expenditures with respect to our
reserves will likely vary from estimates, and such variances may be material.

    In addition, you should not construe PV-10 as the current market value of
the estimated oil and natural gas reserves attributable to our properties. We
have based the estimated discounted future net cash flows from proved reserves
on prices and costs as of the date of the estimate, in accordance with
applicable regulations, whereas actual future prices and costs may be
materially higher or lower. Many factors will affect actual future net cash
flow, including:

  -  prices for oil and natural gas,

  -  the amount and timing of actual production,

  -  supply and demand for oil and natural gas,

  -  curtailments or increases in consumption by crude oil and natural gas
purchasers, and

  -  changes in governmental regulations or taxation.

    The timing of the production of oil and natural gas properties and of the
related expenses affect the timing of actual future net cash flow from proved
reserves and, thus, their actual present value. In addition, the 10% discount
factor, which we are required to use to calculate PV-10 for reporting
purposes, is not necessarily the most appropriate discount factor given actual
interest rates and risks to which our business or the oil and natural gas
industry in general are subject.

    Our long-term financial success will depend on our ability to replace the
reserves we produce.

    In general, the volume of production from oil and gas properties declines
as reserves are depleted. The decline rates depend on reservoir
characteristics. Our reserves will decline as they are produced unless we
acquire properties with proved reserves or conduct successful development and
exploration activities. Our future natural gas and oil production is highly
dependent upon our level of success in finding or acquiring additional
reserves. The business of exploring for, developing or acquiring reserves is
capital intensive and uncertain. We may be unable to make the necessary
capital investment to maintain or expand our oil and gas reserves if cash flow
from operations is reduced and external sources of capital become limited or
unavailable. We cannot assure you that our future development, acquisition and
exploration activities will result in additional proved reserves or that we
will be able to drill productive wells at acceptable costs.

    We depend heavily on successful development of our San Juan Basin
properties.

    Our future success depends on our ability to develop additional natural
gas reserves on our San Juan Basin properties that are economically
recoverable. Most of our proved reserves are in the San Juan Basin, and our
development plans make our future growth highly dependent on increasing
production and reserves in the San Juan Basin. Our proved reserves will
decline as reserves are depleted, except to the extent we conduct successful
exploration or development activities or acquire other properties containing
proved reserves. Our development plan includes increasing our reserve base
through continued drilling and development of our existing properties in the
San Juan Basin. Our San Juan Basin properties can only be effectively
developed and evaluated by drilling activities and the evaluation of drilling
results. Less costly means of evaluation, such as 3-D seismic, are not helpful
on properties such as ours. We cannot be sure that our planned projects will
lead to significant additional reserves or that we will be able to continue
drilling productive wells at acceptable finding and development costs.

    The oil and gas exploration business involves a high degree of business
and financial risk.

    The business of exploring for and, to a lesser extent, developing oil and
gas properties is an activity that involves a high degree of business and
financial risk. Property acquisition decisions generally are based on various
assumptions and subjective judgments that are speculative. Although available
geological and geophysical information can provide information about the
potential of a property, it is impossible to predict accurately the ultimate
production potential, if any, of a particular property or well. Moreover, the
successful completion of an oil or gas well does not ensure a profit on
investment. A variety of factors, both geological and market-related, can
cause a well to become uneconomic or only marginally economic.

    Our industry is subject to numerous hazards.

    The oil and natural gas industry involves operating hazards such as well
blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or
well fluids, fires, formations with abnormal pressures, pipeline ruptures or
spills, pollution, releases of toxic gas and other environmental hazards and
risks, any of which could cause us substantial losses. In addition, we may be
liable for environmental damage caused by previous owners of property we own
or lease. As a result, we may face substantial liabilities to third parties or
governmental entities, which could reduce or eliminate funds available for
exploration, development or acquisitions or cause us to incur losses. In
accordance with industry practice, we maintain insurance against some, but not
all, of the risks described above. An event that is not fully covered by
insurance -- for instance, losses resulting from pollution and environmental
risks, which are not fully insurable -- could have a material adverse effect
on our financial condition and results of operations. Further, our insurance
may not be adequate to cover losses or liabilities and the insurance we do
have may not continue to be available at premium levels that justify its
purchase.

    Exploratory drilling is an uncertain process with many risks.

    Exploratory drilling involves numerous risks, including the risk that we
will not find any commercially productive natural gas or oil reservoirs. The
cost of drilling, completing and operating wells is often uncertain, and a
number of factors can delay or prevent drilling operations, including:

  -  unexpected drilling conditions,

  -  pressure or irregularities in formations,

  -  equipment failures or accidents,

  -  adverse weather conditions,

  -  compliance with governmental requirements, and

  -  shortages or delays in the availability of drilling rigs and the delivery
of equipment.

    Our future drilling activities may not be successful, nor can we be sure
that our overall drilling success rate, or our drilling success rate for
activity within a particular area, will not decline. Unsuccessful drilling
activities could have a material adverse effect on our results of operations
and financial condition. Also, we may not be able to obtain any options or
lease rights in potential drilling locations that we identify. Although we
have identified numerous potential drilling locations, we cannot be sure that
we will ever drill them or that we will produce oil or natural gas from them
or any other potential drilling locations.

    Our key assets are concentrated in a small geographic area.

    The majority of our natural gas production is processed through our East
Blanco gas sweetening plant. Our production, revenue and cash flow will be
adversely affected if this plant's operation is shut down, curtailed or
limited for any reason. Substantially all of our operations are currently
located in one geologic basin in New Mexico.  Because of this geographic
concentration, any regional events that increase costs, reduce availability of
equipment or supplies, reduce demand or limit production, including weather
and natural disasters, may impact us more than if our operations were more
geographically diversified.

    The availability of markets for our natural gas is beyond our control.
Substantially all of our gas is produced in the San Juan Basin in the State of
New Mexico and, consequently, we are particularly sensitive to marketing
constraints that exist or may arise in the future in that area. Historically,
due to the San Juan Basin's relatively isolated location and the resulting
limited access of its natural gas production to the marketplace, natural gas
produced in the San Juan Basin has tended to command prices that are lower
than natural gas prices that prevail in other areas.

    Our business depends on transportation facilities owned by others.

    The marketability of our gas production depends in part on the
availability, proximity and capacity of pipeline systems owned by third
parties. Although we have some contractual control over the transportation of
our product, material changes in these business relationships could materially
affect our operations. Federal and state regulation of gas and oil production
and transportation, tax and energy policies, changes in supply and demand and
general economic conditions could adversely affect our ability to produce,
gather and transport natural gas.

    We face marketing, trading and credit risks.

    The marketability of our production depends in part upon the availability,
proximity and capacity of gas gathering systems, pipelines and processing
facilities. Federal, state and tribal regulation of oil and gas production and
transportation could adversely affect our ability to produce and market oil
and natural gas.

    In addition, the marketing of our oil and natural gas requires us to
assess and respond to changing market conditions, including credit risks. If
we are unable to respond accurately to changing conditions in the commodity
markets, our results of operations could be materially adversely affected. We
try to limit our exposure to price risk by entering into various hedging
arrangements. We are exposed to credit risk because the counterparties to
agreements might not perform their contractual obligations.

    Our hedging arrangements might limit the benefit of increases in commodity
prices.

    To reduce our exposure to short-term fluctuations in the price of oil and
natural gas, we enter into hedging arrangements from time to time with regard
to a portion of our oil and natural gas production. These hedging arrangements
limit the benefit of increases in the price of oil or natural gas while
providing only partial protection against declines in prices. Under our credit
agreement with Aquila, we are required to maintain price hedging arrangements
in place with respect to up to 65% of our oil and gas production.

    Our industry is heavily regulated.

    Federal, state, tribal and local authorities extensively regulate the oil
and gas industry. Legislation and regulations affecting the industry are under
constant review for amendment or expansion, raising the possibility of changes
that may affect, among other things, the pricing or marketing of oil and gas
production. Noncompliance with statutes and regulations may lead to
substantial penalties, and the overall regulatory burden on the industry
increases the cost of doing business and, in turn, decreases profitability.
State, tribal and local authorities regulate various aspects of oil and gas
drilling and production activities, including the drilling of wells (through
permit and bonding requirements), the spacing of wells, the unitization or
pooling of oil and gas properties, environmental matters, safety standards,
the sharing of markets, production limitations, plugging and abandonment, and
restoration.

    We must comply with complex environmental regulations.

    Our operations are subject to complex and constantly changing
environmental laws and regulations adopted by federal, state, tribal and local
governmental authorities. New laws or regulations, or changes to current legal
requirements, could have a material adverse effect on our business. We could
face significant liabilities to the government and third parties for
discharging oil, natural gas or other pollutants into the air, soil or water,
and we could have to spend substantial amounts of monies on investigations,
litigation and remediation. Our failure to comply with applicable
environmental laws and regulations could result in the assessment of
administrative, civil or criminal penalties. We cannot be sure that existing
environmental laws or regulations, as currently interpreted or reinterpreted
in the future, or future laws or regulations will not materially adversely
affect our results of operations and financial condition or that we will not
face material indemnity claims with respect to properties we own or lease or
have owned or leased.

    Our industry is highly competitive.

    We operate in a highly competitive environment. Major oil companies,
independent producers, and institutional and individual investors are actively
seeking oil and gas properties throughout the world, along with the equipment,
labor and materials required to operate properties. Many of our competitors
have financial and technological resources vastly exceeding those available to
us. Many oil and gas properties are sold in competitive bidding processes, as
to which we may lack technological information or expertise available to other
bidders. We cannot be sure that we will be successful in acquiring and
developing profitable properties in the face of this competition.

    We depend on key personnel.

    Our success will continue to depend on the continued services of our
executive officers and a limited number of other senior management and
technical personnel. Loss of the services of any of these people could have a
material adverse effect on our operations. Unlike many other companies in our
industry, we do not maintain "key man" insurance on the lives of any of our
employees. We have employment agreements with four of our executives.

    Our operations have not been profitable.

    We recorded net losses for 1997, 1998, 1999, 2000 and 2001, of $3,704,000,
$18,186,000, $2,777,000, $6,531,000 and $31,365,000, respectively. Our ability
to continue in business and maintain our financing arrangements may be
adversely affected by a continued lack of profitability.

    We do not pay dividends.

    We have never declared or paid any cash dividends on our common stock and
have no intention to do so in the foreseeable future.

    Our articles of incorporation have provisions that discourage corporate
takeovers and could prevent shareholders from realizing a premium on their
investment.

    Our articles of incorporation contain provisions that may have the effect
of delaying or preventing a change in control. Our articles of incorporation
authorize the Board of Directors to issue up to 10,000,000 shares of preferred
stock without shareholder approval and to set the rights, preferences and
other designations, including voting rights, of those shares as the Board may
determine. These provisions, alone or in combination with each other and with
the rights plan described below, may discourage transactions involving actual
or potential changes of control, including transactions that otherwise could
involve payment of a premium over prevailing market prices to shareholders for
their common stock. Our Board of Directors adopted a shareholder rights
agreement designed to enhance the Board's ability to prevent an acquirer from
depriving shareholders of the long-term value of their investment and to
protect shareholders against attempts to acquire Mallon by means of unfair or
abusive takeover tactics. However, the existence of the rights plan may impede
a takeover of Mallon not supported by the Board, including a takeover that may
be desired by a majority of our shareholders or involving a premium over the
prevailing stock price.

ITEM 3:  LEGAL PROCEEDINGS

    In 1992, the Minerals Management Service commenced an audit of royalties
payable on production from certain oil and gas properties in which we own an
interest. The audit was initiated against the predecessor operator of the
properties (Robert Bayless), but we have a significant interest in the
resolution of the matters that arise out of the audit. On December 22, 2000,
administrative decisions were rendered in the case of Robert L. Bayless, MMS-
98-0132-IND relating to so-called "dual-accounting" and "major portion"
matters. Bayless has joined with one other producer to appeal the
administrative rulings by filing Bayless v. United States Department of the
Interior, No. 1:01CV00393, in the United States District Court for the
District of Columbia. The law firm of Fulbright & Jaworski, L.L.P.
(Washington, DC), is representing the producers. The primary issue in dispute
is the manner in which so-called "major portion" prices are determined. If the
MMS's proposed protocol is ultimately upheld, we will be liable for additional
unpaid royalties, interest and (perhaps) penalties. If a more reasonable
protocol is established, as we expect will be the case, our exposure for such
items should be immaterial.

    As of June 30, 2001, the Revenue and Taxation Department of the Jicarilla
Apache Nation (the "Nation") had issued to us Possessory Interest Tax
assessments for 1998, 1999, 2000 and 2001 totaling $3.3 million, as adjusted,
including related penalties and interest.  We have paid the assessments under
protest.  We protested the assessments arguing 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. Our protests have been denied by the Nation's Revenue and Taxation
Department.  We have: 1) filed an appeal to the Nation's Tribal Court, 2)
requested that the Legislative Council of the Nation grant us relief, and 3)
engaged the New Mexico law firm of Modrall, Sperling, Roehl, Harris & Sisk,
P.A., to represent us in this matter. The final outcome of this matter cannot
yet be predicted.

    In June 2001, in connection with staff cuts that were a part of general
corporate overhead reductions, we terminated our employment of several
individuals.  On August 14, 2001, one of those former employees filed a
complaint in the Federal District Court for the District of New Mexico, in
which he claims his employment was wrongfully terminated. That case, Costalez
v. Mallon Oil, CIV-01 929, is in the very early stages of discovery.  We have
retained the law firm of Holme Roberts & Owen LLP to defend us and the other
named defendants.  We believe the allegations of the suit are wholly without
merit, and intend to defend ourselves vigorously. This case is in the early
stages of discovery, and no outcome can yet be predicted.

ITEM 4:  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

    None.
<PAGE>


PART II
ITEM 5:  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Price Range of Common Stock

    Our common stock is traded on the Nasdaq National Market tier of the
Nasdaq Stock Market under the symbol "MLRC."  The following table sets forth,
for the periods indicated, the high and low sale prices of the common stock as
reported on the Nasdaq National Market.

<TABLE>
<CAPTION>
                                           High       Low
    <S>                                    <C>        <C>
    Year Ending December 31, 2000:
        First Quarter                      $6.250     $3.813
        Second Quarter                      9.750      5.250
        Third Quarter                       8.750      6.063
        Fourth Quarter                      7.688      4.938
    Year Ending December 31, 2001:
        First Quarter                       8.375      5.875
        Second Quarter                      8.250      5.300
        Third Quarter                       5.960      2.000
        Fourth Quarter                      3.650      2.190
    Year Ending December 31, 2002:
        First Quarter (through March 15)    3.040      0.900
</TABLE>

Holders

    As of March 15, 2002, there were approximately 600 shareholders of record
of the common stock.

Dividend Policy

    We do not intend to pay cash dividends on our common stock in the
foreseeable future. We instead intend to retain any earnings to support our
growth. Any future cash dividends would depend on future earnings, capital
requirements, our financial condition and other factors deemed relevant by our
Board of Directors.  Under the terms of our credit facility with Aquila, we
may not pay dividends without the consent of Aquila.  For a description of the
credit facility, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations - Liquidity and Capital Resources."
<PAGE>


ITEM 6:  SELECTED FINANCIAL DATA

    The following table sets forth selected consolidated financial data for
each of the years in the five-year period ended December 31, 2001. This
information should be read in conjunction with the consolidated financial
statements and "Management's Discussion of Financial Condition and Results of
Operations," included elsewhere herein.


<TABLE>
<CAPTION>
                                                      Year Ended December 31,
                                                      2001        2000        1999       1998       1997
<S>                                                   <C>         <C>         <C>        <C>        <C>
Selected Statements of Operations Data:               (In thousands, except per share data)

  Revenues:
    Oil and gas sales                                 $ 19,340    $ 16,803    $ 13,138   $ 13,069   $ 8,582
    Other                                                  425         504         160        109        69
                                                        19,765      17,307      13,298     13,178     8,651

  Costs and expenses:
    Oil and gas production (1)                          12,049       7,595       5,107      5,273     3,037
    Depreciation, depletion and amortization             7,399       6,382       4,822      5,544     2,725
    Impairment of oil and gas properties                16,418          --          --     16,842        24
    Impairment of mining properties                         --          --          --         --       350
    Loss on sale of oil and gas properties               3,109          --          --         --        --
    General and administrative                           6,439       3,609       2,915      2,562     2,274
    Interest and other                                   5,716       6,252       3,126      1,143       701
                                                        51,130      23,838      15,970     31,364     9,111

  Equity in loss of affiliate                               --          --          --         --    (3,244)
  Loss before extraordinary item                       (31,365)     (6,531)     (2,672)   (18,186)   (3,704)

  Extraordinary loss on early retirement of debt            --          --        (105)        --        --
  Net loss                                             (31,365)     (6,531)     (2,777)   (18,186)   (3,704)

  Accretion of mandatorily redeemable common stock        (605)       (428)       (116)        --        --
  Dividends on preferred stock and accretion               (21)        (85)       (120)      (120)     (185)
  Preferred stock conversion inducement                     --          --          --         --      (403)

  Net loss attributable to common shareholders        $(31,991)   $ (7,044)   $ (3,013)  $(18,306)  $(4,292)
                                                      ========    ========    ========   ========   =======

Per Share Data:
  Loss attributable to common shareholders
    before extraordinary item                         $  (2.99)   $  (0.83)   $  (0.40)  $  (2.61)  $ (0.92)
  Extraordinary loss                                        --          --       (0.01)        --        --

  Net loss attributable to common shareholders        $  (2.99)   $  (0.83)   $  (0.41)  $  (2.61)  $ (0.92)
                                                      ========    ========    ========   ========   =======

  Weighted average shares outstanding                   10,686       8,525       7,283      7,015     4,682

Other Data:
  Capital expenditures                                $ 17,510    $ 18,207    $ 9,852    $ 36,354   $20,169

Selected Balance Sheet Data:
  Working capital (deficit)                           $     54    $    377    $(2,678)   $ (3,782)  $ 1,190
  Total assets                                          37,971      91,710     65,426      58,452    51,426
  Long-term debt (2)                                    28,970      40,180     34,874      27,183         1
  Mandatorily redeemable preferred stock                    --         798      1,341       1,329     1,317
  Mandatorily redeemable common stock (3)                4,853       4,248      3,450          --        --
  Shareholders' (deficit) equity                          (599)     28,536     19,490      22,164    40,196
</TABLE>




(1) Lease operating expense for 2001 includes assessments for possessory
interest taxes, interest and penalties of $2.2 million for 1998-2000 and $1.1
million for 2001, which were paid in 2001 under protest.
(2) Long-term debt includes long-term debt net of current maturities and
unamortized discount, notes payable-other and lease obligations net of current
portion.
(3) Represents the obligation to purchase 490,000 shares of common stock from a
shareholder for a price of $12.50 per share in September 2003.  See Note 6 to
our consolidated financial statements.
<PAGE>


ITEM 7:  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

    The following discussion is intended to assist in understanding our
historical consolidated financial position at December 31, 2001 and 2000, and
results of operations and cash flows for each of the years ended December 31,
2001, 2000 and 1999. Our historical consolidated financial statements and
notes thereto included elsewhere in this report contain detailed information
that 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 natural 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 natural gas prices can be expected to
continue to be subject to wide fluctuations in the future. A substantial or
extended decline in gas prices could have a material adverse effect on our
financial position, results of operations and access to capital, as well as
the quantities of gas reserves that we may produce economically.

Critical Accounting Policies

    The following summarizes several of our critical accounting policies.  See
a complete list of significant accounting policies in Note 1 to the
consolidated financial statements.

Use of Estimates and Significant Risks:

    The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make
significant estimates and assumptions that affect the amounts reported in
these financial statements and accompanying notes. The more significant areas
requiring the use of estimates relate to oil and gas reserves, fair value of
financial instruments, valuation allowance for deferred tax assets, and useful
lives for purposes of calculating depreciation, depletion and amortization.
Actual results could differ from those estimates.

    Our operations are subject to numerous risks and uncertainties. Among
these are risks related to the oil and gas business (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,
the effects of competition and extensive environmental regulation, and many
other factors, many of which are necessarily out of our control. The nature of
oil and gas drilling operations is such that the expenditure of substantial
drilling and completion costs are required well in advance of the receipt of
revenues from the production developed by the operations. Thus, it will
require more than several quarters for the financial success of that strategy
to be demonstrated. Drilling activities are subject to numerous risks,
including the risk that no commercially productive oil or gas reservoirs will
be encountered.

Oil and Gas Properties:

    Oil and gas properties are accounted for using the full cost method of
accounting.  Under this method, all costs associated with property
acquisition, exploration and development are capitalized, including general
and administrative expenses directly related to these activities.  All such
costs are accumulated in one cost center, the continental United States.  See
Note 2 to the consolidated financial statements for a complete discussion of
our oil and gas properties.

    Proceeds on disposal of properties are ordinarily accounted for as
adjustments of capitalized costs, with no gain or loss recognized, unless such
adjustment would significantly alter the relationship between capitalized
costs and proved oil and gas reserves.  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
percent, plus the lower of cost or fair market value of unproved properties,
as adjusted for related tax effects.

    Depletion is calculated using the units-of-production method based upon
the ratio of current period production to estimated proved oil and gas
reserves expressed in physical units, with oil and gas converted to a common
unit of measure using one barrel of oil as an equivalent to six thousand cubic
feet of natural gas.

    Estimated abandonment costs (including plugging, site restoration, and
dismantlement expenditures) are accrued if such costs exceed estimated salvage
values, as determined using current market values and other information.
Abandonment costs are estimated based primarily on environmental and
regulatory requirements in effect from time to time.  At December 31, 2001 and
2000, in management's opinion, the estimated salvage values equaled or
exceeded estimated abandonment costs.

Full Cost Ceiling Test:

    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 percent, 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.

Hedging Activities:

    Our use of derivative financial instruments is limited to management of
commodity price and interest rate risks. Gains and losses on such transactions
are accounted for as part of the transaction being hedged.  If an instrument
is settled early, any gains or losses are deferred and recognized as part of
the transaction being hedged.

    We periodically enter into commodity derivative contracts and fixed-price
physical contracts to manage our exposure to oil and gas price volatility.
Commodity derivatives contracts, which are generally placed with major
financial institutions or with counterparties of high credit quality that we
believe are minimal credit risks, may take the form of futures contracts,
swaps or options.  The oil and gas reference prices of these commodity
derivatives contracts are based upon crude oil and natural gas futures which
have a high degree of historical correlation with actual prices received by
us.  Prior to January 1, 2001, we accounted for our commodity derivatives
contracts using the hedge (deferral) method of accounting.  Under this method,
realized gains and losses from our price risk management activities are
recognized in oil and gas revenue when the associated production occurs and
the resulting cash flows are reported as cash flows from operating activities.
Gains and losses from commodity derivatives contracts that are closed before
the hedged production occurs are deferred until the production month
originally hedged.  In the event of a loss of correlation between changes in
oil and gas reference prices under a commodity derivatives contract and actual
oil and gas prices, a gain or loss would be recognized currently to the extent
the commodity derivatives contract did not offset changes in actual oil and
gas prices.

    On January 1, 2001, we 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.

Contractual Commitments and Obligations

    In addition to the Aquila Credit Agreement, we had various other
contractual obligations as of December 31, 2001.  The following table lists
our significant liabilities at December 31, 2001 including the Aquila Credit
Agreement:

<TABLE>
<CAPTION>
                              Payments Due by Period
                              Less than                       After
Contractual Obligations       1 Year   2-3 Years   4-5 Years  5 Years  Total
                              (In thousands)
<S>                           <C>      <C>         <C>        <C>     <C>
Aquila Credit Agreement       $ --     $26,711     $--        $--     $26,711
Lease obligation to Universal
  Compression, Inc.            500       4,067      --         --       4,567
Note payable to Bank One,
  Colorado                      17          33      58         --         108
Operating leases               238          65      --         --         303

                              $755     $30,876     $58        $--     $31,689
                              ====     =======     ===        ===     =======
</TABLE>

    We lease our corporate offices in Denver, Colorado under the terms of an
operating lease, which expires in January 2003.  Yearly payments under the
lease are approximately $150,000.  The office lease in Durango, Colorado
represents a commitment of $26,000 per year through September 2004.  The
remaining operating lease commitments represent equipment leases, which expire
during 2002 through 2003.

Liquidity and Capital Resources

    We have generated net losses of $31.4 million, $6.5 million and
$2.8 million for the years ended December 31, 2001, 2000 and 1999,
respectively.  However, we have generated cash flows from operating activities
of $1.1 million, $4.0 million and $2.4 million for the years ended
December 31, 2001, 2000 and 1999, respectively.

    As discussed more fully in Note 2 to the consolidated financial
statements, on September 14, 2001, we completed the sale of our Delaware Basin
oil and gas properties.  Consequently, our remaining operations are located
primarily in the San Juan Basin of northwest New Mexico.  We have minimal
access to the capital necessary to continue to develop our properties in the
San Juan Basin.  Subsequent to year end, however, we were able to amend our
credit facility to provide, among other things, for a $2.5 million increase in
the borrowings available under the credit facility.  In addition, we are
currently seeking alternate methods of financing our discretionary capital
expenditures for 2002, including joint ventures with industry partners.
However, there is no assurance that we will be able to secure financing on
terms acceptable to us.

    In addition, because production from the San Juan Basin is predominantly
natural gas, we are particularly sensitive to changes in the price of natural
gas.  Historically, natural gas prices have experienced significant
fluctuations and have been particularly volatile in recent years.  Price
fluctuations can result from variations in weather, levels of regional or
national production and demand, availability of transportation capacity to
other regions of the country and various other factors.  Increases or
decreases in natural gas prices received could have a significant impact on
our future results.  If natural gas prices received decline significantly from
those received at year end, or if we are unable to maintain production levels
at our San Juan Basin properties, we may have to implement cost cutting
measures in both our administrative and operating areas.

    As discussed more fully below, in conjunction with the February 2002
amendment to the Aquila Credit Agreement, through December 31, 2002, we are
only required to make interest payments. We believe that cash on hand,
available borrowings under the Aquila Credit Agreement and cash generated from
operating activities will be sufficient to meet our cash requirements through
December 31, 2002.

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

    During the year ended December 31, 2001, our capitalized costs incurred in
oil and gas producing activities were $17.5 million.  During 2001, we drilled
21 wells, of which 19 were successful, and recompleted two wells.  We are
currently evaluating the number of wells we will drill during 2002.  We plan
to fund our capital requirements for the next 12 months with additional
financing or joint venture arrangements.  We cannot be sure that any
additional financing or joint ventures will be available to us on acceptable
terms.

    As discussed above, on September 14, 2001, we completed the sale of our
Delaware Basin properties, effective July 1, 2001, for an adjusted purchase
price of approximately $31.5 million.  After paying approximately $2.0 million
of additional costs related to the sale, we received net proceeds of
approximately $29.4 million, of which we used approximately $24.1 million to
repay a portion of our note payable to Aquila.  The remaining $5.3 million was
used for operations.

    In October 2000, we issued 2,660,000 shares of our common stock in a
public offering at a price of $6.25 per share. We received net proceeds, after
commissions and other costs, of approximately $15.3 million, which was used
primarily to finance our oil and gas drilling activities.

    In September 1999, we established a credit agreement (the "Aquila Credit
Agreement") with Aquila.  Through December 31, 2001, we had drawn $52.3
million, including accrued interest and repaid $25.6 million under the Aquila
Credit Agreement.  Approximately $24.1 million was repaid with the proceeds
from the sale of our Delaware Basin properties in September 2001 as discussed
above.

    The initial amount available under the Aquila Credit Agreement was $45.7
million.  In November 2000, the Aquila Credit Agreement was amended and the
amount available under the agreement was increased by $7.7 million, making the
total available $53.4 million.  Through December 31, 2001, we had drawn $52.3
million, including accrued interest, under the Aquila Credit Agreement, of
which $28.0 million was used to retire the Bank One Facility in September
1999.  Principal payments on the four-year loan began in November 1999 based
on our cash flow from operations, as defined (the "Defined Cash Flow"), less
advances for our development drilling program.  Through December 31, 2000, we
did not make any principal payments because drilling expenditures equaled or
surpassed Defined Cash Flow during that period.  We had expected to begin
making principal payments in March 2001 in amounts equal to the Defined Cash
Flow and paid Aquila $1.4 million on April 6, 2001.  On March 30, 2001, we
negotiated a change in the terms of our agreement with Aquila to delay the
required repayment of principal.  Instead, the repayment schedule for the
twelve months beginning April 30, 2001 was to be 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.  Aquila allowed us to make interest only payments totaling $505,000
for October 2001 to December 2001.  In February 2002, we notified Aquila that
as of December 31, 2001, we would not be in compliance with one of the
covenants under the Aquila Credit Agreement.  That covenant requires us to
maintain projected net revenue attributable to our proved reserves in an
amount sufficient to fully amortize the balance under the Aquila Credit
Agreement by the maturity date of September 9, 2003.  As a result, in February
2002, the Aquila Credit Agreement was amended for a second time, as follows:

(i) As long as no new event of default occurs subsequent to the date of
the second amendment, Aquila has agreed that through December 31, 2002, it
will not exercise any of the remedies available to Aquila due to any event of
default that occurs and is continuing regarding the amount of projected net
revenue required to amortize the amounts outstanding by September 9, 2003.

(ii) Interest on amounts outstanding accrues at prime plus 3% starting
January 1, 2002, through September 30, 2002, and increases to prime plus 4%
after October 1, 2002.  We are required to pay interest only on the
outstanding balance through December 31, 2002.

(iii) The amount available under the agreement was increased by $2.5
million, making the total available $55.9 million.  Aquila may, at its
discretion, advance additional loans up to $2.5 million to be used for our
development operations and/or working capital needs.

(iv) A "change of control" provision was added, which calls for the
prepayment of the entire outstanding balance, together with any accrued and
unpaid interest, at the occurrence of a change of control of the Company.

(v) We have the option to purchase from Aquila 490,000 shares of our
common stock previously issued to Aquila for a price of $2.6 million if a sale
of the Company is consummated prior to September 30, 2002.

(vi) Aquila's one-time right to require us to purchase shares of our common
stock previously issued to Aquila (the "Put Option") was amended to provide
that Aquila has the option to sell to us up to 490,000 shares of our common
stock at $10.00 per share if a sale of the Company is consummated at any time
after September 30, 2002 and prior to September 9, 2003, or at $12.50 per
share if the outstanding balance under the Aquila Credit Agreement is paid on
the earlier of September 9, 2003 or the date on which Aquila notifies us of
the acceleration of payment of the outstanding balance because of the
occurrence of an event of default.

(vii) We issued to Aquila 125,000 shares of the Company's common stock as a
part of the amendment.  If a sale of the Company is not consummated before
October 1, 2002, we will issue Aquila an additional 150,000 shares.

(viii) Upon a change of control of the Company occurring on or before
September 30, 2002, we will pay Aquila $500,000.  If a change of control of
the Company occurs after September 30, 2002, we will pay Aquila $1,250,000.
Through March 29, 2002, we had drawn $800,000 under provision (iii) above, and
had $1.7 million available for future draws.

    The Aquila Credit Agreement is secured by substantially all of our oil and
gas properties and contains various covenants and restrictions, including ones
that could limit our ability to incur other debt, dispose of assets, or change
management.  Interest on the amounts outstanding under the Aquila Credit
Agreement accrues at prime plus 2% and was added to the loan balance through
March 31, 2001.  The weighted average interest rate for borrowings outstanding
under the Aquila Credit Agreement at December 31, 2001 was 7%. The outstanding
loan balance is due in full on September 9, 2003.  As part of the transaction,
we also entered into an Agency Agreement with Aquila under which we pay Aquila
a marketing fee equal to 1% of the net proceeds (as defined) from the sale of
our oil and gas production to market our gas and to negotiate our gas purchase
contracts.

    In 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%. Payments under the
master rental contract commenced in September 1999. We made principal payments
totaling $439,000 and $384,000 to Universal Compression during 2001 and 2000,
respectively.

    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. Principal and
interest is payable quarterly beginning October 1, 1998. We repaid $16,000 and
$15,000 of this loan during 2001 and 2000, respectively. In March 1999, the
due date of the loan was extended from July 1999 to April 2002.  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.

    In April 2000, we redeemed 55,200 shares of our Series B Mandatorily
Redeemable Convertible Preferred Stock at the mandatory redemption price of
$10 per share by issuing a convertible promissory note for $552,000 to the
Series B holder. Interest on the note accrued at 11.3% and was payable
quarterly beginning on June 30, 2000.  The note and all accrued interest was
paid in full in October 2000.  We redeemed the remaining 80,000 shares of
Series B Preferred Stock in April 2001 at $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 $8.8 million (including
the drilling of six wells) over a three-year period, with a possible extension
of three more years. We will need to secure joint venture or other additional
financing in order to complete the work program.

Results of Operations

<TABLE>
<CAPTION>
                                                Year Ended December 31,
                                                2001       2000       1999
                                         (In thousands, except per unit data)
<S>                                             <C>        <C>        <C>
Operating Results from Oil and Gas Operations:
    Oil and gas revenues                        $19,340    $16,803    $13,138
    Production tax and marketing expense          3,655      3,422      1,682
    Lease operating expense (2)                   8,394      4,173      3,425
    Depletion                                     6,476      5,570      4,319
    Depreciation                                    300        258        268
    Impairment                                   16,418         --         --
Net Production:
    Natural gas (MMcf)                            5,954      6,022      5,600
    Oil (MBbl)                                      105        171        172
    Total (MMcfe)                                 6,584      7,048      6,632
Average Sales Price Realized (1):
    Natural gas (per Mcf)                       $  2.83    $  2.10    $  1.81
    Oil (per Bbl)                               $ 23.97    $ 24.43    $ 17.38
    Per Mcfe                                    $  2.94    $  2.38    $  1.98
Average Cost Data (per Mcfe):
    Production tax and marketing expense        $  0.56    $  0.49    $  0.25
    Lease operating expense (2)                 $  1.27    $  0.59    $  0.52
    Depletion                                   $  0.98    $  0.79    $  0.65
</TABLE>
________________
(1) Includes effects of hedging. See "Hedging Activities."
(2) Lease operating expense in 2001 includes assessments for possessory
interest taxes, interest and penalties of $2.2 million for 1998-2000 and $1.1
million for 2001 which we are protesting.
<PAGE>

Year Ended December 31, 2001 Compared with Year Ended December 31, 2000

    Revenues. Total revenues for the year ended December 31, 2001 increased
14% to $19,765,000 from $17,307,000 for the year ended December 31, 2000. Oil
and gas sales for the year ended December 31, 2001 increased 15% to
$19,340,000 from $16,803,000. The increase was due to higher gas prices,
partially offset by oil and gas production declines.  Average oil prices for
the year ended December 31, 2001 decreased 2% to $23.97 per barrel from $24.43
per barrel for the year ended December 31, 2000 and average gas prices for the
year ended December 31, 2001 increased 35% to $2.83 per Mcf from $2.10 per Mcf
for the year ended December 31, 2000. Natural gas constituted approximately
90% of our production in 2001 and 85% in 2000. Oil production for the year
ended December 31, 2001 decreased 39% to 105,000 barrels from 171,000 barrels
for the year ended December 31, 2000 and gas production for the year ended
December 31, 2001 decreased 1% to 5,954,000 Mcf from 6,022,000 Mcf for the
year ended December 31, 2000.  In September 2001, we sold our Delaware Basin
properties, effective July 1, 2001.  The sold properties produced primarily
oil.

    Production Tax and Marketing. Production tax and marketing expenses
increased 7% to $3,655,000 in 2001 from $3,422,000 in 2000.  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 16% and 13% in 2001 and 2000, respectively.
Production tax rates increased in 2001.  In addition, the production tax rate
for our Delaware Basin properties, which we sold in September 2001, averaged
9% of sales compared to our remaining properties in the San Juan Basin which
averaged 18% of sales in 2001.  Production tax and marketing expense per Mcfe
increased $0.07 to $0.56, or 7%, in 2001 from $0.49 in 2000 because of higher
gas prices.

    Lease Operating Expense. Lease operating expenses increased 101% to
$8,394,000 in 2001 from $4,173,000 in 2000.  In 2001, the Jicarilla Apache
Nation assessed us possessory interest taxes, interest and penalties of
approximately $2,200,000 for 1998-2000 and $1,100,000 for 2001.  We paid the
assessments under protest.  These amounts are included in lease operating
expense in 2001.  Excluding the assessment, lease operating expense per Mcfe
increased $0.18, or 31%, to $0.77 in 2001 from $0.59 in 2000 due to higher
plant operation, salt water disposal and surface maintenance costs in 2001
relative to increases in production.

    Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization for the year ended December 31, 2001 increased 16% to $7,399,000
from $6,382,000 for the year ended December 31, 2000, primarily due to higher
depletion expense. Depletion per Mcfe for the year ended December 31, 2001
increased 24% to $0.98 from $0.79 for the year ended December 31, 2000,
primarily due to a higher ratio of increases in capital expenditures to
increases in reserves.

    Impairment of Oil & Gas Properties.  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
$16,418,000.  Had we used the prices in effect at September 30, 2001, the
write-down would have been $25,292,000.  We currently operate only in the
continental United States.

    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 $31,463,000.
After paying approximately $2,033,000 of additional costs which included
approximately $1,325,000 resulting from the settlement of our oil swap
associated with the Delaware Basin properties, we received net proceeds of
$29,430,000.  Of those net proceeds, we used $24,134,000 to repay a portion of
the note payable to Aquila (see Note 3 to our consolidated financial
statements).  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 or 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 $3,128,000 for the year ended
December 31, 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.  Also included in the loss on the sale of oil
and gas properties for 2001 is a net gain of $19,000 on other oil and gas
equipment.

    General and Administrative Expenses. General and administrative expenses
for the year ended December 31, 2001 increased 78% to $6,439,000 from
$3,609,000 for the year ended December 31, 2000. The increase is primarily due
to non-cash stock compensation expense, primarily related to the issuance of
employee stock options with below market strike prices, which was higher in
2001 by approximately $1,924,000.  In addition, unusual non-cash expenses in
2001 related to a termination settlement with one of our former officers and a
partial forgiveness of certain notes receivable from related party
shareholders totaled approximately $907,000.

    Interest and Other Expenses. Interest and other expenses for the year
ended December 31, 2001 decreased 9% to $5,716,000 from $6,252,000 for the
year ended December 31, 2000. The decrease is primarily due to lower
outstanding borrowings and lower interest rates.

    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 benefit in our consolidated
statements of operations for the years ended December 31, 2001 and 2000. At
December 31, 2001, we had a net operating loss carryforward for U.S. Federal
income tax purposes of $47,300,000, which will begin to expire in 2002.

    Net Loss. Net loss for the year ended December 31, 2001 increased to
$31,365,000 from $6,531,000 for the year ended December 31, 2000 as a result
of the factors discussed above. We paid the 8% dividend of $19,000 and $77,000
on $800,000 and $798,000 face amount Series B Mandatorily Redeemable
Convertible Preferred Stock in each of the years ended December 31, 2001 and
2000, respectively, and realized accretion of $2,000 and $8,000, respectively.
In 1999, we issued 420,000 shares of mandatorily redeemable common stock, in
conjunction with a refinancing. In 2000, we issued an additional 70,000 shares
of mandatorily redeemable common stock in conjunction with an amendment to the
same financing agreement. The difference between the value of the shares at
the redemption price of $12.50 per share and the market value of the shares at
the date of issuance is being accreted over a period of up to 49 months.
During 2001 and 2000, we realized accretion of $605,000 and $428,000,
respectively, related to these shares. Net loss attributable to common
shareholders for the year ended December 31, 2001 was $31,991,000 compared to
net loss attributable to common shareholders of $7,044,000 for the year ended
December 31, 2000.

Year Ended December 31, 2000 Compared with Year Ended December 31, 1999

    Revenues. Total revenues for the year ended December 31, 2000 increased
30% to $17,307,000 from $13,298,000 for the year ended December 31, 1999. Oil
and gas sales for the year ended December 31, 2000 increased 28% to
$16,803,000 from $13,138,000. The increase was due to higher oil and gas
prices and higher gas production. Average oil prices for the year ended
December 31, 2000 increased 41% to $24.43 per barrel from $17.38 per barrel
for the year ended December 31, 1999 and average gas prices for the year ended
December 31, 2000 increased 16% to $2.10 per Mcf from $1.81 per Mcf for the
year ended December 31, 1999. Natural gas constituted approximately 85% of our
production in 2000 and 84% in 1999. Oil production for the year ended
December 31, 2000 decreased 1% to 171,000 barrels from 172,000 barrels for the
year ended December 31, 1999 and gas production for the year ended
December 31, 2000 increased 8% to 6,022,000 Mcf from 5,600,000 Mcf for the
year ended December 31, 1999. Gas production for 2000 was up from 1999 because
of the resumption of our drilling and recompletion program in fourth quarter
2000 after the receipt of additional financing. We have been focusing on
drilling gas wells.

    Production Tax and Marketing. Production tax and marketing expenses for
the year ended December 31, 2000 increased 103% to $3,422,000 from $1,682,000
for the year ended December 31, 1999. The increase was primarily attributable
to higher prices in 2000. 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 expense was 13% in both 2000 and 1999.
Production tax and marketing expense per Mcfe increased $0.24, or 96%, to
$0.49 for the year ended December 31, 2000 from $0.25 for the year ended
December 31, 1999.

    Lease Operating Expense. Lease operating expenses ("LOE") increased 22% to
$4,173,000 in 2000 from $3,425,000 in 1999.  LOE per Mcfe increased $0.07, or
13%, to $0.59 for the year ended December 31, 2000 from $0.52 for the year
ended December 31, 1999. LOE per Mcfe in 2000 is higher primarily due to
increased field personnel costs and possessory interest taxes relative to
increases in production.

    Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization for the year ended December 31, 2000 increased 32% to $6,382,000
from $4,822,000 for the year ended December 31, 1999, primarily due to higher
depletion expense. Depletion per Mcfe for the year ended December 31, 2000
increased 22% to $0.79 from $0.65 for the year ended December 31, 1999,
primarily due to a higher ratio of increases in capital expenditures to
increases in reserves.

    General and Administrative Expenses. General and administrative expenses
for the year ended December 31, 2000 increased 24% to $3,609,000 from
$2,915,000 for the year ended December 31, 1999. The increase is primarily due
to the issuance of employee stock options with a below market strike price and
increased costs for contract and consulting services.

    Interest and Other Expenses. Interest and other expenses for the year
ended December 31, 2000 increased 100% to $6,252,000 from $3,126,000 for the
year ended December 31, 1999. The increase is primarily due to higher
outstanding borrowings and higher interest rates.

    Income Taxes. We incurred net operating losses for U.S. Federal income tax
purposes in 2000 and 1999, 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 benefit in our consolidated
statements of operations for the years ended December 31, 2000 and 1999. At
December 31, 2000, we had a net operating loss carryforward for U.S. Federal
income tax purposes of $38,800,000, which will begin to expire in 2001.

    Extraordinary Loss. We incurred an extraordinary loss of $105,000 during
the year ended December 31, 1999, as a result of the refinancing of our debt
with a new lender.

    Net Loss. Net loss for the year ended December 31, 2000 increased 135% to
$6,531,000 from $2,777,000 for the year ended December 31, 1999 as a result of
the factors discussed above. We paid the 8% dividend of $77,000 and $108,000
on $798,000 and $1,341,000 face amount Series B Mandatorily Redeemable
Convertible Preferred Stock in each of the years ended December 31, 2000 and
1999, respectively, and realized accretion of $8,000 and $12,000,
respectively. In 1999, we issued 420,000 shares of mandatorily redeemable
common stock, in conjunction with a refinancing. In 2000, we issued an
additional 70,000 shares of mandatorily redeemable common stock in conjunction
with an amendment to the same financing agreement. The difference between the
value of the shares at the redemption price of $12.50 per share and the market
value of the shares at the date of issuance is being accreted over a period of
up to 49 months. During 2000 and 1999, we realized accretion of $428,000 and
$116,000, respectively, related to these shares. Net loss attributable to
common shareholders for the year ended December 31, 2000 was $7,044,000
compared to net loss attributable to common shareholders of $3,013,000 for the
year ended December 31, 1999.

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
credit agreement with Aquila, 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
$3,292,000, $8,965,000 and $102,000 for the years ended December 31, 2001,
2000 and 1999, respectively.

Miscellaneous

    Our oil and gas operations are significantly affected by certain
provisions of the Internal Revenue Code that are 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.

ITEM 7A:  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk

    We use commodity derivative financial instruments, including swaps, to
reduce the effect of natural gas price volatility on a portion of our natural
gas production. Commodity swap agreements are generally used to fix a price at
the natural gas market location or to fix a price differential between the
price of natural gas at Henry Hub and the price of gas at its market location.
Settlements are based on the difference between a fixed and a variable price
as specified in the agreement.  The fair value of these instruments reflected
below is the estimated amount that we would receive (or pay) to settle the
contracts as of December 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 production. See "Hedging Activities" above.  The following table
summarizes our outstanding energy swaps at December 31, 2001:

<TABLE>
<CAPTION>
                           Fixed Prie
    Year     MMBtu         per MMBtu       Fair Value
    <S>      <C>           <C>             <C>
    2002     1,558,000     $2.55-$3.91     $  94,000
    2003       996,000     $2.55            (629,000)
    2004       852,000     $2.55            (657,000)
</TABLE>

    Under our credit agreement with Aquila, we may be required to maintain
price hedging arrangements in place with respect to up to 65% of our oil and
gas production. Accordingly, included above are agreements to hedge a total of
3,406,000 MMBtu of gas related to production for 2002 -- 2004 at fixed prices
ranging from $2.55-$3.91 per MMBtu. In addition to the amounts in the above
table, we entered into basis swaps to fix the differential between the NYMEX
(Henry Hub) price and the index price at which the hedged gas is to be sold
for 3,406,000 MMBtu for 2002 -- 2004. At December 31, 2001, these basis swaps
had a fair value of $135,000, $(65,000) and $(72,000) for production related
to 2002, 2003 and 2004, respectively.

Interest Rate Risk

    The table below provides information about our financial instruments
sensitive to changes in interest rates, including debt obligations. The table
presents principal cash flows and related weighted average interest rates by
expected maturity dates.

<TABLE>
<CAPTION>
                               Expected Maturity
                                (In thousands)
                                                                         Fair
                        2002   2003      2004    2005   2006  Thereafter Value
<S>                     <C>    <C>       <C>     <C>    <C>   <C>        <C>
Long-term debt:
 Fixed rate             $517   $   586   $3,514   $17    $ 41   $ --   $ 4,675
 Average interest rate  12.7%     12.7%    12.8%   8.0%   8.0%    --
 Variable rate          $  --  $26,711   $   --   $ --   $ --   $ --   $26,711
 Average interest rate     --     7.75%      --     --     --     --
</TABLE>
<PAGE>

ITEM 8:  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

    Our consolidated financial statements that constitute Item 8 follow the
text of this Annual Report on Form 10-K. An index to the consolidated
financial statements appears at page F-1.

ITEM 9:  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

    None.
<PAGE>


PART III

ITEM 10:  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

    Information concerning our directors and executive officers is set forth
in Item 1 of Part I of this report.

ITEM 11:  EXECUTIVE COMPENSATION

    The following table summarizes certain information regarding compensation
awarded to, earned by or paid by us for services rendered for the year ended
December 31, 2001 to our chief executive officer and our four other most
highly compensated individuals whose total compensation, exceeded $100,000 for
such year.


                         SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
                          Annual Compensation                    Long Term Compensation
                                                                 Awards
Name and                                         Other Annual    Restricted     Securities    All Other
Principal                                        Compensation    Stock Awards   Underlying    Compensation
Position           Year   Salary($)   Bonus($)   ($)             ($)            Options (#)   ($)
<S>                <C>    <C>         <C>         <C>             <C>           <C>           <C>
G.O. Mallon, Jr.   2001   190,000     165,434           --             --       132,000        2,625
CEO                2000   175,000      46,320           --             --        24,000        2,625
                   1999   175,000      29,530           --             --            --        2,500

R.K. Ross          2001   155,000      68,513           --             --        30,000        2,625
E.V.P.             2000   140,000      21,625           --             --         9,384        2,625
                   1999   140,000      13,390           --             --            --        2,500

P.H. Blum          2001    42,221       5,969           --          2,910        97,500        1,187
E.V.P.

A.R. Lopez         2001    97,050      51,779           --          9,657        20,000        2,625
Treasurer          2000    97,050      14,924           --             --         8,000        2,625
                   1999    92,400       9,465           --             --            --        2,500

D.M. Erickson      2001   121,500      66,427           --         18,026        50,000        2,625
Senior V.P.        2000   115,500      10,485           --             --         8,000        2,625
of Mallon Oil      1999   110,000       8,295           --             --            --        2,500
</TABLE>

                             OPTION GRANTS IN 2001

<TABLE>
<CAPTION>
                   Individual Grants

                   Number of Securities                             Exercise or                Grant Date
                   Underlying Options     Percent of Total Otions   Base Price    Expiration   Present Value
Name               Granted (#)            Granted in Fiscal Year    ($/Sh)        Date         ($)  (1)
<S>                <C>                    <C>                       <C>           <C>          <C>
G.O. Mallon, Jr.   132,000                27.8%                     0.01          12/31/10     842,160

R.K. Ross           30,000                 6.3%                     0.01          12/31/10     191,400

P.H. Blum           97,500                20.5%                     0.01          12/31/10     622,050

A.R. Lopez          20,000                 4.2%                     0.01          12/31/10     127,600

D.M. Erickson       50,000                10.5%                     0.01          12/31/10     319,000
</TABLE>



1. The Grant Date Present Value of the options was determined using the Black-
Scholes option-pricing model, using the following assumptions: risk-free
interest rate - 4.6%; expected life in years - 6; expected volatility - 99%;
expected dividends - 0.0%.
<PAGE>


    The following table shows the number of shares covered by all exercisable
and unexercisable stock options held by the named individuals as of December
31, 2001, as well as the value of unexercisable "in the money" options at that
date.

             AGGREGATE OPTION EXERCISES IN 2000 AND YEAR END OPTION VALUES


<TABLE>
<CAPTION>
                                      Value      Number of Securities Under-    Value of Unexercised
                    Shares Acquired   Realized   lying Unexercised Options      In-The-Money Options
Name                On Exercise (#)   ($)        At December 31, 2001 (#)       At December 31, 2001 ($)(1)
                                                 Exercisable   Unexercisable    Exercisable   Unexercisable
<S>                 <C>               <C>        <C>           <C>              <C>           <C>
G.O. Mallon, Jr.       --                 --     47,491        132,000          122,665       397,320

R.K. Ross              --                 --     75,560         33,128           38,395        99,715

P.H. Blum              --                 --     49,402         98,833          118,600       247,487

A.R. Lopez          5,334             33,424     22,000         22,666               --         8,025

D.M. Erickson          --                 --     25,334         52,666           76,255       158,525
</TABLE>



(1) Amounts shown represent aggregated fair market value at the share price
on December 31, 2001 of $3.02 per share, less the aggregate exercise price of
the unexercised "in the money" options held. These values have not been, and
may never be, realized. Actual gains, if any, on exercise will depend on the
value of the common stock on the date of exercise.

    Equity Participation Plans. Under the Mallon Resources Corporation 1988
Equity Participation Plan and the Mallon Resources Corporation 1997 Equity
Participation Plan, shares of common stock have been reserved for issuance for
various compensation purposes. The Plans are administered by the Compensation
Committee, currently comprised of Messrs. Reinhardt and Douglass. The terms of
any awards made under the Plans are within the broad discretion of the
Committee. At December 31, 2001, the following options to purchase shares of
our common stock were issued and outstanding under the Plans:

<TABLE>
<CAPTION>
                  Weighted
    Number of     Average
    Shares        Exercise Price
    <S>           <C>
    764,055       $2.10
</TABLE>

    Employee Profit Sharing and Thrift Plan. We established the Mallon
Resources Corporation 401(k) Profit Sharing Plan (the "401(k) Plan") effective
January 1, 1989. We will match an employee's contribution to the 401(k) Plan
in an amount up to 25% of his or her eligible monthly contributions. We may
also contribute additional amounts at the discretion of the Compensation
Committee of the Board of Directors, contingent upon our realization of
earnings that, in the sole discretion of the Board of Directors, are adequate
to justify a corporate contribution. The 401(k) Plan is open to all of our
full time employees who have attained the age of 21.

ITEM 12:  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

    The following table sets forth information concerning the beneficial
ownership of shares of our common stock as of March 15, 2001, by (a) each
shareholder known by us to own of record or beneficially more than 5% of our
outstanding common stock; (b) our chief executive officer (Mr. Mallon); (c)
each of our directors; and (d) all of our directors and executive officers as
a group:

<TABLE>
<CAPTION>
                                                   Number           Percent
Name and address (1)                               of shares        Owned
<S>                                                <C>              <C>
George O. Mallon, Jr.                                693,024 (2)     6.27%
Roy K. Ross                                          147,702 (3)     1.35%
Peter H. Blum                                        110,735 (4)     1.01%
Frank Douglass                                        66,010 (5)        *
Roger R. Mitchell                                     70,813 (6)        *
Francis J. Reinhardt, Jr.                             77,586 (7)        *
Rutabaga Capital Management.                         603,400 (8)     5.55%
Wellington Management Company, LLP                   720,000 (8)     6.63%
Aquila Energy Capital                                615,000 (8)     5.66%
J O Hambro Capital Management Limited              1,578,200 (8)    14.52%
All officers and directors as a group (7 persons)  1,224,438 (9)    10.58%
</TABLE>
__________
*  Less than 1%
1. The address of Messrs. Mallon, Ross, and Blum is 999 18th Street, Suite
1700, Denver, CO 80202. The address of Mr. Douglass is 10424 Woodford, Dallas,
TX 75229. The address of Mr. Mitchell is 113 Cypress Cove Lane, Mooresville,
NC 28117. The address of Mr. Reinhardt is 650 Madison Ave., 23rd Floor, New
York, NY 10022. The address of Rutabaga Capital Management is 64 Broad Street,
3rd Floor, Boston, MA 02109. The address of Wellington Management Company, LLP
is 75 State Street, Boston, MA 02109. The address of Aquila Energy Capital is
909 Fannin Street, Suite 1850, Houston, TX  77010-1007. The address of J O
Hambro Capital Management Limited is Ryder Court, 14 Ryder Street, London SW1Y
6QB, England.

2. Includes 2,166 shares owned by Mr. Mallon's wife and 179,491 shares that
could be acquired by Mr. Mallon upon the exercise of immediately exercisable
stock options and warrants that he holds.

3. Includes 88,688 shares that could be acquired by Mr. Ross upon the exercise
of immediately exercisable stock options and warrants that he holds. Does not
include 20,000 shares covered by stock options that have not yet vested.

4. Includes 63,235 shares that could be acquired by Mr. Blum upon the exercise
of immediately exercisable stock options and warrants that he holds. Does not
include 85,000 shares covered by stock options and warrants that have not yet
vested.

5. Includes 36,406 shares that could be acquired by Mr. Douglass upon the
exercise of immediately exercisable stock options and warrants that he holds.

6. Includes 31,736 shares that could be acquired by Mr. Mitchell upon the
exercise of immediately exercisable stock options that he holds.

7. Includes 34,401 shares that could be acquired by Mr. Reinhardt upon the
exercise of immediately exercisable stock options and warrants that he holds.

8. Based upon information contained in various public filings made with the
S.E.C.

9. Includes 465,290 shares that could be acquired upon the exercise of
immediately exercisable stock options and warrants. Does not include 118,333
shares covered by stock options and warrants that have not yet vested.

ITEM 13:  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

    Under our "Stock Ownership Encouragement Program," in August 1999, Messrs.
Mallon and Ross borrowed $1,585,018 and $391,284, respectively, from us that
they used to exercise certain options owned by them. Messrs. Mallon and Ross
issued promissory notes to us in the noted amounts, which bear interest at the
rate of 7.0% per annum, and are due August 31, 2004. In June 2001, the amounts
due under the notes were reduced to $230,548 and $56,914, respectively.  Upon
the occurrence of a change in control of the Company (as defined in our
Bylaws), all amounts due under the notes will be automatically forgiven.

    In May 2001, we entered into an employment termination agreement with
Kevin M. Fitzgerald, a former officer and director.  Under the agreement, Mr.
Fitzgerald waived certain portions of his employment contract, surrendered
certain options and warrants and conveyed to us his interest in Deep Gas, LLC.
In consideration of Mr. Fitzgerald's concessions, we accelerated the vesting
of certain options held by Mr. Fitzgerald and reduced the amount of a note
receivable from Mr. Fitzgerald.

    In July 1999, we entered into a financial consulting services contract
with Bear Ridge Capital LLC., which is wholly-owned by Mr. Blum, one of our
directors.  Under the contract, Bear Ridge Capital LLC was paid a monthly
retainer and was issued warrants to purchase an aggregate of 40,000 shares of
our common stock at a per share exercise price of $0.01.  Warrants covering
10,000 shares of our common stock vested on July 1, 2001.  The remaining
warrants were forfeited.  During 2001, 2000 and 1999, we paid Bear Ridge
Capital LLC $99,000, $121,000 and $110,000 in fees, respectively, and expensed
$3,000, $26,000 and $25,000 in stock compensation expense, respectively,
related to the warrants.  In September 2001, we entered into an employment
agreement with Mr. Blum, pursuant to which he became Executive Vice President
of the Company.
<PAGE>

                                    PART IV

ITEM 14:  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)  The following documents are filed as a part of this report:

    (1)  Financial Statements

    See the accompanying index to our consolidated financial statements at
page F-1, which lists the documents that are filed as a part of this report.

    (3)  Exhibits

    See the Exhibit Index that follows the signature page to this report and
is incorporated herein by this reference.

(b)  Reports on Form 8-K:

    We filed the following Periodic Report on Form 8-K during the fourth
quarter of 2001:

Date of Report         Item(s) Reported

November 27, 2001      Item 5. "Other Events" - Explore Strategic Alternatives

(c)  Exhibits:

    See the Exhibit Index that follows the signature page to this report and
is incorporated herein by this reference.

<PAGE>

                                   SIGNATURES

    Pursuant to the requirements of Section 13 or 15(d) 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

    Date:  April 4, 2002    By:       /s/ George O. Mallon, Jr.
                                   ____________________________
                                   George O. Mallon, Jr.
                                   Principal Executive Officer

    Date:  April 4, 2002    By:       /s/ Alfonso R. Lopez
                                   ____________________________
                                   Alfonso R. Lopez
                                   Principal Financial Officer
                                   Principal Accounting Officer

    Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.

    Date:  April 4, 2002    By:       /s/ George O. Mallon, Jr.
                                   ____________________________
                                   George O. Mallon, Jr.
                                   Director

    Date:  April 4, 2002    By:       /s/ Frank Douglass
                                   ____________________________
                                   Frank Douglass
                                   Director

    Date:  April 4, 2002    By:       /s/ Roy K. Ross
                                   ____________________________
                                   Roy K. Ross
                                   Director

    Date:  April 4, 2002    By:       /s/ Peter H. Blum
                                   ____________________________
                                   Peter H. Blum
                                   Director
<PAGE>

                                EXHIBIT INDEX
Exhibit
Number  Document Description                                         Location
* 3.01  Amended and Restated Articles of Incorporation of the Company     (1)
* 3.02  Bylaws of the Company                                             (1)
* 3.03  Statement of Designations--Series B Preferred Stock               (2)
* 3.04  Shareholder Rights Agreement                                      (3)
*10.01  Mallon Employee Bonus Pool                                       (10)
*10.02  Equity Participation Plan, amended November 2, 1990               (4)
*10.03  Stock Compensation Plan for Outside Directors                     (5)
*10.04  1997 Equity Participation Plan                                    (6)
*10.05  (Amended and Restated) Employment Contract with CEO              (10)
*10.07  (Amended and Restated) Employment Contract of Executive Vice
            President                                                    (10)
*10.08  Employment Contract of Executive Vice President                  (11)
*10.09  Severance and Sale Program                                        (7)
*10.10  Stock Ownership Encouragement Program                             (8)
*10.11  Promissory Note and Stock Pledge of CEO                           (7)
*10.13  Promissory Note and Stock Pledge of Executive Vice President      (7)
*10.14  Aquila Energy Capital Credit Agreement, dated as of
            September 9, 1999                                             (9)
*10.15  Master Rental Contract with Universal Compression dated
            September 9, 1999                                             (9)
*10.19  Letter Agreement dated February 2000 with George O. Mallon, Jr.  (10)
*10.20  Replacement Promissory Note of CEO                               (12)
*10.21  Replacement Promissory Note of Executive Vice President          (12)
*21.01  Subsidiaries                                                      (4)
    99  Letter to the S.E.C. regarding Arthur Andersen LLP                 #
____________________________
*    These exhibits were filed in previous filings with the S.E.C. identified
below.

1. Incorporated by reference from Mallon Resources Corporation Exhibits to
Registration Statement on Form S-4 (S.E.C. File No. 33-23076) filed on
August 15, 1988.
2. Incorporated by reference from Mallon Resources Corporation (S.E.C. File
No. 0-17267) Form 8-K dated August 24, 1995.
3. Incorporated by reference from Mallon Resources Corporation (S.E.C. File
No. 0-17267) Form 8-K dated April 22, 1997.
4. Incorporated by reference from Mallon Resources Corporation (S.E.C. File
No. 0-17267) Form 10-K for fiscal year ended December 31, 1990.
5. Incorporated by reference from Mallon Resources Corporation Exhibits to
Registration Statement on Form S-8 (S.E.C. File No. 33-39635) filed on
March 28, 1991.
6. Incorporated by reference from Mallon Resources Corporation (S.E.C. File
No. 0-17267) definitive proxy statement for annual meeting of shareholders
held June 6, 1997.
7. Incorporated by reference from Mallon Resources Corporation (S.E.C. File
No. 0-17267) Form 10-K for fiscal year ended December 31, 1999.
8. Incorporated by reference from Mallon Resources Corporation (S.E.C. File
No. 0-17267) Form 8-K dated July 19, 1999.
9. Incorporated by reference from Mallon Resources Corporation (S.E.C. File
No. 0-17267) Form 8-K dated September 9, 1999.
10. Incorporated by reference from Mallon Resources Corporation (S.E.C. File
No. 0-17267) Form 10-K for fiscal year ended December 31, 2000.
11. Incorporated by reference from Mallon Resources Corporation (S.E.C. File
No. 0-17267) Form 10-Q dated September 30, 2001.
12. Incorporated by reference from Mallon Resources Corporation (S.E.C. File
No. 0-17267) Form 10-Q dated June 30, 2001.

#  Filed herewith.
<PAGE>

GLOSSARY OF CERTAIN INDUSTRY TERMS

    Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.

    Bcf. Billion cubic feet.

    Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

    Development location. A location on which a development well can be
drilled.

    Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves.

    Dry hole. A well found to be incapable of producing either oil or gas in
sufficient quantities to justify completion as an oil or gas well.

    Estimated future net revenues. Revenues from production of oil and gas, net
of all production-related taxes, lease operating expenses and capital costs.

    Exploratory well. A well drilled to find and produce oil or gas in an
unproved area, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir, or to extend a known reservoir.

    Gross acres. An acre in which a working interest is owned.

    Gross well. A well in which a working interest is owned.

    MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.

    Mcf. One thousand cubic feet.

    Mcfe. One thousand cubic feet of natural gas equivalent, determined using
the ratio of six Mcf of natural gas (including natural gas liquids) to one Bbl
of crude oil or condensate.

    MMBbl. One million barrels of crude oil or other liquid hydrocarbons.

    MMBtu. One million Btus.

    MMcf. One million cubic feet.

    MMcfe. One million cubic feet of natural gas equivalent.

    Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells.

    PV-10 or present value of estimated future net revenues. Estimated future
net revenues discounted by a factor of 10% per annum, before income taxes and
with no price or cost escalation or de-escalation, in accordance with
guidelines promulgated by the S.E.C.

    Production costs. All costs necessary for the production and sale of oil
and gas, including production and ad valorem taxes.

    Productive well. A well that is producing oil or gas or that is capable of
production.

    Proved developed reserves. Reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

    Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions, i.e., prices and costs as of
the date the estimate is made.  Prices include consideration of changes in
existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.

    Proved undeveloped reserves. Reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion.

    Recompletion. The completion for production of an existing wellbore in
another formation from that in which the well has previously been completed.

    S.E.C. The United States Securities and Exchange Commission.

    Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.

    Working interest. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
<PAGE>

                   Index to Consolidated Financial Statements



                                                                     Page

Report of Independent Public Accountants                             F-2

Consolidated Balance Sheets                                          F-3

Consolidated Statements of Operations                                F-4

Consolidated Statements of Shareholders' Equity                      F-5

Consolidated Statements of Cash Flows                                F-7

Notes to Consolidated Financial Statements                           F-8
<PAGE>


                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS





To the Board of Directors and Shareholders of
Mallon Resources Corporation:

We have audited the accompanying consolidated balance sheets of Mallon
Resources Corporation (a Colorado corporation) and subsidiaries as of
December 31, 2001 and 2000, and the related consolidated statements of
operations, shareholders' equity and cash flows for each of the three years in
the period ended December 31, 2001.  These consolidated financial statements
are the responsibility of the Company's management.  Our responsibility is to
express an opinion on these consolidated financial statements based on our
audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements.  An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation.  We believe that our audits provide
a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Mallon
Resources Corporation and its subsidiaries as of December 31, 2001 and 2000,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2001, in conformity with accounting
principles generally accepted in the United States.

As explained in Notes 1 and 11 to the consolidated financial statements, on
January 1, 2001, the Company changed its method of accounting for derivative
instruments and hedging activity.

ARTHUR ANDERSEN LLP

Denver, Colorado
March 15, 2002
<PAGE>


                        MALLON RESOURCES CORPORATION

                        CONSOLIDATED BALANCE SHEETS
                     (In thousands, except share data)

                                    ASSETS

<TABLE>
<CAPTION>
                                                                                       December 31,
                                                                                       2001        2000
<S>                                                                                    <C>         <C>
Current assets:
  Cash and cash equivalents                                                            $  1,943    $ 14,155
  Accounts receivable:
    Oil and gas sales                                                                       714       3,460
    Joint interest participants, net of allowance of $3 and $39, respectively               302         353
    Other                                                                                     1          19
  Inventories                                                                               151         215
  Derivative asset                                                                          229          --
  Prepaid expenses                                                                           28          --
  Other                                                                                      10         123
         Total current assets                                                             3,378      18,325

Property and equipment:
  Oil and gas properties, full cost method                                               93,933     120,972
  Natural gas processing plant                                                            8,648       8,560
  Other property and equipment                                                            1,085       1,112
                                                                                        103,666     130,644
Less accumulated depreciation, depletion and amortization                               (70,414)    (59,057)
                                                                                         33,252      71,587

Debt issuance costs, net                                                                  1,041       1,529
Other, net                                                                                  300         269

Total Assets                                                                           $ 37,971    $ 91,710
                                                                                       ========    ========

                                   LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
  Trade accounts payable                                                               $  2,153    $  3,689
  Undistributed revenue                                                                     612       2,045
  Accrued taxes and expenses                                                                 42          35
  Current portion of long-term debt                                                         517      12,179
         Total current liabilities                                                        3,324      17,948

Long-term debt, net of unamortized discount of $1,899 and $2,813, respectively           28,970      40,180
Derivative liability                                                                      1,423          --
                                                                                         30,393      40,180

Total liabilities                                                                        33,717      58,128

Commitments and contingencies (Note 4)

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                                         4,853       4,248

Shareholders' equity:
  Common Stock, $0.01 par value, 25,000,000 shares authorized, 10,252,827 and 10,115,093
    shares issued and outstanding, respectively                                             103         101
  Additional paid-in capital                                                             93,012      92,456
  Accumulated deficit                                                                   (92,520)    (61,155)
  Accumulated other comprehensive loss                                                   (1,194)         --
  Notes receivable from shareholders                                                         --      (2,866)
         Total shareholders' equity                                                        (599)     28,536

Total Liabilities and Shareholders' Equity                                             $ 37,971    $ 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)



<TABLE>
<CAPTION>
                                               For the Years Ended
                                               December 31,
                                               2001        2000       1999
<S>                                            <C>         <C>        <C>
Revenues:
  Oil and gas sales                            $ 19,340    $16,803    $13,138
  Interest and other                                425        504        160
                                                 19,765     17,307     13,298

Costs and expenses:
  Oil and gas production                         12,049      7,595      5,107
  Depreciation, depletion and amortization        7,399      6,382      4,822
  Impairment of oil and gas properties           16,418         --         --
  Loss on sale of oil and gas properties          3,109         --         --
  General and administrative, net                 6,439      3,609      2,915
  Interest and other                              5,716      6,252      3,126
                                                 51,130     23,838     15,970

Loss before extraordinary item                  (31,365)    (6,531)    (2,672)
Extraordinary loss on early retirement of debt       --         --       (105)
Net loss                                        (31,365)    (6,531)    (2,777)
Accretion of mandatorily redeemable common stock   (605)      (428)      (116)
Dividends and accretion on preferred stock          (21)       (85)      (120)

Net loss attributable to common shareholders   $(31,991)   $(7,044)   $(3,013)
                                               ========    =======    =======

Basic loss per share:
  Loss attributable to common shareholders
     before extraordinary item                 $  (2.99)   $ (0.83)   $ (0.40)
  Extraordinary loss                                 --         --      (0.01)

Net loss attributable to common shareholders   $  (2.99)   $ (0.83)   $ (0.41)
                                               ========    =======    =======

Basic weighted average common shares
   outstanding                                   10,686      8,525      7,283
                                               ========    =======    =======
</TABLE>













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



                        MALLON RESOURCES CORPORATION

             CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
                   (In thousands, except share amounts)


<TABLE>
<CAPTION
                                                                         Accumulated    Notes
                                                  Additional             Other          Receivable
                              Common Stock        Paid-In   Accumulated  Comprehensive  from
                              Shares      Amount  Capital   Deficit      Loss           Shareholders  Total
<S>                           <C>         <C>     <C>       <C>          <C>            <C>        <C>
Balance, December 31, 1998    7,021,065   $ 70    $73,941   $(51,847)    $     --       $    --    $ 22,164

  Stock options granted              --     --         66         --           --            --          66
  Stock options exercised       392,235      4      2,673         --           --        (2,622)         55
  Accrued interest receivable
    on notes from shareholders       --     --         --         --           --           (61)       (61)
  Warrants issued to director        --     --         25         --           --            --          25
  Extension of warrants'
    expiration date                  --     --        217         --           --            --         217
  Accretion of mandatorily
    redeemable common stock          --     --       (116)        --           --            --       (116)
  Issuance of restricted
    common stock to officers         --     --         37         --           --            --          37
  Dividends on preferred stock       --     --       (108)        --           --            --       (108)
  Accretion of preferred stock       --     --        (12)        --           --            --        (12)
  Net loss                           --     --         --     (2,777)          --            --     (2,777)

Balance, December 31, 1999    7,413,300     74     76,723    (54,624)          --        (2,683)    19,490

  Stock options granted              --     --        761         --           --            --        761
  Stock options exercised        18,567      1         --         --           --            --          1
  Accrued interest receivable
    on notes from shareholders       --     --         --         --           --          (183)      (183)
  Warrants issued to director        --     --         31         --           --            --         31
  Exercise of warrants            8,426     --         67         --           --            --         67
  Accretion of mandatorily
    redeemable common stock          --     --       (428)        --           --            --       (428)
  Issuance of restricted
    common stock to officers         --     --          7         --           --            --          7
  Issuance of common stock
    to officers and directors
    in exchange for oil and
    gas properties               14,800     --        119         --           --            --        119
  Issuance of common stock
    in public offering        2,660,000     26     15,261         --           --            --     15,287
  Dividends on preferred stock       --     --        (77)        --           --            --        (77)
  Accretion of preferred stock       --     --         (8)        --           --            --         (8)
  Net loss                           --     --         --     (6,531)          --            --     (6,531)

Balance, December 31, 2000   10,115,093   $101    $92,456   $(61,155)    $     --       $(2,866)   $28,536
</TABLE>

                               (Continued)


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


                        MALLON RESOURCES CORPORATION

             CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
                   (In thousands, except share amounts)

                               (Continued)


<TABLE>
<CAPTION
                                          Addi-               Accumu-      Notes
                                          tional   Accumu-    lated Other  Receivable             Compre-
                      Common Stock        Paid-In  lated      Comprehen-   from Share-            hensive
                      Shares      Amount  Capital  Deficit    sive Loss    holders      Total     Loss
<S>                   <C>         <C>     <C>      <C>        <C>          <C>          <C>       <C>
Balance,
 December 31, 2000    10,115,093  $101    $92,456  $(61,155)  $     --     $(2,866)     $ 28,536  $      --

  Stock options granted       --    --      2,711        --         --          --         2,711
  Stock options
    exercised             94,734     2         --        --         --          --             2
  Warrants issued
    to director               --    --          3        --         --          --             3
  Cancellation of
    warrants in
    exchange for
    common stock          18,000    --          3        --         --          --             3
  Issuance of
    restricted stock      25,000    --        161        --         --          --           161
  Accretion of manda-
    torily redeemable
    common stock              --    --       (605)       --         --          --          (605)
  Dividends on
    preferred stock           --    --        (19)       --         --          --           (19)
  Accretion of
    preferred stock           --    --         (2)       --         --          --            (2)
  Interest on notes
    receivable from
    shareholders              --    --         --        --         --         (87)          (87)
  Payment of notes
    receivable from
    shareholder               --    --         --        --         --         360           360
  Partial forgiveness
    of note receivable
    from shareholders         --    --     (1,696)       --         --       2,593           897
  Cumulative effect of
    change in accounting
    principle                 --    --         --        --    (15,171)         --       (15,171)  (15,171)
  Reclassification
    adjustment for
    settled hedging
    contracts                 --    --         --        --      3,292          --         3,292     3,292
  Changes in fair
    value of outstand-
    ing hedge positions       --    --         --        --     10,685          --        10,685    10,685
  Net loss                    --    --         --   (31,365)        --          --       (31,365)  (31,365)

Balance,
 December 31, 2001    10,252,827  $103    $93,012  $(92,520)   $(1,194)     $   --      $   (599)  $(32,559)
                      ==========  ====    =======  ========    =======      ======      ========   ========
</TABLE>








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



                        MALLON RESOURCES CORPORATION

                   CONSOLIDATED STATEMENTS OF CASH FLOWS
                               (In thousands)



<TABLE>
<CAPTION>
                                                                         For the Years Ended
                                                                         December 31,
                                                                         2001         2000         1999
<S>                                                                      <C>          <C>          <C>
Cash flows from operating activities:
  Net loss                                                               $(31,365)    $ (6,531)    $ (2,777)
  Adjustments to reconcile net loss to net cash provided by operating activities:
    Depreciation, depletion and amortization                                7,399        6,382        4,822
    Impairment of oil and gas properties                                   16,418           --           --
    Loss on sale of oil and gas properties                                  3,109           --           --
    Accrued interest expense added to long-term debt                        1,401        4,738          998
    Accrued interest income added to notes receivable from shareholders       (87)        (183)         (60)
    Extraordinary loss                                                         --           --          105
    Non-cash stock compensation expense                                     2,502          578          323
    Amortization of discount on long-term debt                                914          705          188
    Partial forgiveness of notes receivable from related party shareholders   907           --           --
    Changes in operating assets and liabilities:
      Decrease (increase) in:
        Accounts receivable                                                 2,815       (1,535)        (540)
        Inventory and other current assets                                     59          (48)         (22)
      (Decrease) increase in:
        Trade accounts payable and undistributed revenue                   (2,969)         (83)         408
        Accrued taxes and expenses                                              6          (17)         (97)
        Deferred revenue                                                       --           --         (910)
Net cash provided by operating activities                                   1,109        4,006        2,438

Cash flows from investing activities:
  Additions to property and equipment                                     (16,785)     (17,818)      (9,826)
  Proceeds from sale of property and equipment                             29,465           --           --
  Receipts from notes receivable-related parties                                7           77            5
Net cash provided by (used in) investing activities                        12,687      (17,741)      (9,821)

Cash flows from financing activities:
  Proceeds from long-term debt                                                837       12,414       43,332
  Payments of long-term debt                                              (26,025)        (399)     (34,404)
  Redemption of preferred stock                                              (800)          --           --
  Debt issuance costs                                                          (3)         (81)      (1,995)
  Net proceeds from sale of common stock in public offering                    --       15,287           --
  Payment of preferred dividends                                              (19)         (77)        (108)
  Payment of current note payable for redemption of preferred stock            --         (552)          --
  Proceeds from stock option and warrant exercises                              2           68           55
Net cash (used in) provided by financing activities                       (26,008)      26,660        6,880

Net (decrease) increase in cash and cash equivalents                      (12,212)      12,925         (503)
Cash and cash equivalents, beginning of year                               14,155        1,230        1,733

Cash and cash equivalents, end of year                                   $  1,943     $ 14,155     $  1,230
                                                                         ========     ========     ========


Supplemental cash flow information:
  Cash paid for interest                                                 $  4,801     $    773     $  1,988
                                                                         ========     ========     ========

  Non-cash transactions:
    Issuance of common stock in exchange for oil and gas properties purchased
        from officers and directors                                      $     --     $    119     $     --
    Sale of common stock in exchange for notes receivable from shareholders     --           --        2,622
</TABLE>




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


                        MALLON RESOURCES CORPORATION

                NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Operations:

    Mallon Resources Corporation ("Mallon" or the "Company") was incorporated
on July 18, 1988 under the laws of the State of Colorado. The Company engages
in oil and gas exploration and production through its wholly-owned subsidiary,
Mallon Oil Company ("Mallon Oil"), whose oil and gas operations are conducted
primarily in the State of New Mexico.  Mallon operates its business and
reports its operations as one business segment.

Current Operating Issues:

    The Company has generated net losses of $31.4 million, $6.5 million and
$2.8 million for the years ended December 31, 2001, 2000 and 1999,
respectively.  However, the Company has generated cash flows from operating
activities of $1.1 million, $4.0 million and $2.4 million for the years ended
December 31, 2001, 2000 and 1999, respectively.

    As discussed more fully in Note 2, on September 14, 2001, the Company
completed the sale of its Delaware Basin oil and gas properties.
Consequently, the Company's remaining operations are located primarily in the
San Juan Basin of northwest New Mexico.  The Company has minimal access to the
capital necessary to continue to develop its properties in the San Juan Basin.
Subsequent to year end, however, the Company was able to amend its credit
facility to provide, among other things, for a $2.5 million increase in the
borrowings available under the credit facility.  In addition, the Company is
currently seeking alternate methods of financing its discretionary capital
expenditures for 2002, including joint ventures with industry partners.
However, the Company can not be assured that it will be able to secure
financing on terms acceptable to the Company.

    In addition, because production from the San Juan Basin is predominantly
natural gas, the Company is particularly sensitive to changes in the price of
natural gas.  Historically, natural gas prices have experienced significant
fluctuations and have been particularly volatile in recent years.  Price
fluctuations can result from variations in weather, levels of regional or
national production and demand, availability of transportation capacity to
other regions of the country and various other factors.  Increases or
decreases in natural gas prices received could have a significant impact on
the Company's future results.  If natural gas prices decline significantly
from those received by the Company at year end, or if the Company is unable to
maintain production levels at its San Juan Basin properties, Mallon may have
to implement cost cutting measures in both its administrative and operating
areas.

    As discussed more fully in Note 17, in conjunction with the February 2002
amendment to the Company's credit agreement, through December 31, 2002, the
Company is only required to make interest payments on the credit facility.
Management believes that cash on hand, availability under its credit facility
and cash generated from operating activities will be sufficient to meet the
Company's cash requirements through December 31, 2002.

Principles of Consolidation:

    The consolidated financial statements include the accounts of Mallon Oil
and all of its wholly-owned subsidiaries.  All significant intercompany
transactions and accounts have been eliminated from the consolidated financial
statements.

Cash, Cash Equivalents and Short-term Investments:

    Cash and cash equivalents include investments that are readily convertible
into cash and have an original maturity of three months or less. All short-
term investments are held to maturity and are reported at cost.

Fair Value of Financial Instruments:

    The Company's financial instruments consist of cash, cash equivalents,
accounts receivable, notes receivable, inventories, accounts payable, other
accrued liabilities and long-term debt. Except for long-term debt, the
carrying amounts of such financial instruments approximate fair value due to
their short maturities.  At December 31, 2001 and 2000, based on rates
available for similar types of debt, the fair value of long-term debt was not
materially different from its carrying amount. The Company's derivative
instruments, which are intended to manage commodity price risks, are recorded
at fair value (see Note 11).

Inventories:

    Inventories, which consist of oil and gas lease and well equipment, are
valued at the lower of average cost or estimated net realizable value.

Oil and Gas Properties:

    Oil and gas properties are accounted for using the full cost method of
accounting.  Under this method, all costs associated with property
acquisition, exploration and development are capitalized, including general
and administrative expenses directly related to these activities.  All such
costs are accumulated in one cost center, the continental United States.

    Proceeds on disposal of properties are ordinarily accounted for as
adjustments of capitalized costs, with no gain or loss recognized, unless such
adjustment would significantly alter the relationship between capitalized
costs and proved oil and gas reserves (see Note 2).  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 percent, plus the lower of cost or fair market value of
unproved properties, as adjusted for related tax effects (see Note 2).

    Depletion is calculated using the units-of-production method based upon
the ratio of current period production to estimated proved oil and gas
reserves expressed in physical units, with oil and gas converted to a common
unit of measure using one barrel of oil as an equivalent to six thousand cubic
feet of natural gas (see Note 2).

    Estimated abandonment costs (including plugging, site restoration, and
dismantlement expenditures) are accrued if such costs exceed estimated salvage
values, as determined using current market values and other information.
Abandonment costs are estimated based primarily on environmental and
regulatory requirements in effect from time to time.  At December 31, 2001 and
2000, in management's opinion, the estimated salvage values equaled or
exceeded estimated abandonment costs.

Other Property and Equipment:

    Other property and equipment is recorded at cost and depreciated over the
estimated useful lives (generally three to seven years) using the straight-
line method.  Costs incurred relating to a natural gas processing plant are
being depreciated over twenty-five years using the straight-line method.  The
cost of normal maintenance and repairs is charged to expense as incurred.
Significant expenditures that increase the life of an asset are capitalized
and depreciated over the estimated useful life of the asset. Upon retirement
or disposition of assets, related gains or losses are reflected in operations.

Gas Balancing:

    The Company uses the entitlements method of accounting for recording
natural gas sales revenues. Under this method, revenue is recorded based on
the Company's net working interest in field production. Deliveries of natural
gas in excess of the Company's working interest are recorded as liabilities
while under-deliveries are recorded as receivables.  The receivables and
liabilities at December 31, 2001 and 2000 are not material.

Concentration of Credit Risk:

    As an operator of jointly owned oil and gas properties, the Company sells
oil and gas production to numerous oil and gas purchasers and pays vendors for
oil and gas services.  The risk of non-payment by the purchasers is considered
minimal and the Company does not generally obtain collateral for sales to
them.  Joint interest receivables are subject to collection under the terms of
operating agreements which provide lien rights, and the Company considers the
risk of loss likewise to be minimal.

    The Company is exposed to credit losses in the event of non-performance by
counterparties to financial instruments, but does not expect any
counterparties to fail to meet their obligations.  The Company generally does
not obtain collateral or other security to support financial instruments
subject to credit risk but does monitor the credit standing of counterparties.

Stock-Based Compensation:

    As permitted under the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 123, "Accounting for Stock-Based Compensation", the
Company has elected to continue to measure compensation cost using the
intrinsic value based method of accounting prescribed by the Accounting
Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to
Employees."  The Company has made pro forma disclosures of net income (loss)
and net income (loss) per share as if the fair value based method of
accounting as defined in SFAS No. 123 had been applied (see Note 9).

    In March 2000, the Financial Accounting Standards Board ("FASB") issued
Interpretation No. 44, "Accounting for Certain Transactions Involving Stock
Compensation."  Adoption of this Interpretation did not have a material impact
on the Company's financial position or results of operations.

Transportation Costs:

    In September 2000, the Emerging Issues Task Force reached consensus on
Issue No. 00-10, "Accounting for Shipping and Handling Fees and Costs" ("EITF
Issue 00-10").  EITF Issue 00-10 requires retroactive restatement of
transportation costs as an expense rather than as a reduction to revenue in
certain cases.  The implementation of EITF Issue 00-10 in the fourth quarter
of 2000 had no impact on the Company's financial statements.

General and Administrative Expenses:

    General and administrative expenses are reported net of amounts allocated
to working interest owners of the oil and gas properties operated by the
Company, and net of amounts capitalized pursuant to the full cost method of
accounting.

Hedging Activities:

    The Company's use of derivative financial instruments is limited to
management of commodity price and interest rate risks. Gains and losses on
such transactions are accounted for as part of the transaction being hedged.
If an instrument is settled early, any gains or losses are deferred and
recognized as part of the transaction being hedged (see Note 11).

    The information presented in Note 11 of the consolidated financial
statements represents all of the Company's derivative financial instruments
outstanding as of December 31, 2001, as defined by SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities."  In connection with
adoption of SFAS No. 133 on January 1, 2001, the Company designated and
documented the hedging relationship of the Company's derivative contracts in
place at December 31, 2000 to hedge natural gas and oil sales.  Upon adoption
of SFAS No. 133 on January 1, 2001 the Company recorded as a cumulative effect
of a change in accounting principle, a $15.2 million hedging loss in
accumulated other comprehensive loss for the fair market value of derivative
contracts designated as hedges, and a corresponding $15.2 million derivative
liability.

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 when it adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (see Note 11).

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 Convertible Preferred Stock were converted to common stock.
The consolidated statements of operations for 2001, 2000 and 1999 reflect only
basic earnings per share because the Company was in a loss position for all
years presented and all common stock equivalents are anti-dilutive.

Use of Estimates and Significant Risks:

    The preparation of consolidated financial statements in conformity with
generally accepted accounting principles requires management to make
significant estimates and assumptions that affect the amounts reported in
these financial statements and accompanying notes. The more significant areas
requiring the use of estimates relate to oil and gas reserves, fair value of
financial instruments, valuation allowance for deferred tax assets, and useful
lives for purposes of calculating depreciation, depletion and amortization.
Actual results could differ from those estimates.

    The Company and its operations are subject to numerous risks and
uncertainties. Among these are risks related to the oil and gas business
(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, the effects of competition and extensive
environmental regulation, and many other factors, many of which are
necessarily out of the Company's control. The nature of oil and gas drilling
operations is such that the expenditure of substantial drilling and completion
costs are required well in advance of the receipt of revenues from the
production developed by the operations. Thus, it will require more than
several quarters for the financial success of that strategy to be
demonstrated. Drilling activities are subject to numerous risks, including the
risk that no commercially productive oil or gas reservoirs will be
encountered.

Reclassifications:

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

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 or 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 SFAS 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.

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 $31.5 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 $29.4 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 or 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 $3.1 million for the year ended December 31, 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.

    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 percent, 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.

    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.

    In June 2000, the Company purchased additional working interests in
certain wells from two of the Company's officers and one of its directors in
exchange for forgiveness of $56,000 of joint interest participants accounts
receivable, 14,800 shares of common stock valued at $119,000 and $3,000 in
cash.

NOTE 3. NOTES PAYABLE AND LONG-TERM DEBT

    Long-term debt consists of the following:

<TABLE>
<CAPTION>
                                                              December 31,
                                                           2001          2000
                                                             (In thousands)
<S>                                                        <C>       <C>
Note payable to Aquila Energy Capital Corporation,
    due 2003                                               $26,711   $ 50,042
Less unamortized discount                                   (1,899)    (2,813)
                                                            24,812     47,229
Lease obligation to Universal Compression, Inc.              4,567      5,006
8.0% unsecured note payable to Bank One, Colorado, N.A.,
    due 2006                                                   108        124
                                                            29,487     52,359
Less current portion                                          (517)   (12,179)

         Total                                             $28,970   $ 40,180
                                                           =======   ========
</TABLE>

    The Company had a revolving line of credit (the "Bank One Facility") with
Bank One, Texas, N.A. The Bank One Facility consisted of two separate lines of
credit: a primary revolving line of credit and a term loan commitment of $6.5
million (the "Equipment Loan").  The Bank One Facility was retired in
September 1999 (see discussion below). Unamortized loan origination fees of
$105,000 related to the Bank One Facility are included in extraordinary loss
on early retirement of debt in the Company's consolidated statement of
operations for 1999.

    In September 1999, the Company established a credit agreement (the "Aquila
Credit Agreement") with Aquila Energy Capital Corporation ("Aquila").  Through
December 31, 2001, the Company had drawn $52.3 million, including accrued
interest and repaid $25.6 million under the Aquila Credit Agreement.
Approximately $24.1 million was repaid with the proceeds from the sale of the
Company's Delaware Basin properties in September 2001 (see Note 2).

    The initial amount available under the Aquila Credit Agreement was $45.7
million.  In November 2000, the Aquila Credit Agreement was amended and the
amount available under the agreement was increased by $7.7 million, making the
total available $53.4 million.  Through December 31, 2001, the Company had
drawn $52.3 million, including accrued interest, under the Aquila Credit
Agreement, of which $28.0 million was used to retire the Bank One Facility in
September 1999.  Principal payments on the four-year loan began in November
1999 based on the Company's cash flow from operations, as defined (the
"Defined Cash Flow"), less advances for the Company's development drilling
program.  Through December 31, 2000, the Company did not make any principal
payments because drilling expenditures equaled or surpassed Defined Cash Flow
during that period.  The Company had expected to begin making principal
payments in March 2001 in amounts equal to the Defined Cash Flow and paid
Aquila $1.4 million on April 6, 2001.  On March 30, 2001, the Company
negotiated a change in the terms of its agreement with Aquila to delay the
required repayment of principal.  Instead, the repayment schedule for the
twelve months beginning April 30, 2001 was to be 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.  Aquila allowed the Company to make interest only
payments totaling $505,000 for October 2001 to December 2001.  In February
2002, the Aquila Credit Agreement was amended for a second time to allow,
among other things, for the payment of interest only on the outstanding
balance through December 31, 2002 (see Note 17).  The Aquila Credit Agreement
is secured by substantially all of the Company's oil and gas properties and
contains various covenants and restrictions, including ones that could limit
the Company's ability to incur other debt, dispose of assets, or change
management.  Interest on the amounts outstanding under the Aquila Credit
Agreement accrues at prime plus 2% and was added to the loan balance through
March 31, 2001.  The weighted average interest rate for borrowings outstanding
under the Aquila Credit Agreement at December 31, 2001 was 7%.  The
outstanding loan balance is due in full on September 9, 2003.  As part of the
transaction, the Company also entered into an Agency Agreement with Aquila
under which the Company pays Aquila a marketing fee equal to 1% of the net
proceeds (as defined) from the sale of the Company's oil and gas production to
market the Company's gas and to negotiate the Company's gas purchase
contracts.  Marketing fees of $133,000, $119,000 and $31,000 were recorded as
oil and gas production expense in 2001, 2000 and 1999, respectively.

    The Company paid approximately $2.0 million in debt issue costs in
connection with the establishment of the Aquila Credit Agreement.  These costs
are reflected, net of amortization, in the Company's December 31, 2001 and
2000 consolidated balance sheets, as debt issuance costs.  The costs are being
amortized over a period of up to 48 months using the effective interest rate
method.  Amortization expense, related to these costs, of $489,000, $439,000
and $109,000 is included in the Company's 2001, 2000 and 1999 consolidated
statements of operations, respectively.

    In conjunction with the establishment and subsequent first amendment of
the Aquila Credit Agreement, the Company issued to Aquila 490,000 shares of
the Company's common stock (see Note 6).  See Note 17 for additional stock
issued in 2002.

    In September 1999, the Company also entered into a sale-leaseback
agreement with Universal Compression, Inc. to refinance and retire the
Equipment Loan under the Bank One Facility.  The Company also terminated its
interest rate swap agreement related to the Equipment Loan in September 1999
for a gain of $3,500.  The sale-leaseback was recorded as a financing under
the provisions of SFAS No. 98, "Accounting for Leases."  The $5.5 million
obligation has a five-year term with monthly payments beginning in September
1999.  The Company made principal payments totaling $439,000 and $384,000 to
Universal Compression during 2001 and 2000, respectively.  The obligation
bears interest at an imputed interest rate of 12.8%.

    In July 1998, the Company 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 the Company's field office.  The Company drew $155,000 on this
loan during 1998.  Principal and interest is payable quarterly.  The Company
repaid $16,000 and $15,000 of this loan during 2001 and 2000, respectively.
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.

    Estimated principal payments on outstanding debt at December 31, 2001 are
as follows:

<TABLE>
<CAPTION>
                                      (In thousands)
    <S>                               <C>
    2002                              $   517
    2003                               27,297
    2004                                3,514
    2005                                   17
    2006                                   41
    Thereafter                             --

                                      $31,386
                                      =======
</TABLE>

NOTE 4. COMMITMENTS AND CONTINGENCIES

Operating Leases:

    The Company leases office space, office equipment and vehicles under non-
cancelable leases which expire in 2003. Rental expense is recognized on a
straight-line basis over the terms of the leases. The total minimum rental
commitments at December 31, 2001 are as follows:

<TABLE>
<CAPTION>
                                      (In thousands)
    <S>                               <C>
    2002                              $238
    2003                                45
    2004                                20
    Thereafter                          --

                                      $303
                                      ====
</TABLE>

    Rent expense was $337,000, $373,000 and $305,000 for the years ended
December 31, 2001, 2000 and 1999, respectively.

Contingencies:

    As of December 31, 2001, the Revenue and Taxation Department of the
Jicarilla Apache Nation (the "Nation") issued to the Company Possessory
Interest Tax assessments for 1998, 1999, 2000 and 2001 totaling $3.5 million,
including related penalties and interest.  The Company has paid the
assessments under protest.  This amount is included in the Company's
December 31, 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.  In March 2002, the Company was assessed an
additional $1.5 million for 2002.  The Company intends to file a protest for
this amount also.  The Company has: 1) requested that the Legislative Council
of the Nation grant the Company relief, and 2) engaged New Mexico counsel to
represent it.  The final outcome of this matter cannot yet be predicted.

    By letter dated October 9, 2001, the Company was advised that the Minerals
Management Service will audit the royalties payable on production from certain
oil and gas properties in which the Company owns an interest.  The audit began
in mid-November 2001.  The final outcome of this matter cannot yet be
predicted.

    In June 2001, in connection with staff cuts that were part of general
corporate reductions, the Company terminated an employee.  The employee filed
a complaint, in which he claims he was wrongfully terminated.  The Company
believes the allegations of the suit are wholly without merit, and intends to
defend itself vigorously, but cannot predict the outcome of the case.

    In 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 the Plaintiff certain used drilling
materials having an estimated salvage value of $14,000.

    In 1992, the Minerals Management Service commenced an audit of royalties
payable on production from certain oil and gas properties in which the Company
owns an interest.  The audit was initiated against the predecessor operator of
the properties, but the Company has since undertaken primary responsibility
for resolving matters that arise out of the audit.  The Company's liability
with respect to the predecessor operator's liability is limited to $100,000.
However, the Company may have an additional liability with respect to
transactions that have occurred subsequent to its purchase of the oil and gas
properties in question.  The audit focused on several matters, the most
significant of which were the manner in which production is measured and the
manner in which royalties are calculated and accounted for.  Certain alleged
deficiencies preliminarily suggested by the audit were contested.
Determinations contrary to several of the Company's positions were rendered in
June 1999, which the Company has determined not to appeal.  Certain key items
relating to the calculation of royalties have yet to be determined.  A
determination contrary to the Company's position concerning so-called "major
portion" issues was recently rendered by the Department of the Interior.  The
Company's interests in this controversy are represented by outside legal
counsel who is appealing the Department of the Interior's rulings.  In
addition, the Company has recently determined to attempt to negotiate a
private protocol addressing the manner in which royalties are calculated and
accounted for.  The final outcome of these matters cannot yet be predicted.

NOTE 5. MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED STOCK

    In April 1994, the Company completed the private placement of 400,000
shares of Series B Mandatorily Redeemable Convertible Preferred Stock, $0.01
par value per share (the "Series B Stock"). The Series B Stock bore an 8%
dividend payable quarterly, and was convertible into shares of the Company's
common stock at an adjusted conversion price.  Proceeds from the placement
were $3,774,000, net of stock issue costs of $226,000.  In connection with the
Series B Stock, dividends of $19,000, $77,000 and $108,000 were paid in 2001,
2000 and 1999, respectively.  Accretion of preferred stock issue costs was
$2,000, $8,000 and $12,000 in 2001, 2000 and 1999, respectively.

    In April 2000, the Company redeemed 55,200 shares of its Series B Stock at
the mandatory redemption price of $10 per share by issuing a convertible
promissory note for $552,000 to the Series B holder, a company in which one of
Mallon's directors is also a director.  Interest on the note accrued at 11.3%
and was payable quarterly beginning on June 30, 2000.  The note and all
accrued interest was paid in full in October 2000.  The Company redeemed the
remaining 80,000 shares of Series B Stock in April 2001 at the mandatory
redemption price of $10.00 per share.

NOTE 6. MANDATORILY REDEEMABLE COMMON STOCK

    In September 1999, in conjunction with the establishment of the Aquila
Credit Agreement, the Company issued to Aquila 420,000 shares of the Company's
common stock.  In November 2000, in conjunction with an amendment to the
Aquila Credit Agreement, the Company issued an additional 70,000 shares to
Aquila.  These transactions were recorded as Mandatorily Redeemable Common
Stock in the accompanying consolidated balance sheets, based on the market
value of the Company's common stock on the date of issuance.  Aquila has a
one-time right to require the Company to purchase the 490,000 shares at $12.50
per share during the 30-day period beginning September 9, 2003.  The
difference between the value of the shares at the redemption price of $12.50
per share and the market value of the shares on the date of issuance is being
accreted to the redemption date using the effective interest method.
Accretion of $605,000, $428,000 and $116,000 was recorded during the years
ended December 31, 2001, 2000 and 1999, respectively, as a direct charge to
additional paid-in capital and was included in the net loss attributable to
common shareholders in the Company's consolidated statements of operations for
2001, 2000 and 1999.

NOTE 7. CAPITAL

Preferred Stock:

   The Board of Directors is authorized to issue up to 10,000,000 shares of
preferred stock having a par value of $.01 per share, to establish the number
of shares to be included in each series, and to fix the designation, rights,
preferences and limitations of the shares of each series.  At December 31,
2001 and 2000, -0- and 80,000 shares of Series B Preferred Stock were
outstanding, respectively.

Common Stock:

    In October 2000, the Company issued 2,660,000 shares of its common stock
in a public offering at a price of $6.25 per share.  The Company received net
proceeds, after commissions and other costs, of approximately $15.3 million,
which was used primarily to finance the Company's oil and gas drilling
activities.

Warrants:

    The Company has outstanding warrants to purchase an aggregate of 85,334
shares of common stock, as described below.

    In July 1999, the Company entered into a financial consulting services
contract with Bear Ridge Capital LLC.  Under the contract, Bear Ridge Capital
was paid a monthly retainer and was issued warrants to purchase an aggregate
of 40,000 shares of the Company's common stock at a per share exercise price
of $0.01.  Warrants covering 10,000 shares vested on July 1, 2001.  The
remaining warrants were forfeited.  During 2001, 2000 and 1999, the Company
recorded $3,000, $26,000 and $25,000, respectively, of stock compensation
expense related to these warrants. Bear Ridge Capital is wholly-owned by a
Company director and officer.

    Warrants to purchase an aggregate of 78,023 shares of the Company's common
stock at an adjusted exercise price of $8.01 per share were issued in June
1995 to the holders of Laguna Gold Company's Series A Preferred Stock in
connection with the private placement of that stock.  In June 2000, warrants
to purchase 8,426 shares were exercised for total proceeds of $67,500.  The
remaining 69,597 warrants expired June 30, 2000.

    In October 1998, several members of the Company's Board of Directors
purchased from a third party 40,000 (of 160,000) warrants with an exercise
price of $7.80 per share issued by the Company in October 1996.  On
December 11, 1998, the exercise price of all 160,000 outstanding warrants was
reduced to $6.88 per share, the closing price of the Company's stock on that
day.  The repricing of the warrants was done in conjunction with the repricing
of the Company's stock options as discussed in Note 9.  The warrants
originally were to expire on October 16, 2000.  In October 1999, the Company
extended the expiration date of all 160,000 outstanding warrants from
October 16, 2000 to December 31, 2002.  As a result of the extension, the
Company recorded approximately $217,000 of stock compensation expense in
fourth quarter 1999.  In September 2001, one of the Company's directors became
an officer of the Company.  This individual held 84,666 of the 160,000
warrants discussed above.  As part of his employment agreement, he exchanged
all 84,666 of his warrants for 18,000 shares of the Company's common stock.

NOTE 8. SHAREHOLDER RIGHTS PLAN

    In June 2001, 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. At the present time, the Company knows of no
proposed or threatened takeover, tender offer or other effort to gain control
of the Company. Under the terms of the Plan, the Rights will be distributed as
a dividend at the rate of one Right for each Common Share held. Shareholders
will not actually receive certificates for the Rights, but the Rights will
become part of each Common Share.  All Rights expire on June 30, 2006.

    Each Right will entitle the holder to buy shares of common stock at an
exercise price of $40.00. The Rights will be exercisable and will trade
separately from the Common Shares only if a person or group acquires
beneficial ownership of 20% or more of the Company's Common Shares or
commences a tender or exchange offer that would result in such a person or
group owning 20% or more of the Common Shares. Only when one or more of these
events occur will shareholders receive certificates for the Rights.

    If any person actually acquires 20% or more of the Common Shares -- other
than through a tender or exchange offer for all Common Shares that provides a
fair price and other terms for such shares -- or if a 20% or more shareholder
engages in certain "self-dealing" transactions or engages in a merger or other
business combination in which the Company survives and its Common Shares
remain outstanding, the other shareholders will be able to exercise the Rights
and buy Common Shares of the Company having twice the value of the exercise
price of the Rights. In other words, payment of the $40.00 per Right exercise
price will entitle the holder to acquire $80.00 worth of Common Shares.
Additionally, if the Company is involved in certain other mergers where its
shares are exchanged, or certain major sales of assets occur, shareholders
will be able to purchase the other party's common shares in an amount equal to
twice the value of the exercise price of the Rights.

    The Company will be entitled to redeem the Rights at $.01 per Right at any
time until the tenth day following public announcement that a person has
acquired a 20% ownership position in Common Shares of the Company. The Company
in its discretion may extend the period during which it can redeem the Rights.

NOTE 9. STOCK COMPENSATION

    At December 31, 2001, the Company had two stock-based compensation plans.
As permitted under SFAS No. 123, the Company has elected to continue to
measure compensation costs using the intrinsic value method of accounting
prescribed by APB Opinion No. 25.  Under that method, the difference between
the exercise price and the market value of the shares at the date of grant is
charged to compensation expense, ratably over the vesting period, with a
corresponding increase in shareholders' equity.  Compensation costs charged
against income for all plans were $1,840,000, $545,000 and $21,000 for 2001,
2000 and 1999, respectively.

    Under the Mallon Resources Corporation 1988 Equity Participation Plan (the
"1988 Equity Plan"), 250,000 shares of common stock have been reserved in
order to provide for incentive compensation and awards to employees and
consultants. The 1988 Equity Plan provides that a three-member committee may
grant stock options, awards, stock appreciation rights, and other forms of
stock-based compensation in accordance with the provisions of the 1988 Equity
Plan. The options vest over a period of up to four years and expire over a
maximum of 10 years from the date of grant.

    In June 1997, the shareholders approved the Mallon Resources Corporation
1997 Equity Participation Plan (the "1997 Plan") under which shares of common
stock have been reserved to provide employees, consultants and directors of
the Company with incentive compensation.  The 1997 Plan is administered by a
committee of the Board of Directors who may, in its sole discretion, select
the participants, and determine the number of shares of common stock to be
subject to incentive stock options, non-qualified options, stock appreciation
rights and other stock awards in accordance with the provisions of the 1997
Plan.  The aggregate number of shares of common stock that may be issued under
the 1997 Plan is equal to 11% of the number of outstanding shares of common
stock from time to time.  This authorization may be increased from time to
time by approval of the Board of Directors and by the ratification of the
shareholders of the Company.  In 2001, the Committee approved the grant of
475,000 stock options with an exercise price of $0.01 each.  In 2000, the
Committee approved the grant of 122,384 stock options with an exercise price
of $0.01 each and 4,000 stock options at above fair value.  No options were
granted under the 1997 Plan during 1999.  The options vest over a period of up
to five years and expire over a maximum of 10 years from the date of grant.

    In 1997, the Company granted to a consultant options to purchase 3,000 of
the Company's common shares at $8.50 per share, exercisable from November 1997
to December 2000 which expired unexercised.  In 1999, the Company granted this
same individual additional options to purchase 3,000 of the Company's common
shares at $8.50 per share, exercisable from January 1999 to December 2001.
The exercise price of these 3,000 options were reduced from $8.50 per share to
$0.01 per share in 2001 and were exercised in 2001.  These options were not
part of either the 1988 Equity Plan or the 1997 Plan.  During 2001 and 1999,
the Company recorded $2,000 and $22,000 of compensation expense related to
these options.  No compensation expense related to these options was recorded
in 2000.

    The following table summarizes activity with respect to all outstanding
stock options.

<TABLE>
<CAPTION>
                                                      Weighted
                                                      Average
                                         Shares       Exercise Price
    <S>                                  <C>          <C>
    Outstanding at December 31, 1998      817,404      $6.25
      Granted                               3,000       8.50
      Exercised                          (392,235)      6.82
      Forfeited                           (10,200)      6.88
    Outstanding at December 31, 1999      417,969       5.71
      Granted                             126,384       0.23
      Exercised                           (18,567)      0.03
      Forfeited                           (16,133)      5.76
    Outstanding at December 31, 2000      509,653       4.55
      Granted                             475,000       0.01
      Exercised                           (94,734)      0.01
      Forfeited                          (125,864)      5.52

    Outstanding at December 31, 2001      764,055       2.10
                                         ========      =====

    Options exercisable:
      December 31, 1999                   200,017      $4.95
                                         ========      =====

      December 31, 2000                   324,564      $4.68
                                         ========      =====

      December 31, 2001                   359,597      $4.45
                                        ========       =====
</TABLE>

    The weighted average remaining contractual life of the options outstanding
under both the 1988 Equity Plan and 1997 Plan at December 31, 2001 is
approximately 8 years.

    In January 2001, the Company granted a total of 25,000 shares of
restricted common stock and charged $76,000 against income, based on the fair
market value of the shares as of the date of grant.

    In April 1997, the Company granted a total of 25,000 shares of restricted
common stock to three of its officers as an inducement to continue in its
employ.  The fair market value of the shares at the date of grant was charged
ratably over the vesting period of three years.  The Company charged $-0-,
$7,000 and $37,000 against income in 2001, 2000 and 1999, respectively,
related to this grant.  The grant of restricted stock was not a part of the
Company's equity plans.

    Had compensation expense for the Company's 2001, 2000 and 1999 grants of
stock-based compensation been determined consistent with the fair value based
method under SFAS No. 123, the Company's net loss, net loss attributable to
common shareholders, and the net loss per share attributable to common
shareholders would approximate the pro forma amounts below:

<TABLE>
<CAPTION>
                  2001                  2000                1999
                  As         Pro        As        Pro       As        Pro
                  Reported   Forma      Reported  Forma     Reported  Forma
                  (In thousands)
<S>               <C>        <C>        <C>       <C>       <C>       <C>
Net loss          $(31,365)  $(31,705)  $(6,531)  $(6,664)  $(2,777)  $(3,266)
Net loss attributable
   to common
   shareholders    (31,991)   (32,331)   (7,044)   (7,177)   (3,013)   (3,502)
Net loss per share
   attributable to
   common
   shareholders      (2.99)     (3.03)    (0.83)    (0.84)    (0.41)    (0.48)
</TABLE>

    The fair value of each option is estimated as of the grant date, using the
Black-Scholes option-pricing model, with the following assumptions:

<TABLE>
<CAPTION
                                                  2001      2000     1999
<S>                                               <C>       <C>      <C>
Risk-free interest rate                            4.55%     6.6%     6.3%
Expected life (in years)                           6         6        5
Expected volatility                               99.25%    93.8%    69.5%
Expected dividends                                  0.0%     0.0%     0.0%

Weighted average fair value of options granted    $6.38    $5.84    $5.28
</TABLE>

    In July 1999, the Company adopted a Stock Ownership Encouragement Program
to encourage holders of options to exercise their rights to purchase shares of
the Company's common stock.  Under the program, the Company may lend option
holders the funds necessary to exercise their options.  Funds advanced are
immediately paid to the Company in connection with the exercise of the
options.  As a result, the Company incurs no cash outlay.  Loans made under
the program must be approved by the Board of Directors or by its Compensation
Committee, and are represented by secured, interest-bearing, full recourse
promissory notes from the participants.

    In September 1999, certain officers of the Company exercised options to
purchase 381,360 shares of common stock at an exercise price of $6.88 per
share, and borrowed funds from the Company to do so.  The notes bore interest
at 7%, which was due 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.  The notes and accrued interest
were reflected as a reduction of shareholders' equity in the accompanying
consolidated balance sheets for 2000.

    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 year ended December 31, 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 year ended December 31, 2001 in the accompanying consolidated
statements of operations.  This charge is included in the total expensed in
2001 for all stock compensation plans discussed above.

    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 year ended
December 31, 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 charge of $581,000 for the year ended December 31, 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.

    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
December 31, 2001, 193,864 outstanding stock options were affected by this new
policy.  Under the provisions of 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 December 31, 2001, no compensation expense had
been recorded related to the options discussed above.

NOTE 10. BENEFIT PLANS

    Effective January 1, 1989, the Company and its affiliates established the
Mallon Resources Corporation 401(k) Profit Sharing Plan (the "401(k) Plan").
The Company and its affiliates match contributions to the 401(k) Plan in an
amount up to 25% of each employee's monthly contributions. The Company may
also contribute additional amounts at the discretion of the Compensation
Committee of the Board of Directors, contingent upon realization of earnings
by the Company which, at the sole discretion of the Compensation Committee,
are adequate to justify a corporate contribution. For the years ended
December 31, 2001, 2000 and 1999, the Company made matching contributions of
$42,000, $44,000 and $32,000, respectively. No discretionary contributions
were made during any of the three years ended December 31, 2001.

    The Company maintains a program which provides bonus compensation to
employees from oil and gas revenues which are included in a pool to be
distributed at the discretion of the Chairman of the Board. For the years
ended December 31, 2001, 2000 and 1999, a total of $618,000, $156,000 and
$141,000, respectively, was distributed to employees.  Of the amount
distributed in 2001, approximately $398,000 was related to proceeds received
from the sale of the Company's Delaware Basin properties.

NOTE 11. HEDGING ACTIVITIES

    The Company periodically enters into commodity derivative contracts and
fixed-price physical contracts to manage its exposure to oil and gas price
volatility.  Commodity derivatives contracts, which are generally placed with
major financial institutions or with counterparties of high credit quality
that the Company believes are minimal credit risks, may take the form of
futures contracts, swaps or options.  The oil and gas reference prices of
these commodity derivatives contracts are based upon crude oil and natural gas
futures which have a high degree of historical correlation with actual prices
received by the Company.  Prior to January 1, 2001, the Company accounted for
its commodity derivatives contracts using the hedge (deferral) method of
accounting.  Under this method, realized gains and losses from the Company's
price risk management activities are recognized in oil and gas revenue when
the associated production occurs and the resulting cash flows are reported as
cash flows from operating activities.  Gains and losses from commodity
derivatives contracts that are closed before the hedged production occurs are
deferred until the production month originally hedged.  In the event of a loss
of correlation between changes in oil and gas reference prices under a
commodity derivatives contract and actual oil and gas prices, a gain or loss
would be recognized currently to the extent the commodity derivatives contract
did not offset changes in actual oil and gas prices.

    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.

    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.

    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 December 31, 2001, the Company had price
swaps covering 3,406,000 MMBtu of gas related to production for 2002-2004 at
fixed prices ranging between $2.55-$3.91 per MMBtu.  In addition, the Company
had outstanding at December 31, 2001 basis swaps to fix the differential
between the NYMEX (Henry Hub) price and the index price at which the hedged
gas is to be sold for 3,406,000 MMBtu for 2002-2004.

    The following table indicates the Company's outstanding energy swaps at
December 31, 2001:

<TABLE>
<CAPTION>
Product       Production   Fixed Price   Duration     Reference
<S>           <C>          <C>           <C>          <C>
Gas (MMBtu)   1,558,000    $2.55-$3.91   1/02-12/02   NYMEX (Henry Hub)
Gas (MMBtu)     996,000    $2.55         1/03-12/03   NYMEX (Henry Hub)
Gas (MMBtu)     852,000    $2.55         1/04-12/04   NYMEX (Henry Hub)
</TABLE>

   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
the crude oil swaps for a total cost of $1,325,000.  At December 31, 2001,
this transaction is reflected as a part of the loss on the sale of oil and gas
properties.

    At December 31, 2001, the Company had recorded a current derivative asset
of $229,000, a long-term derivative liability of $1.4 million and an
unrealized loss of $1.2 million in accumulated 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 2001, losses of $3.3 million were transferred from accumulated
other comprehensive loss to oil and gas revenues related to settled positions
and an unrealized gain of $10.7 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 $229,000 of unrealized hedging gains in accumulated other
comprehensive loss at December 31, 2001.

    For the years ended December 31, 2001, 2000 and 1999, the Company's losses
under its swap agreements were $3,292,000, $8,965,000 and $102,000,
respectively, and are included in oil and gas sales in the Company's
consolidated statements of operations.  At December 31, 2001, the estimated
net amount the Company would have paid to terminate its outstanding energy
swaps and basis swaps, described above, was approximately $1,194,000.

NOTE 12. MAJOR CUSTOMERS

    Sales to customers in excess of 10% of total revenues for the years ended
December 31, 2001, 2000 and 1999 were:

<TABLE>
<CAPTION>
                  2001           2000         1999
                  (In thousands)
<S>               <C>            <C>          <C>
Customer A        $11,422        $11,970      $2,368
Customer B          5,288          5,161       2,347
Customer C          1,894          3,274       2,025
Customer D             --             --       4,087
</TABLE>

NOTE 13. INCOME TAXES

    The Company incurred a loss for book and tax purposes in all periods
presented. There is no income tax benefit or expense for the years ended
December 31, 2001, 2000 and 1999.

    Deferred tax assets are comprised of the following as of December 31, 2001
and 2000:

<TABLE>
<CAPTION>
                                                      2001       2000
                                                      (In thousands)
<S>                                                   <C>        <C>
    Deferred Tax Assets:
      Net operating loss and percentage
         depletion carryforward                       $ 18,496   $ 14,491
      Oil, gas and other property basis differences      8,121         --
      Other                                              1,211        387
         Total deferred tax assets                      27,828     14,878

    Deferred Tax Liabilities:
      Oil, gas and other property basis differences         --     (2,101)
    Net deferred tax assets                             27,828     12,777

    Less valuation allowance                           (27,828)   (12,777)

         Net deferred tax assets                      $     --   $     --
                                                      ========   ========
</TABLE>

    In 2001, in connection with the sale of the Delaware Basin oil and gas
properties (see Note 2), the Company utilized approximately $7,300,000 of a
previously unrecognized capital loss carryforward to offset capital gain
realized on the sale.

    At December 31, 2001, for Federal income tax purposes, the Company had a
net operating loss carryforward of approximately $47,300,000, which expires in
varying amounts between 2002 and 2021.  In addition, at December 31, 2001, the
Company had a percentage depletion carryforward of approximately $2,300,000,
which will not expire.

NOTE 14. RELATED PARTY TRANSACTIONS

    In January and February 2002, the Company forgave certain notes receivable
from certain officers and a director of the Company plus accrued interest
totaling $57,556.  Accordingly, a provision for $57,556 was made in December
2001 to reduce the carrying value of the notes.

    Please refer to Note 9 for discussion regarding the partial forgiveness of
certain notes receivable from related-party shareholders in May and June 2001.

    In July 1999, the Company entered into a financial consulting services
contract with Bear Ridge Capital LLC, which is wholly-owned by one of the
Company's directors.  In September 2001, this individual became an officer of
the Company.  Under the contract, Bear Ridge Capital was paid a monthly
retainer and was issued warrants to purchase an aggregate of 40,000 shares of
the Company's common stock at a per share exercise price of $0.01.  Warrants
covering 10,000 shares of the Company's common stock vested on July 1, 2001.
The remaining warrants were forfeited (see Note 7).  During 2001, 2000 and
1999, the Company paid Bear Ridge Capital $99,000, $121,000 and $110,000 in
fees, respectively, and expensed $3,000, $26,000 and $25,000 in stock
compensation expense, respectively, related to the warrants.  In September
2001, this consulting agreement was terminated and the Company entered into an
employment agreement with the principal of Bear Ridge Capital LLC.

    In February 2000, the Compensation Committee of the Company's Board of
Directors granted to the Chairman of the Company certain overriding royalty
interests burdening certain oil and gas concessions that the Company may be
awarded by the Government of Costa Rica.

NOTE 15. SUPPLEMENTARY INFORMATION ON OIL AND GAS OPERATIONS

    Certain historical costs and operating information relating to the
Company's oil and gas producing activities as of and for the years ended
December 31, 2001, 2000 and 1999 are as follows:


<TABLE>
<CAPTION>
                                                                           2001        2000        1999
                                                                           (In thousands)
<S>                                                                        <C>         <C>         <C>
Capitalized Costs Relating to Oil and Gas Activities:
  Oil and gas properties (see notes 1-4 below)                             $ 93,933    $120,972    $103,315
  Natural gas processing plant                                                8,648       8,560       8,341
  Accumulated depreciation, depletion and amortization (1), (3), (4)        (69,669)    (58,408)    (52,884)

                                                                           $ 32,912    $ 71,124    $ 58,772
                                                                           ========    ========    ========

Costs Incurred in Oil and Gas Producing Activities:
  Property acquisition costs                                               $    816    $    578    $    123
  Exploration costs                                                           2,872       2,860       2,080
  Development costs:
    Gas plant processing                                                         88         219          80
    Pipeline                                                                  3,026       1,593       1,646
    Salt water disposal                                                          --          63         326
    Drilling                                                                 10,701      12,867       5,502

                                                                           $ 17,503    $ 18,180    $  9,757
                                                                           ========    ========    ========

Results of Operations from Oil and Gas Producing Activities:
  Oil and gas sales                                                        $ 19,340    $ 16,803    $ 13,138
  Lease operating expense                                                   (12,049)     (7,595)     (5,107)
  Depletion and depreciation                                                 (6,776)     (5,828)     (4,587)
  Impairment of oil and gas properties (1)                                  (16,418)         --          --

  Results of operations from oil and gas producing activities              $(15,903)   $  3,380    $  3,444
                                                                           ========    ========    ========
</TABLE>
__________


(1) In the third quarter of 2001, the net book value of the Company's oil and
gas properties exceeded the net present value of the underlying reserves.
Accordingly, the Company wrote-down its oil and gas properties at
September 30, 2001 by $16,418,000, utilizing commodity prices subsequent to
September 30, 2001.  At December 31, 2001, 2000 and 1999, the net present
value of the underlying reserves exceeded the net book value of the Company's
oil and gas properties.

(2) Includes $2,104,000 of unevaluated property costs not being amortized at
December 31, 2001, of which $884,000 is related to Costa Rica.  In 2001, 2000
and 1999, $792,000, $341,000 and $107,000 were incurred, respectively, of
which $427,000, $304,000 and $43,000, respectively, were related to Costa
Rica.  The Company anticipates that substantially all unevaluated costs will
be classified as evaluated costs within 5 years.

(3) During 2000, the Company retired $304,000 of oil and gas properties and
accumulated depletion related to Offshore Belize.

(4) During 2001, the Company sold its oil and gas properties in the Delaware
Basin.  As discussed in Note 2, 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 $3,128,000 million for the year ended December 31, 2001.  The
loss included costs of approximately $32,521,000 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.

(5) Lease operating expense in 2001 includes assessments for possessory
interest taxes, interest and penalties of approximately $2,200,000 for 1998-
2000 and $1,100,000 for 2001, which the Company is protesting.

Estimated Quantities of Proved Oil and Gas Reserves (unaudited):

    Set forth below is a summary of the changes in the net quantities of the
Company's proved crude oil and natural gas reserves estimated by independent
consulting petroleum engineering firms for the years ended December 31, 2001,
2000 and 1999.  All of the Company's reserves are located in the continental
United States.

<TABLE>
<CAPTION>
                                                              Oil       Gas
                                                            (MBbls)    (MMcf)
<S>                                                         <C>        <C>
Proved Reserves
  Reserves, December 31, 1998                                1,264     84,161
    Extensions, discoveries and additions                      482     47,020
    Production                                                (172)    (5,600)
    Revisions                                                  322    (33,056)
  Reserves, December 31, 1999                                1,896     92,525
    Acquisitions of reserves in place                            1        144
    Extensions, discoveries and additions                       --     35,813
    Production                                                (171)    (6,022)
    Revisions                                                  412    (11,989)
  Reserves, December 31, 2000                                2,138    110,471
    Sales of reserves in place                              (1,782)   (28,858)
    Extensions, discoveries and additions                       (2)    12,690
    Production                                                (105)    (5,954)
    Revisions                                                 (221)   (35,210)

  Reserves, December 31, 2001                                   28     53,139
                                                            ======    =======

Proved Developed Reserves
  December 31, 1998                                            945     65,786
                                                            ======    =======

  December 31, 1999                                          1,204     38,539
                                                            ======    =======

  December 31, 2000                                          1,494     47,334
                                                            ======    =======

  December 31, 2001                                             16     37,635
                                                            ======    =======
</TABLE>

Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
Relating to Proved Oil and Gas Reserves (unaudited):

    The following summary sets forth the Company's unaudited future net cash
flows relating to proved oil and gas reserves, based on the standardized
measure prescribed in SFAS No. 69, for the years ended December 31, 2001, 2000
and 1999:

<TABLE>
<CAPTION>
                             2001         2000          1999
                             (In thousands)
<S>                          <C>          <C>           <C>
Future cash in-flows         $102,405     $ 960,017     $240,007
Future production costs       (43,674)     (228,350)     (80,667)
Future development costs      (17,259)      (56,057)     (31,059)
Future income taxes              (168)     (221,140)     (16,514)
Future net cash flows          41,304       454,470      111,767
Discount at 10%               (15,722)     (180,689)     (48,719)

Standardized measure of
  discounted future net
  cash flows, end of year    $ 25,582     $ 273,781     $ 63,048
                             ========     =========     ========
</TABLE>

    Future net cash flows were computed using yearend prices and yearend
statutory income tax rates (adjusted for permanent differences, operating loss
carryforwards and tax credits) that relate to existing proved oil and gas
reserves in which the Company has an interest.

    The following are the principal sources of changes in the standardized
measure of discounted future net cash flows at December 31, 2001, 2000 and
1999:


<TABLE>
<CAPTION>
                                                                     2001         2000         1999
                                                                     (In thousands)
<S>                                                                  <C>          <C>          <C>
Standardized measure, beginning of year                              $ 273,781    $  63,048    $ 43,339
Net revisions to previous quantity estimates and other                  32,193      (12,422)    (10,881)
Extensions, discoveries, additions, and changes in timing of
   production, net of related costs                                      4,883      120,131      30,107
Sales of reserves in place                                            (111,886)          --          --
Purchase of reserves in place                                               --          122          --
Changes in estimated future development costs                            5,860      (21,559)    (14,053)
Previously estimated development costs incurred during the period        2,293        2,875       2,294
Sales of oil and gas produced, net of production costs                 (13,906)     (18,173)     (8,031)
Net change in prices and production costs                             (314,162)     251,949      25,374
Accretion of discount                                                   27,378        7,033       4,215
Net change in income taxes                                             119,148     (119,223)     (9,316)

Standardized measure, end of year                                    $  25,582    $ 273,781    $ 63,048
                                                                     =========    =========    ========
</TABLE>


    There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves and in projecting the future rates of production,
particularly as to natural gas, and timing of development expenditures. Such
estimates may not be realized due to curtailment, shut-in conditions and other
factors which cannot be accurately determined. The above information
represents estimates only and should not be construed as the current market
value of the Company's oil and gas reserves or the costs that would be
incurred to obtain equivalent reserves.

NOTE 16. SUPPLEMENTAL QUARTERLY FINANCIAL DATA (Unaudited):

<TABLE>
<CAPTION>
                        First      Second     Third       Fourth     Total
2001                    (In thousands, except per share amounts)
<S>                     <C>        <C>        <C>         <C>        <C>
Revenues                $ 7,330    $ 5,403    $  4,161    $ 2,871    $ 19,765
Expenses                  7,824      9,714      25,206      8,386     51,130

Net loss                $  (494)   $(4,311)   $(21,045)   $(5,515)   $(31,365)
                        =======    =======    ========    =======    ========

Net loss attributable
 to common shareholders $  (656)   $(4,462)   $(21,199)   $(5,674)   $(31,991)
                        =======    =======    ========    =======    ========

Net loss per share
 attributable to
 common shareholders    $ (0.06)   $ (0.42)   $  (1.98)   $ (0.53)   $ (2.99)
                        =======    =======    ========    =======    =======

2000

Revenues                $ 3,982    $ 3,251    $  4,808    $ 5,266    $17,307
Expenses                  5,613      5,147       5,912      7,166     23,838

Net loss                $(1,631)   $(1,896)   $ (1,104)   $(1,900)   $(6,531)
                        =======    =======    ========    =======    =======

Net loss attributable
 to common shareholders $(1,759)   $(2,017)   $ (1,226)   $(2,042)   $(7,044)
                        =======    =======    ========    =======    =======

Net loss per share
 attributable to
 common shareholders    $ (0.22)   $ (0.26)   $  (0.16)   $ (0.19)   $ (0.83)
                        =======    =======    ========    =======    =======
</TABLE>

NOTE 17. SUBSEQUENT EVENT:

    In February 2002, the Company notified Aquila that it would not be in
compliance as of December 31, 2001 with one of the covenants under the Aquila
Credit Agreement.  That covenant requires the Company to maintain projected
net revenue attributable to its proved reserves in sufficient amount to fully
amortize the balance under the Aquila Credit Agreement by the maturity date of
September 9, 2003.  As a result, in February 2002, the Aquila Credit Agreement
was amended for a second time.  This amendment superseded the March 30, 2001,
waiver by Aquila regarding the requirement for principal payments.  The second
amendment contains the following provisions:

(i)  As long as no new event of default occurs subsequent to the date of the
second amendment, Aquila has agreed that through December 31, 2002, it will
not exercise any of the remedies available to Aquila due to any event of
default that occurs and is continuing regarding the amount of projected net
revenue required to amortize the amounts outstanding by September 9, 2003.

(ii)  Interest on amounts outstanding accrues at prime plus 3% starting
January 1, 2002, through September 30, 2002, and increases to prime plus 4%
after October 1, 2002.  The Company is required to pay interest only on the
outstanding balance through December 31, 2002.

(iii)  The amount available under the agreement was increased by $2.5 million,
making the total available $55.9 million.  Aquila may, at its discretion,
advance additional loans up to $2.5 million to be used for development
operations and/or working capital needs of the Company.

(iv)  A "change of control" provision was added, which calls for the
prepayment of the entire outstanding balance, together with any accrued and
unpaid interest, at the occurrence of a change of control of the Company.

(v)  The Company has the option to purchase from Aquila 490,000 shares of the
Company's common stock previously issued to Aquila for a price of $2.6 million
if a sale of the Company is consummated prior to September 30, 2002.

(vi)  Aquila's one-time right to require the Company to purchase shares of the
Company's common stock previously issued to Aquila (the "Put Option") was
amended to provide that Aquila has the option to sell to the Company up to
490,000 shares of the Company's common stock at $10.00 per share if a sale of
the Company is consummated at any time after September 30, 2002 and prior to
September 9, 2003, or at $12.50 per share if the outstanding balance under the
Aquila Credit Agreement is paid on the earlier of September 9, 2003 or the
date on which Aquila notifies the Company of the acceleration of payment of
the outstanding balance because of the occurrence of an event of default.

(vii)  The Company issued to Aquila 125,000 shares of the Company's common
stock as a part of the amendment.  If a sale of the Company is not consummated
before October 1, 2002, the Company will issue Aquila an additional 150,000
shares.

(viii)  Upon a change of control of the Company occurring on or before
September 30, 2002, the Company will pay Aquila $500,000.  If a change of
control of the Company occurs after September 30, 2002, the Company will pay
Aquila $1,250,000.

    Through March 29, 2002, the Company had drawn $800,000 under provision
(iii) above, and had $1.7 million available for future draws.

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