Securities and Exchange Commission
                              Washington, D.C.  20549

Form 10-K/A
Amendment to Report
Filed Pursuant to Section 12, 13 or 15(d) of the Securities 
Exchange Act of 1934 

Mallon Resources Corporation
(Exact name of Registrant as specified in its charter)

0-17267
(Commission file number)

Amendment No. 1

     The undersigned registrant hereby amends the following items, 
financial statements, exhibits or other portions of its Annual 
Report on Form 10K for the year ended December 31, 1996 (the "1996 
Form 10-K"), as set forth in the pages attached hereto:

         Items 1 and 2 of the 1996 Form 10-K
         Item 6 of the 1996 Form 10-K
         Item 7 of the 1996 Form 10-K

(List of all such items, financial statements, exhibits or other 
portions amended)

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

                             Mallon Resources Corporation

December 3, 1997                /s/ Roy K. Ross               
                             Roy K. Ross, Executive Vice President

Items 1 and 2 of the 1996 Form 10-K are hereby amended to read in 
their entirety as follows:

ITEMS 1 AND 2:     BUSINESS AND PROPERTIES

General History

Mallon Resources Corporation, a Colorado corporation (the 
"Company"), is an independent energy company engaged in domestic 
oil and gas development, exploration and production.  The Company 
was organized in 1988 in connection with the consolidation of 
Mallon Oil Company ("Mallon Oil") and Laguna Gold Company 
("Laguna").  From inception, the Company has engaged in two 
separate and distinct facets of the natural resources business:  
through Mallon Oil the Company pursued its core oil and gas 
business, and through Laguna the Company engaged in mining 
activities.  By early 1996, the Company concluded that the level 
of capital and management resources required to fully develop each 
of these businesses made it inadvisable for the Company to 
continue to pursue both.  Accordingly, over the course of 1996 the 
Company reduced its ownership interest in Laguna from 80% to 56%.  
By establishing Laguna's financial independence through a Canadian 
financing and listing on The Toronto Stock Exchange, the Company 
is now able to focus all of its efforts on the oil and gas 
business.  Since the completion of those events, Laguna has been 
operating independently, without reliance on the Company for 
financial support.  

In light of the recent implementation of this fundamental change 
in the manner in which the Company will henceforth pursue its 
business, the Company's past performance is not necessarily 
indicative of its future operations.

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

Overview of Oil and Gas Operations

The significant majority of the Company's assets and revenues are 
utilized in its oil and gas operations, which are conducted 
primarily in the State of New Mexico.  The Company's activities 
are focused in the Delaware Basin of southeast New Mexico where it 
has been active since 1982, and in the San Juan Basin of northwest 
New Mexico where it has been active since 1984.  Numerous 
potentially productive geologic formations and zones tend to be 
stacked atop one another in the Delaware and San Juan Basins.  
This feature allows most wells to target multiple potential pay 
zones, thus reducing drilling risks.  It also permits the Company 
to conduct exploration operations in conjunction with its 
development drilling.  Wells drilled to one horizon offer 
opportunities to examine potential up-hole zones or can be drilled 
to deeper prospective formations for relatively little additional 
cost.  Due to its substantial acreage positions and operating 
experience in these areas, the Company intends to continue to 
concentrate its operational efforts on these two basins for the 
foreseeable future.

The Company's objectives are to develop its inventory of 
properties, expand its oil and gas reserves and increase its cash 
flow.  The Company intends to pursue these objectives by 
increasing its drilling and recompletion activities on its 
Delaware and San Juan Basin properties, while maintaining control 
over its drilling, completion and operating costs.

In September 1993, in a significant acquisition, the Company 
purchased its core group of Delaware Basin properties from 
Pennzoil Exploration and Production Company.  In October 1996, the 
Company completed a significant financing in which it sold 2.3 
million shares of common stock for net proceeds of approximately 
$13.2 million.  For the first time in the Company's history, the 
Company has funds available to develop and exploit the Company's 
substantial inventory of oil and gas properties.

In December 1996, the Company entered into an agreement to acquire 
additional interests in some of its San Juan Basin gas properties 
and to become operator of those properties.  The Company assumed 
operations on December 31, and title to the properties passed on 
January 1, 1997.  The reserve information reported in various 
places in Items 1 and 2 of this report includes the reserves 
attributable to this acquisition as if the Company owned them on 
December 31, 1996.  See Note 17 to the Consolidated Financial 
Statements for a presentation of reserve information excluding 
this transaction.  The Company increased its estimated proved 
reserves from 2.2 MMBOE as of December 31, 1992, to 6.4 MMBOE as 
of December 31, 1996, a 191% increase.  As of December 31, 1996, 
the Company's proved reserves, as estimated by its independent 
petroleum engineers, GeoQuest Reservoir Technologies, Inc. 
("GeoQuest"), consisted of 1.7 MMBbls of crude oil and 28.4 Bcf of 
natural gas, with a Pre-tax SEC 10 Value of $50.0 million.  At 
December 31, 1996, the Company owned interests in 227 gross (74 
net) producing wells and operated 108, or 48%, of them.

Selected Fields and Areas of Interest

The Company's activities are focused in the Delaware Basin of 
southeastern New Mexico and in the San Juan Basin of northwestern 
New Mexico.  At December 31, 1996, these areas accounted for 
substantially all of the Company's estimated proved reserves, with 
3.8 MMBOE attributable to the Company's Delaware Basin properties 
and 2.6 MMBOE attributable to its San Juan Basin properties.

Delaware Basin, Southeastern New Mexico

The Delaware Basin has been an area of significant activity for 
the Company since 1982, when the Company acquired an interest in 
the Brushy Draw field.  Wells in the Delaware Basin produce from a 
variety of formations, the principal of which are the Cherry 
Canyon, Brushy Canyon, Strawn and Morrow Formations.  These 
formations each contain multiple potentially productive zones.  
The Cherry Canyon and Brushy Canyon formations are shallow and 
primarily produce oil, while the deeper Strawn and Morrow 
Formations generally produce natural gas.  The Company's primary 
properties in the Delaware Basin are in the Lea Northeast, Quail 
Ridge, White City and South Carlsbad fields.  The Company also 
continues to assess potential in its Shipp, Lovington Northeast 
and Brushy Draw properties.  The Company owns interests in 
approximately 24,500 gross (19,300 net) acres of oil and gas 
leases in the Delaware Basin.

     Lea Northeast Field, Lea County, New Mexico.  The Company is 
actively developing a Cherry Canyon Formation play in this field.  
Since 1994, it has drilled 14 wells here, 11 of which were 
productive and one of which is used as a salt water disposal well.  
In 1996, the Company drilled three wells here, two of which were 
completed in the Cherry Canyon.  These wells extended the 
productive limits of the Lea Northeast Field by more than a mile 
to the northwest.  The Company currently operates 12 wells in this 
field.  The Company's wells in Lea Northeast typically target 
between 10 and 15 zones that are productive in the area.  The 
primary producing interval in the field is in the Cherry Canyon 
Formation, although more recently attention has also been directed 
to the deeper Brushy Canyon Formation.  The Company intends to 
drill wells to 10,500 feet in order to test zones in the Bone 
Springs Formation, which is also productive on portions of the 
Company's acreage.  These formations contain multiple reservoir 
zones that occur at depths between 5,500 and 8,200 feet.  The 
Company intends to drill additional wells in Lea Northeast during 
1997 and has delineated 30 additional drill locations in the 
field.  The Company's working interest in these wells ranges from 
36% to 84%, and averages approximately 55%.

     Quail Ridge, Lea County, New Mexico.  Adjacent to Lea 
Northeast, the Company controls a large block of acreage on which 
it operates wells producing from the Bone Springs, Atoka, and 
Morrow Formations.  The Quail Ridge Field has produced primarily 
gas from the Morrow sandstone at depths of approximately 13,500 
feet.  The Company currently has an interest in 10 wells in this 
area and operates five of them.  The Company plans to further 
develop this block by drilling at least seven wells in 1997.  
These wells will be drilled for production from the same Cherry 
Canyon Formation and Brushy Canyon Formation zones found by the 
Company's recent development activities in Lea Northeast, and, if 
successful, would extend the limits of the field by more than two 
miles to the northwest.  The Company controls an approximate 40% 
working interest in this acreage.

     White City and South Carlsbad Fields, Eddy County, New 
Mexico.  These adjacent fields have been the focus of much of the 
Company's recompletion and development activities since 1993.  The 
Company has interests in 29 wells in these fields and operates 11 
of them.  In 1996, the Company drilled a successful Morrow gas 
well and successfully recompleted Morrow gas wells drilled in 
prior years in the Canyon, Strawn, and Atoka Formations.  Plans 
for development include drilling additional wells to the Morrow at 
12,000 feet and developing shallower Cherry Canyon zones.  Like 
all of the Company's recent drilling, a Morrow well will allow for 
exploration of various up-hole zones in the Cherry Canyon and 
Brushy Canyon Formations at depths from 1,500 to 5,300 feet, as 
well as the targeted Canyon, Strawn, Atoka and Morrow Formations, 
which range in depth from 9,000 feet to 12,000 feet.  The 
Company's working interest averages 38%.

     Shipp and Lovington Northeast Fields, Lea County, New Mexico.  
Shipp and Lovington Fields are comprised of a collection of 
individual reservoirs, or algal mounds, in a Strawn Formation 
interval at depths of approximately 11,500 feet.  The mounds range 
in size from 100 to 700 acres.  The Company has interests in 33 
wells and operates 23 wells in these adjacent fields.  During 
1996, the Company initiated a low installation cost pilot 
waterflood project on one of these mounds.  The Company will 
evaluate the success of this secondary recovery project and 
determine the feasibility of expanding the project to other mounds 
in the fields.  The Company's working interest averages 33% in 
Lovington Northeast, and 46% in Shipp.

     Brushy Draw Field, Eddy County, New Mexico.  The Company's 
initial drilling and field development here began in 1982.  
Current production is from the base of the Cherry Canyon 
Formation, at a depth of approximately 5,000 feet.  The Company 
operates 14 wells with an average working interest of 68%.  The 
Company will continue its Cherry Canyon development here, and 
drill three wells in 1997, which will also be analyzed to evaluate 
potential productive zones in the Brushy Canyon Formation.

San Juan Basin, Northwestern New Mexico

The San Juan Basin has been a significant area of activity for the 
Company since 1984.  The Company's primary areas of interest in 
the San Juan Basin are the East Blanco, Gavilan and Otero areas.  
At December 31, 1996, the Company owned interests in approximately 
31,000 gross (16,500 net) acres of oil and gas leases in the San 
Juan Basin.  Wells on these leases produce from a variety of zones 
in the Pictured Cliffs, Mesaverde, Mancos and Dakota Formations 
and primarily produce natural gas.

     East Blanco Area, Rio Arriba County, New Mexico.  This area 
has been under development by the Company since 1986.  The Company 
holds interests in 23 wells in this area.  All production in the 
area has been natural gas, and East Blanco wells typically contain 
reserves in more than one productive zone, primarily in the 
Pictured Cliffs Formation and the Ojo Alamo Formation.  The wells 
also penetrate the Fruitland Coal Formation, which is productive 
in fields adjacent to East Blanco.  At present, the Company has 
identified 44 potential drilling and recompletion locations on its 
East Blanco acreage.  Of the locations currently identified, 14 
have been assigned proved undeveloped reserves in the Pictured 
Cliffs or Ojo Alamo Formations.  At December 31, 1996, the Company 
owned a 59% average working interest in a 20,000 acre block to the 
bottom of the Pictured Cliffs Formation.  In a transaction 
completed on January 1, 1997, the Company enhanced its ownership 
interest in this area to an average 81% working interest in a 
23,400 acre block and became operator of the acreage.  For 1997, 
the Company has scheduled recompletion operations for several of 
the Pictured Cliffs wells in this area, in order to test the 
productive properties of the up-hole Ojo Alamo and Fruitland Coal 
formations.

     Gavilan Field, Rio Arriba County, New Mexico.  The Company 
operates seven wells in this field.  Current production is 
primarily natural gas from the Mancos Formation at approximately 
5,600 feet.  In 1997 the Company plans to recomplete three wells 
in the Mesaverde Formation and to use such wells to test the 
Pictured Cliffs gas sand and two additional Mesaverde pays.  The 
Company holds an average 34% working interest in this acreage.

     Otero Field, Rio Arriba County, New Mexico.  The Company 
operates its two wells in this field, which produce oil from the 
Mancos Formation at approximately 5,300 feet.  The Company intends 
to drill two wells in this field in 1997, which will commingle 
production from the Pictured Cliffs, Mesaverde and Mancos 
Formations.  The Company has an 88% working interest in this 
acreage.

Other Areas

All of the Company's oil and gas operations are currently 
conducted on-shore in the United States.  In addition to the 
properties described above, it has properties in the states of 
Colorado, Oklahoma, Wyoming, North Dakota and Alabama.  While it 
intends to continue to produce its current wells in those states, 
it currently does not expect to engage in any development 
activities in those areas.  The Company also owned a 2.25% working 
interest in an exploration venture that drilled a dry hole 
exploration well offshore Belize in 1997.

Acreage

The majority of the Company's producing oil and gas properties are 
located on leased land held by the Company for as long as 
production is maintained.  The Company believes it has 
satisfactory title to its 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 the Company's oil and 
gas acreage holdings as of December 31, 1996.

<TABLE>
<CAPTION>
                                Developed           Undeveloped  
     Area                    Gross      Net      Gross       Net 
<C>                         <S>       <S>        <S>       <S>
     Delaware Basin         23,002    18,975      1,560       312
     San Juan Basin         10,308     3,503     20,773    13,033
     Other                  10,225     3,953      2,931        50

     Total                  43,535    26,431     25,264    13,395
</TABLE>

Much of the Delaware Basin developed acreage relates to deeper 
natural gas zones as to which larger spacing rules apply.  Most of 
this developed acreage is undeveloped as to shallower zones.

Proved Reserves

The following table sets forth summary information concerning the 
Company's proved oil and gas reserves as of December 31, 1996, as 
estimated in a report (the "GeoQuest Report") prepared by 
GeoQuest.  All calculations have been made in accordance with the 
rules and regulations of the Securities and Exchange Commission 
(the "Commission").  The present value of estimated future net 
revenues has been calculated using a discount factor of 10%.

<TABLE>
<CAPTION>
                                    Oil        Gas       Total
                                   (MBbl)     (MMcf)     (MBOE)
<C>                                <S>        <S>         <S>
     Proved developed reserves     1,225      20,521      4,645 
     Proved undeveloped reserves     482       7,868      1,784 
     Total proved reserves         1,707      28,388      6,439 
     Future net revenues before 
        income taxes (in thousands)                     $93,026 
     Present value of future net 
        revenues before income 
        taxes (in thousands)                            $49,957 
</TABLE>

Drilling Activity

The following table sets forth, for each of the last three years, 
the drilling activities conducted by the Company:

<TABLE>
<CAPTION>
                             Development Wells
                  Gross Wells                    Net Wells
          Productive   Dry   Total      Productive   Dry     Total
<C>           <S>       <S>    <S>        <S>        <S>      <S>
     1996     4         1      5          2.69       0.34     3.03
     1995     7         1      8          4.64       0.68     5.32
     1994     4         0      4          1.75       0.00     1.75

                             Exploratory Wells
                  Gross Wells                    Net Wells
          Productive   Dry   Total      Productive   Dry     Total

     1996     0         0      0          0          0        0
     1995     1         0      1          .3         0        .3
     1994     0         0      0          0          0        0
</TABLE>

From January 1, 1997 to March 25, 1997 the Company drilled seven 
development wells in the United States that are not reflected in 
the above table.  Five of those wells have been completed and two 
are currently awaiting completion.  The Company also drilled one 
gross (0.02 net) dry exploration well in Belize.


Productive Wells

The following table summarizes the Company's gross and net 
interests in productive wells at December 31, 1996.

<TABLE>
<CAPTION>
             Gross Wells                     Net Wells
     Oil   Natural Gas   Total      Oil    Natural Gas   Total
<C>  <S>       <S>        <S>      <S>        <S>        <S>
     118       109        227      39.7       34.7       74.4
</TABLE>

In addition, the Company owns interests in four waterflood units, 
which contain a total of 544 gross wells (8.5 net wells), and four 
gross (2.1 net) salt water disposal wells.

Production and Sales

The following table sets forth information concerning the 
Company's total oil and gas production (including deliveries under 
its volumetric production payment, which was retired in August 
1995) and sales for each of the last three years.

<TABLE>
<CAPTION>
     Year ended December 31,
                                           1996     1995     1994 
<C>                                       <S>      <S>      <S>
     Net Production: 
         Oil (MBbl)                         174      173      146
         Natural gas (MMcf)               1,286    1,238    1,648
         BOE                                388      379      421

     Average Sales Price Realized (1):
         Oil (per Bbl)                   $18.05   $16.45   $14.81
         Natural gas (per Mcf)           $ 2.11   $ 1.58   $ 1.50
         Per BOE                         $15.09   $12.66   $11.00

     Average Cost (per BOE): 
         Production costs                $ 5.80   $ 4.93   $ 4.81
         Depletion                       $ 4.96   $ 5.70   $ 5.53

     Producing Wells (at end of period) (2): 
         Gross Wells                        227      222      220
         Net Wells                           75       71       66
</TABLE>

1)   Includes effects of hedging.  See "Management's Discussion 
     and Analysis of Financial Condition and Results of 
     Operations--Hedging Activities."

2)   In addition, the Company owns interests in four waterflood 
     units, which contain a total of 544 gross wells (8.5 net 
     wells), and four gross (2.1 net) salt water disposal wells.

Laguna Gold Company

At December 31, 1996, the Company owned approximately 14 million 
common shares, representing an approximate 56% interest, in 
Laguna, a company with development stage gold mining concessions 
in Costa Rica.  To establish itself as a financially independent 
company, Laguna completed a financing in Canada in September 1996, 
and listed its common shares on The Toronto Stock Exchange under 
the trading symbol "LGC."  Laguna received approximately 
$4.3 million of net proceeds from its Canadian financing, which 
should permit Laguna to continue its operations without further 
reliance on the Company for financial support.  The Company does 
not have any obligation or intention to finance Laguna's future 
operations.  In conjunction with Laguna's Canadian financing, the 
Company sold 400,000 shares of Laguna common stock and realized a 
gain of $329,000.  Over the course of the year, the Company 
reduced its ownership interest in Laguna from 80% to 56%, and may 
continue to reduce its investment in Laguna in the future.  
Approximately 8.4 million of the Laguna shares owned by the 
Company are subject to an escrow agreement with The Toronto Stock 
Exchange that restricts the ability of the Company to sell such 
shares for up to three years.  For industry segment information 
concerning Laguna, see Note 15 to the Consolidated Financial 
Statements.

Laguna is engaged in the exploration for and development of 
precious metals in Costa Rica, where it holds mineral concessions 
issued by the Government of Costa Rica.  The concessions contain 
the Rio Chiquito Deposit.  Laguna commenced active exploration and 
evaluation of Rio Chiquito in March 1984.  In October 1987, Laguna 
commenced a small pilot heap leach mining operation at the Rio 
Chiquito Deposit.  In July 1989, Laguna concluded that efficient 
commercial exploitation of the project would require a 
substantially larger operation than the pilot project.  
Accordingly, the project was suspended pending additional 
development and funding.  The pilot project produced a total of 
3,800 ounces of gold and 28,600 ounces of silver.

Further exploration and evaluation of the Rio Chiquito Deposit has 
been undertaken since 1989.  Based on the results of a stream 
sediment geochemical sampling program, the Rio Chiquito Deposit 
was found to be located within an arsenic/gold anomaly 
approximately 250 acres in size.  Pit exposures and core drilling 
indicate that the mineralization is found in polyphase stockwork 
quartz veining and hydrothermal breccias that formed in andesitic 
lavas and pyroclastics.  Identified mineralization lies in the 
area of the pilot project pit and to the south, along a strike 
length of approximately 400 meters.

In September 1997, Laguna reported that the mineralized deposit at 
Rio Chiquito consists of an estimated 71.9 million tonnes grading 
0.29 grams per tonne gold and 4.81 grams per tonne silver.  Laguna 
also reported that most of the requisite feasibility work for the 
commercial development of Rio Chiquito has been completed, and 
that it believes the Rio Chiquito Deposit can be placed on 
production if sufficient development capital can be raised.  
However, Laguna gives no assurance that any such funding can be 
secured, or as to the terms upon which capital may be available.  
Pending receipt of the capital required to develop Rio Chiquito, 
Laguna has furloughed workers in Costa Rica and otherwise 
curtailed its expenditures in order to conserve its cash.

General Matters

Executive Officers and Key Employees

The Executive Officers and key employees of the Company are as 
follows:

<TABLE>
<CAPTION>
          Name          Age           Title(s)               Since
<C>                     <S> <S>                               <S>
George O. Mallon, Jr.   52  President, Chairman of the Board  1988
Kevin M. Fitzgerald     42  Executive Vice President          1988
Roy K. Ross             46  Executive Vice President,
                               General Counsel                1992
Alfonso R. Lopez        48  Vice President-Finance, 
                               Treasurer                      1996
Carolena F. Chapman     53  Secretary, Controller             1989
Ray E. Jones            43  Vice President-Engineering 
                               of Mallon Oil                  1994
Randy Stalcup           42  Vice President-Land 
                               of Mallon Oil                  1995
Wendell A. Bond         50  Vice President-Geology
                               of Mallon Oil                  1996
Donald M. Erickson, Jr. 41  Vice President-Operations 
                               of Mallon Oil                  1997
Duane Winkler           42  Operations Manager 
                               of Mallon Oil                  1993
</TABLE>

George O. Mallon, Jr., formed Mallon Oil in 1979 and was a co-
founder of Laguna in 1980.  He became Chairman of the Board of the 
Company upon its formation in December 1988.  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.

Kevin M. Fitzgerald joined Mallon Oil in 1983.  He was named 
Executive Vice President of the Company in 1990.  Mr. Fitzgerald 
earned a B.S. degree in Petroleum Engineering from the University 
of Oklahoma in 1978.

Roy K. Ross joined the Company as Executive Vice President and 
General Counsel in October 1992.  From June 1976 through September 
1992, Mr. Ross was an attorney in private practice with the 
Denver-based law firm of Holme Roberts & Owen.  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.

Alfonso R. Lopez joined the Company in July 1996 as Vice 
President-Finance and Treasurer.  He was Vice President-Finance 
for Consolidated Oil & Gas, Inc. (now Hugoton 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 oil and gas exploration and production 
company.  Mr. Lopez, a certified public accountant, earned his 
B.A. degree in Accounting and Business Administration from Adams 
State College in Colorado in 1970.

Carolena F. Chapman is Secretary and Controller of the Company.  
She joined Mallon Oil in 1979.  She was named to her present 
positions with the Company in October 1989.

Ray E. Jones is Vice President-Engineering of Mallon Oil.  Before 
joining the Company in January 1994, Mr. Jones spent eight years 
with Jerry R. Bergeson & Associates (now GeoQuest), an independent 
consulting firm, where he did reservoir engineering, field studies 
and reserve evaluations, and taught industry courses in basic 
reservoir engineering, reservoir simulation and well testing.  
Mr. Jones graduated from the Colorado School of Mines in 1979, and 
is a registered professional engineer.

Randy Stalcup joined Mallon Oil as Vice President-Land in 
April 1995.  Prior to joining the Company, Mr. Stalcup was 
employed by Beard Oil Company for 13 years, where he was 
Acquisition and Unitization Manager from 1989.  Mr. Stalcup, a 
Certified Professional Landman, earned his B.B.A. degree in 
Petroleum Land Management from the University of Oklahoma in 1979.

Wendell A. Bond, Vice President-Geology of Mallon Oil, joined the 
Company on a full time basis in 1996.  He had served as an 
independent geological consultant to the Company since July 1994 
through Wendell A. Bond, Inc., a company specializing in petroleum 
geological consulting services that he formed in 1988.  Prior to 
1988, Mr. Bond had been employed in a variety of positions for 
several independent and major oil and gas companies, including 
Project Geologist for Webb Resources, District Geologist for Sohio 
Petroleum and Chief Geologist for Samuel Gary Jr. & Associates.  
Mr. Bond earned his B.S. degree in geology from Capital 
University, Columbus, Ohio, and his M.S. degree in geology from 
the University of Colorado.

Donald M. Erickson, Jr., joined Mallon Oil as Vice President-
Operations in February 1997.  Mr. Erickson has more than 21 years 
of experience in oil field operations.  Prior to joining the 
Company, he was Operations Manager for Presidio Exploration, Inc. 
(which was merged into Tom Brown Inc.) from December 1988.  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 
Denver.

Duane Winkler is Operations Manager of Mallon Oil, working out of 
the Carlsbad, New Mexico office.  Before joining the Company in 
October 1993, he was employed by Natural Gas Processing as 
Production Superintendent from 1986 to 1993.  Mr. Winkler, who has 
24 years of experience in drilling, completion and production 
operations, completed his Associates of Engineering Certificate 
from Central Wyoming College in 1996.

At March 25, 1997, the Company had 19 full-time employees in its 
Denver office and 7 full-time employees in its Carlsbad, New 
Mexico, office.  The Company believes it has good relations with 
its employees.

Marketing

The Company's 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.  Natural gas is generally sold on the spot market 
or pursuant to short-term contracts.  Prices paid for crude oil 
and natural gas fluctuate substantially.  Because future prices 
are difficult to predict, the Company hedges a portion of its 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.  The Company nevertheless believes that hedging is 
prudent in certain circumstances in order to minimize the risk of 
falling prices.

Cautionary Statement Regarding Forward-Looking Statements

The discussion in this report contains certain forward-looking 
statements that involve risks and uncertainties.  The Company's 
actual results could differ significantly from those discussed 
herein.  Factors that could cause or contribute to such 
differences include, but are not limited to, those discussed in 
"Special Considerations," and "Management's Discussion and 
Analysis of Financial Condition and Results of Operations," as 
well as those discussed elsewhere in this report.  Statements 
contained in this report that are not historical facts are 
forward-looking statements that are subject to the safe harbor 
created by the Private Securities Litigation Reform Act of 1995.

Special Considerations

In evaluating the Company and its Common Stock, readers should 
consider carefully, among other things, the following special 
considerations.

Oil and Gas Prices; Marketability of Production

The Company's oil and gas revenues and profitability are 
substantially affected by prevailing prices for oil and natural 
gas, which can be extremely volatile.  In general, hydrocarbon 
prices are affected by numerous factors such as economic, 
political and regulatory developments.  Prices have risen recently 
but there can be no assurance that such price levels will be 
sustained.  The unsettled nature of the energy market, which is 
sensitive to foreign political and military events and the 
unpredictability of the actions of the Organization of Petroleum 
Exporting Countries, makes it particularly difficult to estimate 
future prices of oil and natural gas.  Any significant decline in 
prices of oil or natural gas for an extended period could have a 
material adverse effect on the Company's financial condition, 
liquidity and results of operations.  Additionally, substantially 
all of the Company's sales of oil and natural gas are made in the 
spot market or pursuant to contracts based on spot market prices 
and not pursuant to long-term fixed price contracts.  With the 
objective of reducing price risk, the Company enters into hedging 
transactions with respect to a portion of its expected future 
production.  There can be no assurance, however, that such hedging 
transactions will reduce risk or mitigate the effect of any 
substantial or extended decline in oil or natural gas prices.

In addition, the marketability of the Company's production depends 
upon the availability and capacity of pipelines and gas gathering 
systems, the effect of federal and state regulation of such 
production and transportation, general economic conditions and 
changes in demand, all of which could adversely affect the 
Company's ability to market its production.  All of these factors 
are beyond the control of the Company, and the Company is limited 
in its ability to protect its economic interests from their 
effect.  The Company conducts substantially all of its operations 
in the Delaware and San Juan Basins in the State of New Mexico 
and, consequently, is particularly subject to marketing 
constraints that exist or may arise in the future in those areas.  
Historically, due to the San Juan Basin's relatively isolated 
location and the resulting limited access its natural gas 
production has to the natural gas 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.

Uncertainty of Estimates of Reserves and Future Net Revenues

This report contains estimates of the Company's proved oil and gas 
reserves and the estimated future net revenues therefrom based 
upon the GeoQuest Report, that relies upon various assumptions, 
including assumptions required by the Commission as to oil and gas 
prices, drilling and operating expenses, capital expenditures, 
taxes and availability of funds.  The process of estimating oil 
and gas reserves is complex, requiring significant decisions and 
assumptions in the evaluation of available geological, 
geophysical, engineering and economic data for each reservoir.  As 
a result, such estimates are inherently imprecise.  Actual future 
production, oil and gas prices, revenues, taxes, development 
expenditures, operating expenses and quantities of recoverable oil 
and gas reserves may vary substantially from those estimated in 
the GeoQuest Report.  Any significant variance in these 
assumptions could materially affect the estimated quantity and 
value of reserves set forth in this report.  In addition, the 
Company's reserves may be subject to downward or upward revision 
based upon production history, results of future development and 
exploration, prevailing oil and gas prices and other factors, many 
of which are beyond the Company's control.  Actual production, 
revenues, taxes, development expenditures and operating expenses 
with respect to the Company's reserves will likely vary from the 
estimates used, and such variances may be material.

Approximately 28% of the Company's total proved reserves at 
December 31, 1996, were undeveloped, which are by their nature 
less certain.  Recovery of such reserves will require significant 
capital expenditures and successful drilling operations.  The 
reserve data set forth in the GeoQuest Report assumes, based on 
the Company's estimates, that aggregate capital expenditures by 
the Company of approximately $6.4 million through 1998 will be 
required to develop such reserves.  Although cost and reserve 
estimates attributable to the Company's oil and gas reserves have 
been prepared in accordance with industry standards, no assurance 
can be given that the estimated costs are accurate, that 
development will occur as scheduled or that the results will be as 
estimated.

The present value of future net revenues referred to in this 
report should not be construed as the current market value of the 
estimated oil and gas reserves attributable to the Company's 
properties.  In accordance with applicable requirements of the 
Commission, the estimated discounted future net cash flows from 
proved reserves are generally based on prices and costs as of the 
date of the estimate, whereas actual future prices and costs may 
be materially higher or lower.  Actual future net cash flows also 
will be affected by changes in consumption and changes in 
governmental regulations or taxation.  The timing of actual future 
net cash flows from proved reserves, and thus their actual present 
value, will be affected by the timing of both the production and 
the incurrence of expenses in connection with development and 
production of oil and gas properties.  In addition, the 10% 
discount factor, which is required by the Commission to be used in 
calculating discounted future net cash flows for reporting 
purposes, is not necessarily the most appropriate discount factor 
based on interest rates in effect from time to time and risks 
associated with the Company or the oil and gas industry in 
general.

Need for Additional Capital

Due to its active development and exploration program, the Company 
has substantial working capital requirements.  The Company 
believes its current capital and cash flow from operations will 
allow the Company to successfully implement its present business 
strategy.  Additional financing may be required in the future to 
fund the Company's developmental and exploratory drilling.  No 
assurances can be given as to the availability or terms of any 
such additional financing that may be required.  In the event such 
capital resources are not available to the Company, its drilling 
activity may be curtailed.

Replacement of Reserves

The Company's future success will depend upon its ability to find, 
develop or acquire additional oil and gas reserves at prices that 
permit profitable operations.  Unless the Company conducts 
successful exploitation or exploration activities or acquires 
properties containing reserves, the proved reserves of the Company 
will decline.  There can be no assurance that the Company's 
acquisition, exploitation and exploration activities will result 
in additional reserves, or that the Company will be able to drill 
productive wells at acceptable costs.

Operating Hazards; Uninsured Risks

The oil and gas business involves a variety of operating risks, 
including the risk of fire, explosions, blow-outs, pipe failure, 
casing collapse, abnormally pressured formations and environmental 
hazards such as oil spills, gas leaks, ruptures and discharges of 
toxic gases, the occurrence of any of which could result in 
substantial losses to the Company due to injury and loss of life, 
damage to and destruction of property and equipment, pollution and 
other environmental damage and related suspension of operations.  
Gathering systems and processing plants are subject to many of the 
same hazards, and any significant problems related to those 
facilities could adversely affect the Company's ability to market 
its production.  Drilling activities are subject to numerous 
risks, including the risk that no commercially productive oil or 
gas reservoirs will be encountered or that particular wells will 
not produce at economic levels.  The cost of drilling, completing 
and operating wells may vary from initial estimates.  Drilling 
activities may be curtailed, delayed or canceled as a result of 
numerous factors outside the Company's control, including but not 
limited to title problems, weather conditions, compliance with 
governmental requirements, mechanical difficulties and shortages 
or delays in the delivery of drilling rigs or other equipment.  
The Company maintains insurance against some, but not all, 
potential risks; however, there can be no assurance that such 
insurance will be adequate to cover any losses or exposure for 
liability.  Furthermore, the Company cannot predict whether 
insurance will continue to be available at premium levels that 
justify its purchase or whether insurance will be available at 
all.

Regulation

Virtually all of the Company's oil and gas activities are subject 
to a wide variety of federal, state, local and foreign 
governmental regulations, which are changed from time to time in 
response to economic or political conditions.  Matters subject to 
regulation include, but are not limited to, environmental matters, 
discharge permits for drilling operations, drilling and operating 
bonds, reports concerning operations, the spacing of wells, 
unitization and pooling of properties, allowable rates of 
production, restoration of surface areas, plugging and abandonment 
of wells, requirements for the operation of wells and taxation.  
From time to time, regulatory agencies have imposed price controls 
and limitations on production by restricting the rate of flow of 
oil and gas wells below actual production capacity in order to 
conserve supplies of oil and gas.  Many states have raised state 
taxes on energy sources and additional increases may occur, 
although there can be no certainty of the effect that such 
increases would have on the Company.  Legislation and new 
regulations concerning oil and gas exploration and production 
operations are constantly being reviewed and proposed.  All of the 
jurisdictions in which the Company owns and operates properties 
have statutes and regulations governing a number of the matters 
enumerated above.  Compliance with such laws and regulations 
generally increases the Company's cost of doing business and 
consequently affects its profitability.  Due to the frequently 
changing requirements of laws and regulations, there can be no 
assurance that costs of future compliance will not impose new or 
substantial burdens on the Company.

Environmental Matters

The discharge of oil, gas or other pollutants into the air, soil 
or water may give rise to liabilities to governmental agencies and 
third parties, and may require the Company to incur costs to 
remedy such discharges.  Oil, natural gas and other pollutants 
(including salt water brine) may be discharged in many ways, 
including from a well or drilling equipment at a drill site, 
leakage from pipelines or other gathering and transportation 
facilities, leakage from storage tanks and tailings ponds, and 
sudden discharges from damage or explosion at natural gas 
facilities, oil and gas wells or other facilities.  Discharged 
hydrocarbons and other pollutants may migrate through soil to 
water supplies or adjoining property, giving rise to additional 
liabilities.  A variety of federal, state and foreign laws and 
regulations govern the environmental aspects of oil and natural 
gas exploration, production and transportation and may, in 
addition to other laws and regulations, impose liability in the 
event of discharges (whether or not accidental), failure to notify 
the proper authorities of a discharge, and other failures to 
comply with those laws and regulations.  Compliance with 
environmental quality requirements and reclamation laws imposed by 
governmental authorities may necessitate significant capital 
outlays, may materially affect the acquisition or operating costs 
of a given property, or may cause material changes or delays in 
the Company's intended activities.  Management of the Company does 
not believe that its environmental, health, and safety risks are 
materially different from those of comparable companies engaged in 
similar businesses.  Nevertheless, new or different environmental 
standards imposed in the future may adversely affect the Company's 
activities and there can be no assurance that significant costs 
for compliance will not be incurred in the future.  Moreover, no 
assurance can be given that environmental laws will not, in the 
future, result in curtailment of production or material increases 
in the cost of exploration, development or production or otherwise 
adversely affect the Company's operations and financial condition.

Ownership Interest in Laguna

The Company currently owns approximately 14 million shares of 
Laguna common stock.  The Company has no current plans for 
disposing of such shares, and approximately 8.4 million of the 
shares owned by the Company are subject to an escrow agreement 
with The Toronto Stock Exchange that restricts the ability of the 
Company to sell such shares for up to three years.  No assurance 
can be given as to the value that might be received by the Company 
in the future from any transaction in which such interest is sold.  
Furthermore, although the common stock of Laguna is publicly 
traded in Canada on The Toronto Stock Exchange, trading prices on 
that exchange are not necessarily representative of the 
consideration the Company could obtain for such shares currently 
or in the future.

The value of the Company's investment in Laguna will be affected 
by the business results of Laguna.  There are many uncertainties 
in any mineral exploration and development program, such as the 
location of economic ore bodies, the receipt of necessary 
government permits and the construction of mining and processing 
facilities, as well as widely fluctuating prices of minerals.  
Because Laguna's properties are in Costa Rica, additional 
uncertainties include currency risks, risks of changes in foreign 
laws and the risk of expropriation.  Substantial expenditures will 
be required to pursue Laguna's exploration and development 
activities, and substantial time may elapse from the initial 
phases of development until Laguna's activities are fully 
operational.

Statement of Financial Accounting Standards No. 121 ("SFAS 121") 
requires that an impairment loss be recognized in the event that 
facts and circumstances indicate that the carrying amount of an 
asset may not be recoverable.  Estimated future undiscounted net 
cash flow projections developed by Laguna to assess the 
recoverability of its properties include consideration of the 
following factors, among others:  projected mineable reserves 
based upon third party engineering reports; estimated capital 
expenditures required to put the mine on production; projected 
rates of gold and silver production; estimated waste handling and 
stripping costs; projected mine life; recovery rates for gold and 
silver; and estimated gold and silver prices.  The timing of 
projected cash flows is based on the estimated mine life and the 
estimated cost to bring the mine into production.  The testing 
takes into account the type of processing proposed -- either a 
mill or a heap leach - and the timing of the capital expenditures 
required, which vary.  The budgeted capital expenditures are also 
varied depending on the type of process assumed.  The SFAS 121 
impairment testing at December 31, 1996 concluded that no 
impairment loss was required to be recognized.  While impairment 
testing is designed to assure that recorded costs are recoverable 
under assumed, ordinary course operations at a particular point in 
time, such testing cannot assure that such costs will be recovered 
in the event of a sale or other disposition of the property or of 
the Company's interest in Laguna as a whole.  Moreover, many of 
the factors assumed in performing the testing (including prices 
and costs) are matters outside Laguna's control and are subject to 
change over time.

Reliance on Key Personnel

The Company is dependent upon its executive officers, key 
employees and certain consultants.  The unexpected loss of 
services of one or more of these individuals could have a 
detrimental effect on the Company.  The Company does not maintain 
key man insurance on any of its executive officers or key 
employees.  In addition, the continued growth and expansion of the 
Company will depend upon, among other factors, the successful 
retention of skilled and experienced management and technical 
personnel.

Competition

The oil and gas industry and the mining industry are both highly 
competitive.  The Company competes with major companies, other 
independent concerns and individual producers and operators.  Many 
of these competitors have substantially greater financial and 
other resources than does the Company.

Item 6 of the 1996 Form 10-K is hereby amended to read in its 
entirety as follows:

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, 1996.  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,
                                           1996       1995       1994       1993       1992 
                                               (In thousands, except per share data)
<C>                                      <S>        <S>        <S>        <S>        <S>
Selected Statements of Operations Data: 
  Revenues: 
     Oil and gas sales                   $ 5,854    $ 4,800    $ 4,629    $ 2,061    $ 1,408 
     Other                                   666        628       280         230        568 
                                           6,520      5,428     4,909       2,291      1,976 
  Costs and expenses: 
     Oil and gas production                2,249      1,868     2,024         976        800 
     Mining project expenses               1,014        838       459         390        380 
     Depreciation, depletion and 
        amortization                       2,095      2,340     2,409         937        306 
     Impairment of oil and gas properties    264         --        --          --         -- 
     General and administrative            1,999      1,625     1,516         926        682 
     Interest and other                      842        433       132         249         76 
                                           8,463      7,104     6,540       3,478      2,244 

  Minority interest in loss of 
     consolidated subsidiary                 266         --        --          --         -- 
  Loss before extraordinary item          (1,677)    (1,676)   (1,631)     (1,187)       (268)

  Extraordinary loss on early retirement 
     of debt                                (160)      (253)       --          --         -- 
  Net loss                                (1,837)    (1,929)   (1,631)      (1,187)      (268)

  Dividends on preferred stock and 
     accretion                              (376)      (360)     (258)          --        -- 

  Net loss attributable to common 
     shareholders                        $(2,213)   $(2,289)   $(1,889)   $(1,187)    $  (268)

Selected Per Share Data (1): 
  Loss attributable to common share-
     holders before extraordinary item   $ (0.82)   $ (1.04)   $ (1.00)   $ (0.87)    $ (0.22)
  Extraordinary loss                       (0.06)     (0.12)        --         --         -- 
  Net loss attributable to common 
     shareholders                        $ (0.88)   $ (1.16)   $ (1.00)   $ (0.87)    $ (0.22)

  Weighted average shares outstanding      2,512      1,947      1,916      1,368       1,195 

Selected Cash Flow and Other Data: 
    EBITDA (2)                           $ 1,520    $ 1,093    $   876    $   (79)    $    56 
    Capital expenditures                   6,339      3,883      2,379     20,612         190 
</TABLE>

<TABLE>
<CAPTION> 
                                                         At December 31,
                                            1996       1995       1994       1993       1992  
<C>                                       <S>        <S>        <S>        <S>        <S>
Selected Balance Sheet Data: 
  Total assets                            $41,400    $31,635    $28,226    $28,773    $7,675 
  Long-term debt (3)                        3,511     10,037         --         20        30 
  Mandatorily redeemable preferred stock    3,900      3,844      3,804         --        -- 
  Shareholders' equity                     21,904     11,760     13,549     15,029     6,738 
</TABLE>______________

1)  As adjusted for four-to-one reverse stock split.

2)  EBITDA is earnings before income taxes, interest expense, 
depreciation, depletion and amortization, impairment, and 
extraordinary loss.  EBITDA is a financial measure commonly used 
in the Company's industry and should not be considered in 
isolation or as a substitute for net income, cash flow provided by 
operating activities or other income or cash flow data prepared in 
accordance with generally accepted accounting principles or as a 
measure of a company's profitability or liquidity.  The Company 
believes that EBITDA may provide additional information about the 
Company's ability to meet its future requirements for debt 
service, capital expenditures and working capital.  When 
evaluating EBITDA, investors should consider, among other factors, 
(i) increasing or decreasing treads in EBITDA, (ii) whether EBITDA 
has remained at positive levels historically and (iii) how EBITDA 
compares to levels of interest expense.  Other companies may 
define EBITDA differently, and as a result, such measures may not 
be comparable to the Company's EBITDA.

3)  Long-term debt includes long-term debt net of current 
maturities, notes payable-other and capital lease obligations net 
of current portion.


Item 7 of the 1996 Form 10-K is hereby amended to read in its 
entirety as follows:

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

The following discussion is intended to assist in understanding 
the Company's historical consolidated financial position at 
December 31, 1996, 1995 and 1994, and results of operations and 
cash flows for each of the three years in the period ended 
December 31, 1996.  The Company's historical Consolidated 
Financial Statements and notes thereto included elsewhere herein 
contain detailed information that should be referred to in 
conjunction with the following discussion.  The financial 
information discussed below is consolidated information, which 
includes the accounts of Laguna.

Overview

Historically, the Company has engaged in two separate and distinct 
facets of the natural resources business.  Through Mallon Oil, the 
Company has pursued its core oil and gas business.  Through 
Laguna, the Company has engaged in mining activities.  By early 
1996, the Company concluded that the level of capital and 
management resources required to fully develop each of these 
businesses made it inadvisable for the Company to continue to 
pursue both.  Accordingly, the Company separated the businesses by 
establishing the financial independence of Laguna and having the 
Company focus its efforts on the oil and gas business.  Laguna's 
recent Canadian financing and listing on The Toronto Stock 
Exchange were the key steps toward accomplishment of that goal and 
should permit Laguna to operate independently without further 
reliance on the Company for financial support.  The Company does 
not have any obligation or intention to finance Laguna's future 
operations.

In light of the recent implementation of this fundamental change 
in the manner in which the Company will henceforth pursue its 
business, the Company's past financial performance is not 
necessarily indicative of its future operations.

The Company's revenues, profitability and future rate of growth 
will be substantially dependent upon prevailing prices for oil and 
gas, which are in turn dependent upon numerous factors that are 
beyond the Company's control, such as economic, political and 
regulatory developments and competition from other sources of 
energy.  The energy markets have historically been volatile, and 
there can be no assurance that oil and gas prices will not be 
subject to wide fluctuations in the future.  A substantial or 
extended decline in oil or gas prices could have a material 
adverse effect on the Company's financial position, results of 
operations and access to capital, as well as the quantities of oil 
and gas reserves that the Company may economically produce.

Liquidity and Capital Resources

In October 1996, the Company sold 2,300,000 shares of the 
Company's common stock in a public offering.  The Company received 
proceeds of approximately $13,189,000, net of offering costs of 
$1,761,000.  Until its October 1996 equity offering, the Company 
had, since inception, been significantly constrained by a 
continued shortage of capital.  The October 1996 equity offering 
remedied that problem, at least for the foreseeable future.  For 
the first time in the Company's history, the Company has funds 
available to develop and exploit the Company's substantial 
inventory of oil and gas properties.  Management is of the view 
that the Company's chronic liquidity problem can now be solved, on 
a long term basis, by the Company's development of its oil and gas 
properties.  Management believes that such operations will 
increase cash flow and improve liquidity, and thereby allow the 
Company to avoid future working capital short-falls.  The Company 
had a working capital surplus of $5,365,000 at December 31, 1996 
compared to a deficit of $476,000 at December 31, 1995.  The 
increase in working capital at December 31, 1996 is primarily due 
to higher cash balances as a result of the equity offerings by the 
Company and Laguna in 1996.

In March 1996, the Company established a $35,000,000 credit 
facility (the "Facility") with Bank One, Texas, N.A. (the "Bank').  
The Facility establishes two separate lines of credit:  a primary 
revolving line of credit (the "Revolver") and a line of credit to 
be used for development drilling approved by the Bank (the 
"Drilling Line').  The borrowing base under the Revolver is 
subject to redetermination every six months, or at such other 
times as the Bank may determine.  The Company is obligated to 
maintain certain financial and other covenants, including a 
minimum current ratio, minimum net equity, a debt coverage ratio 
and a total bank debt ceiling.  The Facility is collateralized by 
substantially all of the Company's oil and gas properties.  The 
Facility expires March 31, 1999.  The initial borrowing base under 
the Revolver was $10,500,000.  Initial amounts drawn under the 
Revolver were used to retire the amount outstanding under the 
Company's prior line of credit of approximately $10,000,000 and 
related accrued interest.  At June 30, 1996, the borrowing base 
was redetermined and reduced to $8,820,000.  At that time, the 
amount outstanding under the Revolver was $10,231,000, or 
$1,411,000 in excess of the redetermined borrowing base.  Per the 
amended terms of the Facility, the Company drew $2,000,000 under 
the Drilling Line and applied it to reduce amounts outstanding 
under the Revolver to an amount below the redetermined borrowing 
base.  The $2,000,000 drawn under the Drilling Line and $5,301,000 
under the Revolver were repaid in October 1996 upon the completion 
of the public stock sale, discussed below.  Once repaid, the 
Company can no longer borrow against the Drilling Line.  At 
December 31, 1996, the borrowing base under the Revolver was 
$8,820,000, and the principal amount outstanding was $3,269,000, 
leaving the amount available under the Revolver at $5,551,000.  
Effective January 1997, the Borrowing Base was increased to 
$10,000,000.  At March 25, 1997, the principal amount outstanding 
was $3,269,000, leaving the amount remaining available under the 
Revolver at $6,731,000.  The Company is currently in compliance 
with the covenants of the Facility.  For additional information 
concerning the Facility, see Note 4 to the Consolidated Financial 
Statements.

Approximately $1,987,000 of the net proceeds from the Company's 
October 1996 offering were used to purchase and retire all 
outstanding shares of the Company's Series A Convertible Preferred 
Stock.

In May 1996, Laguna sold 5,000,000 Special Warrants for $1.00 per 
Warrant in a private placement for net proceeds of $4,339,000.  In 
September 1996, Laguna completed the registration of the sale of 
the Special Warrants with the Ontario (Canada) Securities 
Commission.

Mandatory redemption of the Company's Series B Mandatorily 
Redeemable Convertible Preferred Stock (the "Series B Stock") was 
to begin in April 1997, when 20% of the outstanding shares (i.e., 
80,000 shares) were to be redeemed for $800,000.  The Company has 
extended an offer to all holders of the Series B Stock to convert 
their shares into shares of the Company's common stock at a 
conversion price of $9.00, rather than the $11.31 conversion price 
otherwise in effect.  On March 25, 1997, a holder of 200,000 
shares of Series B Stock accepted the offer to convert.  When 
completed, this conversion will satisfy the Company's obligation 
to redeem any shares in April.  

Historically, the Company's involvement in both oil and gas and 
mining activities has hampered its ability to raise capital due to 
the complexity of the Company's financial structure and apparent 
market perceptions that the Company was too small to effectively 
pursue two such disparate businesses.  By establishing independent 
financing arrangements for Laguna, management hopes to overcome 
these problems, and place the Company in a position to exploit its 
oil and gas acreage.  The elimination of the Company's commitment 
to fund Laguna's operations should assist the Company in these 
efforts.

To implement its planned drilling and development programs, the 
Company expended $2,462,000 in 1996 and plans to spend 
approximately $10 million in 1997.  With the net proceeds of the 
equity offering, the Company's working capital and credit facility 
and the operating cash flows that are expected to be generated by 
the application of such funds to the Company's drilling program, 
management anticipates that the Company will have sufficient 
capital to fund the continued development of its current 
properties and to meet the Company's liquidity requirements for 
the foreseeable future.

Results of Operations

<TABLE>
<CAPTION>
                                       Year Ended December 31,
                                     1996       1995(1)    1994(1)
                              (In thousands, except per unit data)
<C>                                 <S>        <S>        <S>
Results of Operations: 
    Revenues                        $ 6,520    $ 5,428    $ 4,909 
    Costs and expenses                8,463      7,104      6,540 
    Net loss                         (1,837)    (1,929)    (1,631)
    Net loss attributable to common 
       shareholders                  (2,213)    (2,289)    (1,889)
    Net loss per share attributable 
       to common shares               (0.88)     (1.16)     (1.00)
    EBITDA (2)                        1,520      1,093        876 
    Capital expenditures              6,339      3,995      2,379 

Operating Results from Oil and Gas Operations: 
    Oil and gas revenues            $ 5,854    $ 4,800    $ 4,629 
    Oil and gas production expenses   2,249      1,868      2,024 
    Depletion                         1,924      2,162      2,337 

Net Production: 
    Oil (MBbl)                          174        173        146 
    Natural gas (MMcf)                1,286      1,238      1,648 
    BOE                                 388        379        421 

Average Sales Price Realized: 
    Oil (per Bbl)                   $ 18.05    $ 16.45    $ 14.81 
    Natural gas (per Mcf)           $  2.11    $  1.58    $  1.50 
    Per BOE                         $ 15.09    $ 12.66    $ 11.00 

Average production costs and taxes 
    (per BOE):                      $  5.80    $  4.93    $  4.81 

Average depletion (per BOE):        $  4.96    $  5.70    $  5.53 
</TABLE>
_________________
1)  Includes 692 MMcf and 961 MMcf and 26 MBbls and 48 MBbls 
delivered in 1995 and 1994, respectively, pursuant to the terms of 
the volumetric production agreement which was retired in August 
1995.

2)  EBITDA is earnings before income taxes, interest expense, 
depreciation, depletion and amortization, impairment, and 
extraordinary loss.  EBITDA is a financial measure commonly used 
in the Company's industry and should not be considered in 
isolation or as a substitute for net income, cash flow provided by 
operating activities or other income or cash flow data prepared in 
accordance with generally accepted accounting principles or as a 
measure of a company's profitability or liquidity.  The Company 
believes that EBITDA may provide additional information about the 
Company's ability to meet its future requirements for debt 
service, capital expenditures and working capital.  When 
evaluating EBITDA, investors should consider, among other factors, 
(i) increasing or decreasing treads in EBITDA, (ii) whether EBITDA 
has remained at positive levels historically and (iii) how EBITDA 
compares to levels of interest expense.  Other companies may 
define EBITDA differently, and as a result, such measures may not 
be comparable to the Company's EBITDA.

Year Ended December 31, 1996 Compared with Year Ended December 31, 
1995

Revenues.  Total revenues for the year ended December 31, 1996 
increased 20% to $6,520,000 from $5,428,000 for the year ended 
December 31, 1995.  Oil and gas sales for the year ended 
December 31, 1996 increased 22% to $5,854,000 from $4,800,000 
(including amortization of deferred revenues from a volumetric 
production payment in the year ended December 31, 1995.)  The 
increase was primarily due to higher oil and gas prices.  Average 
oil prices for the year ended December 31, 1996 increased 10% to 
$18.05 per Bbl from $16.45 per Bbl for the year ended December 31, 
1995.  Average gas prices for the year ended December 31, 1996 
increased 34% to $2.11 per Mcf from $1.58 per Mcf for the year 
ended December 31, 1995.  The $329,000 gain on the sale of Laguna 
common stock for the year ended December 31, 1996 compares to the 
$355,000 gain on the termination of a volumetric production 
payment for the year ended December 31, 1995.  There were no sales 
of gold or silver in 1996 or 1995, and no such sales are expected 
in the immediate future.

Oil and Gas Production Expenses.  Oil and gas production expenses 
for the year ended December 31, 1996 increased 20% to $2,249,000 
from $1,868,000 for the year ended December 31, 1995.  The 
increase was primarily attributable to increased operating costs 
related to new wells drilled in 1996 and increased workover 
expenses.

Mining Project Expenses.  Mining project expenses for the year 
ended December 31, 1996 increased 21% to $1,014,000 from $838,000 
for the year ended December 31, 1995.  The increase was primarily 
due to Laguna's drilling program in new exploration areas and 
business development expenses related to reviewing other mineral 
concessions.

Depreciation, Depletion and Amortization.  Depreciation, depletion 
and amortization for the year ended December 31, 1996 decreased 
11% to $2,095,000 from $2,340,000 for the year ended December 31, 
1995.  Depletion per BOE for the year ended December 31, 1996 
decreased 13% to $4.96 from $5.70 for the year ended December 31, 
1995, primarily due to an increase in oil and gas reserves.

General and Administrative Expenses.  General and administrative 
expenses for the year ended December 31, 1996 increased 23% to 
$1,999,000 from $1,625,000 for the year ended December 31, 1995 
due primarily to increased stock compensation costs.

Impairment of Oil and Gas Properties.  Impairment of oil and gas 
properties was $264,000 during the year ended December 31, 1996 
compared to $-0- for the year ended December 31, 1995.  In fiscal 
1996, the Company acquired a 2.25% working interest in an 
exploration venture to drill one or more wells offshore Belize.  
As of December 31, 1996, the Company had incurred and capitalized 
$264,000 related to this venture.  The joint venture drilled a dry 
hole subsequent to December 31, 1996.  Accordingly, the Company 
reduced the carrying amount of its capitalized costs by $264,000.  
During fiscal 1995, the Company's oil and gas activities were 
conducted entirely in the United States.

Interest and Other Expenses.  Interest and other expenses for the 
year ended December 31, 1996 increased 95% to $842,000 from 
$433,000 for the year ended December 31, 1995.  The increase was 
primarily due to higher outstanding borrowings under the Company's 
credit facility.

Minority Interest.  Minority interest in loss of consolidated 
subsidiary of $266,000 represents the minority interest share in 
the Laguna loss.

Income Taxes.  The Company incurred net operating losses ("NOLs") 
for U.S. Federal income tax purposes in 1996 and 1995, 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.  The 
Company's ability to realize the benefit of its deferred tax asset 
will depend on the generation of future taxable income through 
profitable operations and the expansion of the Company's oil and 
gas producing activities.  The market and capital risks associated 
with achieving the above requirement are considerable, resulting 
in the Company's decision to provide a valuation allowance equal 
to the net deferred tax asset.  Accordingly, the Company did not 
recognize any tax benefit in its consolidated statement of 
operations for the years ended December 31, 1996 and 1995.  At 
December 31, 1996, the Company had an NOL carryforward for U.S. 
Federal income tax purposes of approximately $16,100,000, which 
will begin to expire in 2005.

Extraordinary Loss.  The Company incurred extraordinary losses of 
$160,000 and $253,000 during the years ended December 31, 1996 and 
1995, respectively, as a result of the refinancing of its credit 
facilities with new lenders.

Net Loss.  Net loss for the year ended December 31, 1996 decreased 
5% to $1,837,000 from $1,929,000 for the year ended December 31, 
1995 as a result of the factors discussed above.  The Company paid 
the 8% dividend of $320,000 on its $4,000,000 face amount Series B 
Mandatorily Redeemable Convertible Preferred Stock ("Series B 
Preferred Stock") in each of the years ended December 31, 1996 and 
1995, and realized accretion of $56,000 and $40,000, respectively.  
Net loss attributable to common shareholders for the year ended 
December 31, 1996 decreased 3% to $2,213,000 from $2,289,000 for 
the year ended December 31, 1995.

Year Ended December 31, 1995 Compared with Year Ended December 31, 
1994

Revenues.  Total revenues for the year ended December 31, 1995 
increased 11% to $5,428,000 from $4,909,000 for the year ended 
December 31, 1994.  The increase was primarily due to a gain of 
$355,000 on termination of a volumetric production payment.  For 
the year ended December 31, 1995 oil and gas sales, including 
amortization of deferred revenue from a volumetric production 
payment, increased 4% to $4,800,000 from $4,629,000 for the year 
ended December 31, 1994.  Total oil production increased 19% to 
173 MBbls and total gas production decreased 25% to 1,238 MMcf for 
the year ended December 31, 1995.  The increase in oil sales was 
due to the completion of eight productive wells during 1995, and 
the decrease in gas sales was due in part to a decrease in 
production from one of the Company's producing properties, which 
has a steep decline curve, accounting for 267 MMcf of the 
production decrease.  Average oil prices for the year ended 
December 31, 1995 increased 11% to $16.45 per Bbl from $14.81 per 
Bbl for the year ended December 31, 1994.  Average gas prices for 
the year ended December 31, 1995 increased 5% to $1.58 per Mcf 
from $1.50 per Mcf for the year ended December 31, 1994.  During 
the years ended December 31, 1995 and 1994, there were no sales of 
gold or silver.

Oil and Gas Production Expenses.  Oil and gas production expenses 
for the year ended December 31, 1995 decreased 8% to $1,868,000 
from $2,024,000 for the year ended December 31, 1994.  The 
decrease was primarily due to a reduction in repair costs in some 
of the Company's older fields.

Mining Project Expenses.  Mining project expenses for the year 
ended December 31, 1995 increased 83% to $838,000 from $459,000 
for year ended December 31, 1994.  The increase was due primarily 
to increased general and administrative costs relating to expanded 
operations.

General and Administrative Expenses.  General and administrative 
expenses for the year ended December 31, 1995 increased 7% to 
$1,625,000 from $1,516,000 for the year ended December 31, 1994.  
The increase was primarily due to an increase in investment 
banking fees related to a contract which expired in 1995 and 
additional salary expense for two officers hired April 1, 1994, 
which was included for a full year in 1995.  These increases were 
partially offset by a reduction in legal fees and office expenses.

Depreciation, Depletion and Amortization.  Depreciation, depletion 
and amortization for the year ended December 31, 1995 decreased 3% 
to $2,340,000 from $2,409,000 for the year ended December 31, 
1994.  Depletion per BOE for the year ended December 31, 1995 
increased 3% to $5.70 from $5.53 for the year ended December 31, 
1994, primarily due to lower gas production.

Interest and Other Expenses.  Interest and other expenses for the 
year ended December 31, 1995 increased 228% to $433,000 from 
$132,000 for the year ended December 31, 1994.  The increase was 
primarily due to higher outstanding borrowings under the Company's 
credit facility, which were used primarily to terminate a 
volumetric production payment in August 1995.

Income Taxes.  The Company incurred NOLs for U.S. Federal income 
tax purposes in 1995 and 1994, 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.  The Company's ability to 
realize the benefit of its deferred tax asset will depend on the 
generation of future taxable income through profitable operations 
and the expansion of the Company's oil and gas producing 
activities.  The market and capital risks associated with 
achieving the above requirement are considerable, resulting in the 
Company's decision to provide a valuation allowance equal to the 
deferred tax asset.  Accordingly, the Company did not recognize 
any tax benefit in its consolidated statement of operations for 
the years ended December 31, 1995 and 1994.  At December 31, 1995, 
the Company had an NOL carryforward for U.S. Federal income tax 
purposes of approximately $13,400,000, which will begin to expire 
in 2005.

Extraordinary Loss.  The Company incurred an extraordinary loss of 
$253,000 during 1995 as a result of the refinancing of its credit 
facility with a new lender.

Net Loss.  Net loss for the year ended December 31, 1995 increased 
18% to $1,929,000 from $1,631,000 for the year ended December 31, 
1994 as a result of the factors discussed above.  The Company paid 
the 8% dividend totaling $320,000 and $228,000 on its Series B 
Preferred Stock during 1995 and 1994, respectively, and realized 
accretion of $40,000 and $30,000, respectively.  Net loss 
attributable to common shareholders for the year ended 
December 31, 1995 increased 21.2% to $2,289,000 from $1,889,000 
for the year ended December 31, 1994.

Hedging Activities

The Company uses hedging instruments to manage commodity price 
risks.  The Company has 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 the Company's financial interests from 
the volatility of oil and gas prices.

At December 31, 1996, the Company had natural gas swaps in place 
covering an aggregate of 90,000 MMBtu per month of 1997 production 
at fixed prices ranging from $2.54 to $1.50 per MMBtu on an 
"Inside FERC" basis, and oil swaps in place covering an aggregate 
of 9,000 Bbls per month of 1997 production at fixed prices ranging 
from $23.36 to $19.99 on a "NYMEX" basis.  For the years ended 
December 31, 1996, 1995 and 1994, the Company's gains (losses) 
under its swap agreements were ($490,000), $34,000, and $43,000, 
respectively.  For further information about the Company's energy 
swaps, see Note 12 to the Consolidated Financial Statements.

Miscellaneous

The Company's oil and gas operations are significantly affected by 
certain provisions of the Internal Revenue Code of 1986, as 
amended (the "Code"), that are applicable to the oil and gas 
industry.  Current law permits the Company to deduct currently, 
rather than capitalize, intangible drilling and development costs 
incurred or borne by it.  The Company, as an independent producer, 
is also entitled to a deduction for percentage depletion with 
respect to the first 1,000 Bbls 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 the Company's 
taxable income.  Any depletion disallowed under the 65% 
limitation, however, may be carried over indefinitely.

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