MALLON RESOURCES CORP, S-2/A, 1997-11-24

MALLON RESOURCES CORP
S-2/A, 1997-11-24
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON NOVEMBER 24, 1997

FILE NO. 333-38195

================================================================================
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

AMENDMENT NO. 1

FORM S-2

REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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

<TABLE>
<C> <C>
COLORADO 84-1095959
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
GEORGE O. MALLON, JR.
999 18TH STREET, SUITE 1700 MALLON RESOURCES CORPORATION
DENVER, CO 80202 999 18TH STREET, SUITE 1700
(303) 293-2333 DENVER, CO 80202
(Address, including zip code, and telephone (303) 293-2333
number, (Address, including zip code, and telephone
including area code, of registrant's principal number,
executive office) including area code, of agent for service)
</TABLE>

Copies to:

<TABLE>
<C> <C> <C>
THOMAS A. RICHARDSON, ESQ. ALAN P. BADEN, ESQ. ROY K. ROSS, ESQ.
HOLME ROBERTS & OWEN LLP VINSON & ELKINS L.L.P. MALLON RESOURCES CORPORATION
1700 Lincoln, Suite 4100 1001 Fannin, Suite 2300 999 18th Street, Suite 1700
Denver, CO 80203 Houston, Texas 77002 Denver, CO 80202
(303) 861-7000 (713) 758-2222 (303) 293-2333
</TABLE>

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after the effective date of this Registration Statement.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING
PURSUANT TO SAID SECTION 8(a), MAY DETERMINE.

================================================================================
<PAGE> 2

INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A
REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR
MAY OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT
BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR
THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE
SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE
UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS
OF ANY SUCH STATE.

SUBJECT TO COMPLETION, DATED NOVEMBER 24, 1997

PROSPECTUS

2,300,000 SHARES

[MALLON RESOURCES LOGO]

COMMON STOCK

All of the 2,300,000 shares of common stock ("Common Stock") offered hereby
are being sold by Mallon Resources Corporation (the "Company").

The Common Stock is quoted on the Nasdaq National Market under the symbol
"MLRC." On November 21, 1997, the closing price of the Common Stock as reported
by the Nasdaq National Market was $9.88 per share. See "Price Range of Common
Stock."

SEE "RISK FACTORS" BEGINNING ON PAGE 8 FOR A DISCUSSION OF FACTORS THAT
SHOULD BE CONSIDERED BY PROSPECTIVE PURCHASERS OF THE COMMON STOCK OFFERED
HEREBY.

---------------------

THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS
THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS
PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY
IS A CRIMINAL OFFENSE.

<TABLE>
<CAPTION>
=================================================================================================================
PRICE TO UNDERWRITING PROCEEDS TO
PUBLIC DISCOUNTS(1) COMPANY(2)
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Per Share $ $ $
- -----------------------------------------------------------------------------------------------------------------
Total(3) $ $ $
=================================================================================================================
</TABLE>

(1) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities arising under the Securities Act of 1933,
as amended. See "Underwriting."
(2) Before deducting expenses payable by the Company estimated at $310,000.
(3) The Company has granted to the Underwriters a 30-day option to purchase up
to 345,000 additional shares of Common Stock, solely to cover
over-allotments, if any, on the same terms and conditions as the shares
offered hereby. If such option is exercised in full, the total Price to
Public, Underwriting Discounts and Proceeds to Company will be $ ,
$ and $ , respectively. See "Underwriting."

---------------------

The shares of Common Stock are offered severally by the Underwriters
specified herein, subject to receipt and acceptance by them and subject to their
right to reject any order, in whole or in part. It is expected that delivery of
the certificates representing the shares will be made against payment therefor
in Chicago, Illinois, on or about December , 1997.

ABN AMRO CHICAGO CORPORATION GAINES, BERLAND INC.

DECEMBER , 1997

<PAGE> 3

PRINCIPAL AREAS OF ACTIVITY

The map below reflects the general location of the Company's principal
acreage positions in the San Juan and Delaware Basins of New Mexico. Although,
as reflected by the map, the Company's acreage is largely located in the
vicinity of acreage that has, historically, produced oil or natural gas, no
assurance can be given that the Company's undeveloped acreage in these areas
contains commercial quantities of oil or natural gas. Also, due to limitations
of the map's scale, the Company's acreage blocks are depicted as relatively
larger than they are in fact. The formation depths shown are approximations.
Actual depths vary throughout the Basins. See "Business and
Properties -- Selected Fields and Areas of Interest."

CERTAIN PERSONS PARTICIPATING IN THIS OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE COMMON STOCK,
INCLUDING OVER-ALLOTMENT, STABILIZING AND SHORT-COVERING TRANSACTIONS IN SUCH
SECURITIES, AND THE IMPOSITION OF A PENALTY BID IN CONNECTION WITH THE OFFERING.
IN ADDITION, CERTAIN UNDERWRITERS (AND SELLING GROUP MEMBERS, IF ANY) ALSO MAY
ENGAGE IN PASSIVE MARKET MAKING TRANSACTIONS IN THE COMMON STOCK ON THE NASDAQ
NATIONAL MARKET, IN ACCORDANCE WITH RULE 103 OF THE SECURITIES EXCHANGE ACT OF
1934. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITING."
<PAGE> 4

PROSPECTUS SUMMARY

The following summary should be read in conjunction with, and is qualified
in its entirety by, the more detailed information and Consolidated Financial
Statements (including the notes thereto) appearing elsewhere in this Prospectus
and incorporated herein by reference. The term "Company" refers to Mallon
Resources Corporation and its wholly-owned subsidiary, Mallon Oil Company
("Mallon Oil"), but such references do not include Laguna Gold Company
("Laguna"), the Company's majority-owned, consolidated subsidiary, except when
consolidated financial information is being presented or unless the context
requires otherwise. Unless otherwise indicated, the information in this
Prospectus assumes that the Underwriters' over-allotment option will not be
exercised. All Common Stock amounts, share prices and per share data have been
adjusted to give effect to a four to one reverse stock split that occurred on
September 9, 1996. See "Glossary of Terms" for definitions of certain oil and
gas terms used in this Prospectus. Investors should carefully consider the
information set forth in "Risk Factors," beginning on page 8.

THE COMPANY

GENERAL

Mallon Resources Corporation is engaged in the domestic oil and gas
development, exploration and production business. Substantially all of the
Company's estimated proved reserves are located in the San Juan and Delaware
Basins in New Mexico, where the Company has been active since 1982. The Company
has accumulated significant acreage positions in these two basins, where the
Company believes its technical and operational experience and its database of
information enable it to effectively exploit and develop its properties. Between
July 1, 1996 and November 15, 1997, the Company drilled 28 wells and recompleted
22 wells in these two basins. By September 30, 1997, the Company's estimated
proved reserves had increased 65% from 5,473 MBOE at June 30, 1996 to 9,033
MBOE. The Company's average daily production increased 50% from 1,060 BOE for
the year ended December 31, 1996, to 1,587 BOE for the three months ended
September 30, 1997. The Pre-tax SEC 10 Value of the Company's estimated proved
reserves was approximately $37.7 million at September 30, 1997. At such date, on
a BOE basis, 85% of the Company's estimated proved reserves were comprised of
natural gas. The Company currently has identified in excess of 300 potential
drilling and recompletion locations on its acreage in the San Juan and Delaware
Basins. The Company intends to drill or recomplete 59 wells in these two basins
during 1998.

BUSINESS STRATEGY

The Company's primary business strategy is to increase its proved oil and
gas reserves and its cash flows by means of its drilling and recompletion
activities in the San Juan and Delaware Basins. The principal components of this
strategy are:

- Exploration Through Exploitation. The Company's primary operating
strategy is to increase its proved reserves through relatively lower-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 and Delaware Basins, allowing the Company to (i) target multiple
potential pay zones in most wells, thus reducing drilling risks, and (ii)
conduct exploration operations in conjunction with its 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. The recent increases in the Company's
estimated proved reserves and rates of production are primarily
attributable to oil and gas fields discovered or extended by the
Company's exploration through exploitation activities.

- Control of Operations. For the nine months ended September 30, 1997,
approximately 73% of the Company's production on a BOE basis was produced
from properties operated by the Company. The Company believes that this
level of operating control, combined with the Company's operating
experience in the San Juan and Delaware Basins, allows the Company to
better control ongoing operations and costs, field development decisions,
and the timing and nature of capital expenditures.

3
<PAGE> 5

- Strategic Acquisitions. The Company also makes acquisitions of properties
located within its core areas of operations. The Company believes that
its knowledge of the San Juan and Delaware Basins allows the Company to
effectively identify and evaluate valuable acquisition opportunities.
Strategic acquisitions may include increasing the Company's ownership
interest in fields where the Company has an existing interest or
acquiring additional property interests in the San Juan and Delaware
Basins. For example, in January 1997, the Company increased its ownership
interest in, and acquired operating control of, the East Blanco Field in
the San Juan Basin, an area which has contributed significantly to the
recent increase in the Company's estimated proved reserves.

CURRENT OPERATIONS

In the San Juan Basin, the Company operates in the East Blanco, Gavilan and
Otero Fields. Since July 1997, the Company has recompleted 11 wells in the East
Blanco Field establishing what the Company believes is the San Juan Basin's
first commercial gas production from the Ojo Alamo Sandstone. Based on these
recompletion results and other geologic evaluations, the Company has identified
more than 80 Ojo Alamo drilling or recompletion locations on the Company's
acreage. The Company plans to drill 31 wells and recomplete six wells in the Ojo
Alamo during 1998. The Company also plans to drill one well in the Otero Field
during 1998. As of September 30, 1997, the Company's estimated proved reserves
in the San Juan Basin were 6,186 MBOE or approximately 68% of the Company's
total estimated proved reserves.

The Company operates in several fields in the Delaware Basin, where the
Company's late 1996 and 1997 development drilling and exploitation efforts have
led to new discoveries or field extensions in the White City, South Carlsbad,
Quail Ridge and Lea Northeast Fields. The Company has identified approximately
200 drillsites on its acreage to exploit these discoveries and field extensions.
The Company plans to drill 21 wells in the Delaware Basin during 1998. As of
September 30, 1997, the Company's estimated proved reserves in the Delaware
Basin were 2,815 MBOE, or approximately 31% of the Company's total estimated
proved reserves.

THE OFFERING

Common Stock offered by the
Company............................. 2,300,000 shares

Common Stock to be outstanding after
the offering(1)..................... 6,995,264 shares

Use of proceeds..................... To fund exploitation and development
activities and to repay indebtedness
under the Company's revolving line of
credit. The Company intends to use the
revolving line of credit to fund
exploitation and development
activities.

Nasdaq National Market symbol....... MLRC
- ---------------

(1) Does not include 832,788 shares of Common Stock issuable upon exercise of
outstanding options and warrants, or 128,517 shares of Common Stock issuable
upon conversion of the Company's outstanding Series B Mandatorily Redeemable
Convertible Preferred Stock. See "Description of Capital Stock and Other
Securities."

4
<PAGE> 6

SUMMARY FINANCIAL DATA

The following table sets forth, for the periods and at the dates indicated,
summary historical financial data of the Company. The financial data for each of
the three fiscal years ended December 31, 1994, 1995 and 1996 is derived from
the Company's audited Consolidated Financial Statements. The financial data of
the Company for the nine months ended September 30, 1996 and 1997 is derived
from the Company's unaudited interim consolidated financial statements, which,
in the opinion of management of the Company, have been prepared on the same
basis as the annual Consolidated Financial Statements and include all
adjustments (consisting of only normal recurring adjustments) necessary for a
fair presentation of the financial data for such periods. The information in
this table should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Consolidated
Financial Statements and the notes thereto included elsewhere herein. The
results for the nine month period ended September 30, 1997 are not necessarily
indicative of results for the full year.

<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------------- -------------------
1994 1995 1996 1996 1997
------- ------- ------- ------- --------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
Total Revenues.............................................. $ 4,735 $ 5,270 $ 6,366 $ 4,532 $ 5,928
Oil and gas production...................................... 2,024 1,868 2,249 1,511 2,158
Depreciation, depletion and amortization.................... 2,409 2,340 2,095 1,671 1,873
General and administrative.................................. 1,342 1,467 1,845 1,252 1,730
Interest and other.......................................... 132 433 842 702 381
Net loss.................................................... $(1,631) $(1,929) $(1,837) $(1,320) $ (717)
Weighted average shares outstanding(1)...................... 1,916 1,947 2,512 2,032 4,576
Net cash (used in) provided by operating activities......... $ (235) $(6,897) $ (359) $ 425 $ 3,040
Net cash used in investing activities....................... (2,081) (3,840) (6,523) (5,183) (10,214)
Net cash provided by financing activities................... 1,440 11,918 8,384 4,555 4,827
EBITDA(2)................................................... 876 1,093 1,520 1,209 1,595
Capital expenditures........................................ $ 2,379 $ 3,995 $ 6,339 $ 4,982 $ 12,979
</TABLE>

<TABLE>
<CAPTION>
AT SEPTEMBER 30, 1997
---------------------------
ACTUAL AS ADJUSTED(3)
------- --------------
<S> <C> <C>
BALANCE SHEET DATA, CONSOLIDATED:

Working capital (deficit)................................... $(1,732) $10,825
Total assets................................................ 48,082 60,639
Long-term debt(4)........................................... 8,971 602
Mandatorily redeemable convertible preferred stock.......... 1,314 1,314
Shareholders' equity........................................ 23,583 44,509
</TABLE>

- ---------------

(1) As adjusted for the four to one reverse stock split that occurred on
September 9, 1996.

(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 trends 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) As adjusted to reflect the receipt by the Company of estimated net proceeds
from the issuance of 2,300,000 shares of Common Stock and the application of
such proceeds. See "Use of Proceeds" and "Capitalization."

(4) Long-term debt includes long-term debt net of current maturities, notes
payable-other and capital lease and installment obligations net of current
portions.

5
<PAGE> 7

SUMMARY OIL AND GAS RESERVE DATA

The following table sets forth summary information concerning the Company's
estimated proved oil and gas reserves as of June 30 and December 31, 1996, based
upon reports prepared by GeoQuest Reservoir Technologies, Inc. ("GeoQuest"), and
as of September 30, 1997, based upon a report prepared by Ryder Scott Company
Petroleum Engineers ("Ryder Scott"). A summary of the Ryder Scott report is
included as Annex A to this Prospectus. GeoQuest and Ryder Scott are sometimes
referred to herein as the "Independent Engineers," and their reports are
sometimes referred to herein as the "Reserve Reports." All calculations have
been made in accordance with the rules and regulations of the Securities and
Exchange Commission (the "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%. See "Risk Factors -- Uncertainty of
Estimates of Reserves and Future Net Revenues."

<TABLE>
<CAPTION>
JUNE 30, 1996 DECEMBER 31, 1996(1) SEPTEMBER 30, 1997
------------- -------------------- ------------------
<S> <C> <C> <C>
PROVED RESERVES:
Oil (MBbl).................................. 1,937 1,707 1,338
Natural gas (MMcf).......................... 21,213 28,388 46,171
Total (MBOE)................................ 5,473 6,439 9,033
PROVED DEVELOPED RESERVES:
Oil (MBbl).................................. 1,272 1,225 1,007
Natural gas (MMcf).......................... 16,074 20,521 25,013
Total (MBOE)................................ 3,951 4,645 5,176
PRE-TAX SEC 10 VALUE (in thousands)......... $23,784 $49,957 $37,689
</TABLE>

- ---------------

(1) Includes reserves attributable to an acquisition that was consummated on
January 1, 1997.

SUMMARY OPERATING DATA

<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------- ----------------
1994 1995 1996 1996 1997
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
NET PRODUCTION:
Oil (MBbl)(1)........................................... 146 173 174 135 131
Natural gas (MMcf)(1)................................... 1,648 1,238 1,286 934 1,553
Total (MBOE)............................................ 421 379 388 291 390
AVERAGE SALES PRICE REALIZED(2):
Oil (per Bbl)........................................... $14.81 $16.45 $18.05 $17.21 $20.15
Natural gas (per Mcf)................................... $ 1.50 $ 1.58 $ 2.11 $ 1.90 $ 2.04
Per BOE................................................. $11.00 $12.66 $15.09 $14.08 $14.89
AVERAGE COST DATA (PER BOE):
Production tax and marketing expense.................... $ 1.29 $ 1.54 $ 1.84 $ 1.71 $ 1.89
Lease operating expense................................. $ 3.52 $ 3.39 $ 3.96 $ 3.48 $ 3.64
Depletion............................................... $ 5.53 $ 5.70 $ 4.96 $ 5.31 $ 4.35
</TABLE>

AVERAGE DAILY PRODUCTION (BOE)

<TABLE>
<S> <C>
For the year ended December 31, 1996........................ 1,060
For the three month period ended September 30, 1997......... 1,587
</TABLE>

- ---------------

(1) Includes 48 MBbl and 961 MMcf and 26 MBbl and 692 MMcf in 1994 and 1995,
respectively, delivered pursuant to the terms of a volumetric production
payment agreement.

(2) Includes effects of hedging. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Hedging Activities."
6
<PAGE> 8

RISK FACTORS

An investment in the Common Stock offered hereby involves certain risks.
Prospective investors should carefully consider the risk factors set forth under
"Risk Factors" beginning on page 8, which includes discussion of the following
matters.

- Oil and Gas Prices; Hedging

- Marketability of Production

- Geographic Concentration of Operations

- Uncertainty of Estimates of Reserves and Future Net Revenues

- Lack of Profitable Operations

- Absence of Dividends

- Working Capital Requirements

- Replacement of Reserves

- Operating Hazards; Uninsured Risks

- Regulation

- Environmental Matters

- Ownership Interest in Laguna

- Anti-Takeover Provisions

- Series B Preferred Stock -- Right to Elect Directors in Certain
Circumstances

- Reliance on Key Personnel

- Competition

7
<PAGE> 9

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Prospectus includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Prospectus, including without
limitation statements under "Prospectus Summary," "Risk Factors," "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Business and Properties" regarding planned capital expenditures, the
availability of capital resources to fund capital expenditures, estimates of
proved reserves, the number of anticipated wells to be drilled in the future,
the Company's financial position, business strategy and other plans and
objectives for future operations, are forward-looking statements. Although the
Company believes that the expectations reflected in such forward-looking
statements are reasonable, it can give no assurance that such expectations will
prove to have been correct. There are numerous uncertainties inherent in
estimating quantities of proved oil and natural gas reserves and in projecting
future rates of production and timing of development expenditures, including
many factors beyond the control of the Company. Reserve engineering is a
subjective process of estimating underground accumulations of oil and natural
gas that cannot be measured in an exact way, and the accuracy of any reserve
estimate is a function of the quality of available data and of engineering and
geological interpretation and judgment. As a result, estimates made by different
engineers often vary from one another. In addition, results of drilling, testing
and production subsequent to the date of an estimate may justify revisions of
such estimate and such revisions, if significant, would change the schedule of
any further production and development drilling. Accordingly, reserve estimates
are generally different from the quantities of oil and natural gas that are
ultimately recovered. Additional important factors that could cause actual
results to differ materially from the Company's expectations are disclosed under
"Risk Factors" and elsewhere in this Prospectus. All subsequent written and oral
forward-looking statements attributable to the Company or persons acting on its
behalf are expressly qualified in their entirety by such factors.

RISK FACTORS

AN INVESTMENT IN THE COMMON STOCK OFFERED HEREBY INVOLVES CERTAIN RISKS.
PROSPECTIVE INVESTORS SHOULD CAREFULLY CONSIDER THE RISK FACTORS SET FORTH
BELOW, AS WELL AS THE OTHER INFORMATION SET FORTH IN THIS PROSPECTUS OR
INCORPORATED HEREIN BY REFERENCE, PRIOR TO MAKING ANY INVESTMENT IN THE COMMON
STOCK.

OIL AND GAS PRICES; HEDGING

The Company's oil and gas revenues and profitability are substantially
affected by prevailing prices for oil and natural gas. Hydrocarbon prices can be
extremely volatile. In general, hydrocarbon prices are affected by numerous
factors such as economic, political and regulatory developments. 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, the Company's sales of oil and natural gas are often 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 significantly mitigate the effect of any
substantial or extended decline in oil or natural gas prices. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Hedging Activities."

MARKETABILITY OF PRODUCTION

The marketability of the Company's production depends upon the availability
and capacity of pipelines and gas gathering systems, processing facilities, 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,

8
<PAGE> 10

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
San Juan and Delaware 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 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.

GEOGRAPHIC CONCENTRATION OF OPERATIONS

Substantially all of the Company's operations are currently located in two
geologic basins 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 the Company more than if its operations were more
geographically diversified.

UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES
This Prospectus contains estimates of the Company's proved oil and gas
reserves and the estimated future net revenues therefrom based upon the Reserve
Reports prepared by the Independent Engineers that rely 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 Reserve Reports. Any significant
variance in these assumptions could materially affect the estimated quantity and
value of reserves set forth in this Prospectus. 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 43% of the Company's total proved reserves at September 30,
1997 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 Reserve Report prepared by Ryder
Scott as of September 30, 1997, assumes, based on the Company's estimates, that
aggregate capital expenditures by the Company of approximately $14.4 million
through 1999 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. See "Business and Properties -- Proved
Reserves."
The present value of future net revenues referred to in this Prospectus
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.

LACK OF PROFITABLE OPERATIONS

The Company recorded net losses for 1994, 1995, 1996 and the nine months
ended September 30, 1997 of $1,631,000, $1,929,000, $1,837,000 and $717,000,
respectively. The Company's ability to continue in business

9
<PAGE> 11

and maintain its financing arrangements would be adversely affected by a
continued lack of profitability. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations."

ABSENCE OF DIVIDENDS

The Company has never paid cash dividends on its Common Stock and does not
anticipate paying any cash dividends in the foreseeable future. In addition, the
Company's revolving line of credit contains a prohibition on the payment of cash
dividends without the bank's consent. See "Dividend Policy."

WORKING CAPITAL REQUIREMENTS

Due to its active development and exploration program, the Company has
substantial working capital requirements. The Company's current operating budget
for 1998 calls for capital expenditures of approximately $24.7 million during
the course of 1998. The actual amount expended in 1998 may vary, possibly
substantially, from the budgeted amount due to circumstances not currently
foreseeable, including changes in plans as drilling results indicate the
desirability of increases or decreases in emphasis on certain properties, new
acquisitions, and other factors. While the Company believes that the net
proceeds from this Offering and cash flow from operations should allow the
Company to successfully implement its present business strategy, some or all of
the Company's cash flow from operations may be required to service the Company's
bank debt. As a consequence, 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. Shareholders' interests may be
diluted if equity financing is used to fund the Company's working capital
requirements. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations."

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, blowouts, 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. See "Business and Properties -- Operating
Hazards and Environmental Matters."

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

10
<PAGE> 12

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. See
"Business and Properties -- Regulation."

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. For
example, a Federal court recently ruled that the Environmental Protection Agency
is required to regulate the injection of materials into existing wells to
stimulate production. 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. See "Business and Properties -- Operating Hazards and Environmental
Matters."

OWNERSHIP INTEREST IN LAGUNA

The Company owns an approximate 56% interest in Laguna, a gold mining
company whose common shares are listed on The Toronto Stock Exchange under the
trading symbol "LGC." Recent weaknesses in the gold market and the market for
junior gold mining companies have resulted in a substantial reduction in the
price of Laguna common stock on The Toronto Stock Exchange. The Company has
engaged a Canadian investment banking firm to explore strategic alternatives
relating to the Company's interest in Laguna, which may include a sale of the
Company's Laguna stock, a reorganization or merger of Laguna with a third party,
or other transaction. No assurance can be given that any such transaction will
be arranged, or as to the terms of any arrangement that may be made. In
connection with any potential disposition of the Company's interest in Laguna,
the Company may incur a loss on the recovery of its investment. Pending the
receipt of an offer to purchase Laguna, or the negotiation of the terms of a
merger or other transaction, no estimate of whether such a loss will be
incurred, or the amount of such loss, if any, can be made. Laguna has generated
no revenues

11
<PAGE> 13

from its operations in recent years. Laguna's net losses from operations have
contributed $496,000, $987,000, $733,000 and $474,000 to the Company's net
losses for the years ended 1994, 1995, 1996 and the nine months ended September
30, 1997, respectively.

The value of the Company's interest in Laguna will be affected by the
business results of Laguna and by changes in the markets for gold and junior
gold mining companies. 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 not in the United States, 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.
The Company does not have any contractual obligation to finance Laguna's future
operations and has no intention to do so. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Laguna."

ANTI-TAKEOVER PROVISIONS

In April 1997, the Company's Board of Directors adopted a Shareholder
Rights Plan (the "Rights Plan"). The Rights Plan is designed to insure that all
shareholders of the Company receive fair value for their Common Stock in the
event of any 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. While the Rights Plan
is not intended to prevent an acquisition of the Company on terms that are
favorable and fair to all shareholders, its existence may discourage potential
purchasers. The Company is not aware of any plan or intention by any person to
attempt a takeover of the Company. See "Description of Capital Stock and Other
Securities -- Shareholder Rights Plan."

The Company's Restated Articles of Incorporation impose restrictions on
changes in control of the Company. The existence of these provisions may
discourage a party from making a tender offer for or otherwise seeking to obtain
control of the Company. See "Description of Capital Stock and Other
Securities -- Certain Voting Requirements."

SERIES B PREFERRED STOCK -- RIGHT TO ELECT DIRECTORS IN CERTAIN CIRCUMSTANCES

Under the terms of the Company's Series B Preferred Stock, if the Company
has outstanding unpaid cumulative dividends on the Series B Preferred Stock for
three quarterly dividend periods, and until such cumulative dividends have been
paid in full, the holders of shares of Series B Preferred Stock, voting
separately as a class, have the right to elect two additional members to the
Company's board of directors. While any such directors would not constitute a
majority of the board of directors, it is probable that they would attempt to
influence the board of directors, as a whole, to support the satisfaction of the
claims of the holders of the Series B Preferred Stock.

RELIANCE ON KEY PERSONNEL

The Company is dependent upon its executive officers and key employees. 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. See "Management."

COMPETITION

The oil and gas industry is highly competitive. The Company competes with
major oil and gas companies, other independent concerns and individual producers
and operators. Many of these competitors have substantially greater financial
and other resources than the Company. See "Business and Properties --
Competition."

12
<PAGE> 14

USE OF PROCEEDS

The net proceeds to the Company from the sale of the shares of Common Stock
being offered hereby (based on an assumed public offering price of $9.88 per
share) are estimated to be approximately $20.9 million ($24.1 million if the
Underwriters' over-allotment option is exercised in full) after deducting
underwriting discounts and estimated offering expenses.

The Company expects that substantially all of the net proceeds of the
Offering will be used to finance the Company's oil and gas exploitation and
development activities in the San Juan and Delaware Basins of New Mexico.
Although no acquisitions are pending, a portion of the net proceeds may be used
to make strategic acquisitions of oil and gas interests in such basins.

Prior to the expenditure of the net proceeds of this Offering, a portion of
such proceeds will be used to pay down the Company's revolving line of credit
(the "Facility") with Bank One, Texas, N.A. (the "Bank"). The Company intends to
use the revolving line of credit to fund exploitation and development
activities. The amount outstanding under the Facility at November 14, 1997, was
$9,609,000. The interest rate is, at the Company's election, either the Bank's
base rate plus 0.75% (9.25% as of November 14, 1997), or the London Interbank
Offered Rate plus 2.5% (8.25% as of November 14, 1997). The Facility expires on
March 31, 1999. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Liquidity and Capital Resources." Pending
application of the net proceeds as described above, the Company will invest the
net proceeds in short-term, investment grade, interest-bearing securities.

PRICE RANGE OF COMMON STOCK

The Common Stock is quoted on the Nasdaq National 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.
The following quotations have been adjusted to reflect the four to one reverse
stock split of the Common Stock that occurred on September 9, 1996.

<TABLE>
<CAPTION>
HIGH LOW
---- ---
<S> <C> <C>
YEAR ENDED DECEMBER 31, 1995:
First Quarter............................................. $ 8 $ 5
Second Quarter............................................ 8 1/2 5 1/2
Third Quarter............................................. 10 6
Fourth Quarter............................................ 11 4
YEAR ENDED DECEMBER 31, 1996:
First Quarter............................................. $ 8 1/4 $ 5 1/2
Second Quarter............................................ 11 6
Third Quarter............................................. 8 1/2 5
Fourth Quarter............................................ 9 5/8 6 1/2
YEAR ENDING DECEMBER 31, 1997:
First Quarter............................................. $10 1/2 $ 7 1/8
Second Quarter............................................ 9 3/4 6 3/4
Third Quarter............................................. 12 3/8 7 3/8
Fourth Quarter (through November 21, 1997)................ 13 9 7/8
</TABLE>

On November 21, 1997, the closing price of the Common Stock as reported by
the Nasdaq National Market was $9 7/8. As of November 21, 1997, there were
approximately 650 shareholders of record of the Common Stock.

DIVIDEND POLICY

The Company does not intend to pay cash dividends on Common Stock in the
foreseeable future. The Company instead intends to retain any earnings to
support the growth of the Company. Any future cash dividends would depend on
future earnings, capital requirements, the Company's financial condition and
other factors deemed relevant by the Board of Directors. Under the terms of the
Facility, the Company may not pay dividends without the consent of the Bank. For
a description of the Facility, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."

13
<PAGE> 15

DILUTION

The net tangible book value per share of the Common Stock at September 30,
1997 was $5.02. Giving effect to the sale of the Common Stock offered hereby
(assuming no exercise of the Underwriters' over-allotment option), and after
deducting the aggregate underwriting discount and estimated Offering expenses,
the pro forma net tangible book value per common share would have been $6.37.
This represents an immediate increase in net tangible book value of $1.35 per
common share to the existing investors and an immediate dilution of $3.51 per
common share to purchasers of shares in this Offering. The average price paid by
the existing investors for each of the approximately 4,695,000 shares of Common
Stock outstanding on September 30, 1997 (excluding shares of Common Stock
reserved for issuance upon the exercise of outstanding options and warrants) was
$12.39. The following table illustrates the dilution per share to purchasers of
shares in this Offering:

<TABLE>
<S> <C> <C>
Public offering price per share of Common Stock(1).......... $9.88
Net tangible book value per share of Common Stock before
the
Offering(2)............................................ $5.02
Increase attributable to new investors(3)................. 1.35
-----
Pro forma net tangible book value per share of Common Stock
after the Offering........................................ 6.37
-----
Dilution of net tangible book value per share to new
investors(4).............................................. $3.51
=====
</TABLE>

- ---------------

(1) Before deduction of the underwriting discount and estimated Offering
expenses.

(2) Net tangible book value per share of Common Stock, without considering the
purchase of shares of Common Stock by new investors, is equal to total
tangible assets of the Company less total liabilities divided by the number
of shares of Common Stock outstanding at September 30, 1997.

(3) After deduction of the aggregate underwriting discount and estimated
Offering expenses paid by the Company.

(4) Dilution is determined by subtracting pro forma net tangible book value per
share of Common Stock after the Offering from the public offering price paid
by new investors for a share of Common Stock.

14
<PAGE> 16

CAPITALIZATION

The following table sets forth the consolidated capitalization of the
Company as of September 30, 1997, and as adjusted (i) to reflect the sale of
2,300,000 shares of Common Stock offered hereby and (ii) the application of the
estimated net proceeds to the Company therefrom, as described under "Use of
Proceeds." The following table should be read in conjunction with the
Consolidated Financial Statements of the Company and the related notes and other
financial information included elsewhere in this Prospectus.

<TABLE>
<CAPTION>
AT SEPTEMBER 30, 1997
-----------------------
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
Long-term debt(1)........................................... $ 8,971 $ 602
Series B Mandatorily Redeemable Convertible Preferred Stock,
$0.01 par value, 500,000 shares authorized, 135,200 shares
issued and outstanding, liquidation preference and
mandatory redemption of $1,352,000........................ 1,314 1,314
Shareholders' equity:
Common Stock, $0.01 par value, 25,000,000 shares
authorized; 4,695,264 shares issued and outstanding and
6,995,264 shares as adjusted(2)........................ 47 70
Additional paid-in capital................................ 59,121 80,024
Accumulated deficit....................................... (35,585) (35,585)
-------- --------
Total shareholders' equity........................ 23,583 44,509
-------- --------
Total capitalization.............................. $ 33,868 $ 46,425
======== ========
</TABLE>

- ---------------

(1) Long-term debt includes long-term debt net of current maturities, notes
payable-other and capital lease and installment obligations net of current
portions.

(2) Does not include 832,788 shares of Common Stock issuable upon exercise of
outstanding options and warrants, or 128,517 shares of Common Stock issuable
upon conversion of the Company's outstanding Series B Mandatorily Redeemable
Convertible Preferred Stock. See "Description of Capital Stock and Other
Securities."

15
<PAGE> 17

SELECTED CONSOLIDATED FINANCIAL DATA

The following table sets forth, for the periods and at the dates indicated,
selected historical financial data of the Company. The financial data for each
of the five fiscal years ended December 31, 1992, 1993, 1994, 1995 and 1996 is
derived from the Company's audited Consolidated Financial Statements. The
financial data of the Company for the nine months ended September 30, 1996 and
1997 is derived from the Company's unaudited interim consolidated financial
statements, which, in the opinion of management of the Company, have been
prepared on the same basis as the annual Consolidated Financial Statements and
include all adjustments (consisting of only normal recurring adjustments)
necessary for a fair presentation of the financial data for such periods. The
information in this table should be read in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements and the notes thereto included elsewhere
herein. The results for the nine month period ended September 30, 1997 are not
necessarily indicative of results for the full year.

<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------------------------- -----------------
1992 1993 1994 1995 1996 1996 1997
------ ------- ------- ------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
(In thousands, except per share
data)
STATEMENTS OF OPERATIONS DATA:
Revenues:
Oil and gas sales................ $1,408 $ 2,061 $ 4,629 $ 4,800 $ 5,854 $ 4,098 $ 5,806
Other............................ 423 129 106 470 512 434 122
------ ------- ------- ------- ------- ------- -------
1,831 2,190 4,735 5,270 6,366 4,532 5,928
------ ------- ------- ------- ------- ------- -------
Costs and expenses:
Oil and gas production........... 800 976 2,024 1,868 2,249 1,511 2,158
Mining project expenses.......... 380 390 459 838 1,014 648 871
Depreciation, depletion and
amortization................... 306 937 2,409 2,340 2,095 1,671 1,873
Impairment of oil and gas
properties..................... -- -- -- -- 264 -- 59
General and administrative....... 537 825 1,342 1,467 1,845 1,252 1,730
Interest and other............... 76 249 132 433 842 702 381
------ ------- ------- ------- ------- ------- -------
2,099 3,377 6,366 6,946 8,309 5,784 7,072
------ ------- ------- ------- ------- ------- -------
Minority interest in loss of
consolidated subsidiary.......... -- -- -- -- 266 92 427
------ ------- ------- ------- ------- ------- -------
Loss before extraordinary item..... (268) (1,187) (1,631) (1,676) (1,677) (1,160) (717)
Extraordinary loss on early
retirement of debt............... -- -- -- (253) (160) (160) --
------ ------- ------- ------- ------- ------- -------
Net loss........................... (268) (1,187) (1,631) (1,929) (1,837) (1,320) (717)
Dividends on preferred stock and
accretion........................ -- -- (258) (360) (376) (281) (155)
Gain on redemption of preferred
stock............................ -- -- -- -- 3,743 -- --
Preferred stock conversion
inducement....................... -- -- -- -- -- -- (403)
------ ------- ------- ------- ------- ------- -------
Net income (loss) attributable to
common shareholders.............. $ (268) $(1,187) $(1,889) $(2,289) $ 1,530(1) $(1,601) $(1,275)
====== ======= ======= ======= ======= ======= =======
PER SHARE DATA(2):
Loss attributable to common
shareholders before extraordinary
item............................. $(0.22) $ (0.87) $ (0.99) $ (1.05) $ (0.82) $ (0.71) $ (0.28)
Extraordinary loss................. -- -- -- (0.13) (0.06) (0.08) --
------ ------- ------- ------- ------- ------- -------
Net loss attributable to common
shareholders..................... $(0.22) $ (0.87) $ (0.99) $ (1.18) $ (0.88)(1) $ (0.79) $ (0.28)
====== ======= ======= ======= ======= ======= =======
Weighted average shares
outstanding...................... 1,195 1,368 1,916 1,947 2,512 2,032 4,576
OTHER DATA:
Capital expenditures............... $ 190 $20,612 $ 2,379 $ 3,995 $ 6,339 $ 4,982 $12,979
</TABLE>

16
<PAGE> 18

<TABLE>
<CAPTION>
AT DECEMBER 31,
----------------------------------------------
1992 1993 1994 1995 1996 AT SEPTEMBER 30, 1997
------ ------- ------- ------- ------- ---------------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital (deficit)........ $ (67) $ 462 $(1,764) $ (476) $ 5,365 $(1,732)
Total assets..................... 7,675 28,773 28,226 31,635 41,400 48,082
Long-term debt(3)................ 30 20 -- 10,037 3,511 8,971
Mandatorily redeemable preferred
stock.......................... -- -- 3,804 3,844 3,900 1,314
Shareholders' equity............. 6,738 15,029 13,549 11,760 21,904 23,583
</TABLE>

- ---------------

(1) The gain on the redemption of the Series A Convertible Preferred Stock (the
"Series A Stock") in the fourth quarter of 1996 resulted in net income
attributable to common shareholders for the year ended December 31, 1996 of
$1,530,000. However, because the Series A Stock is reflected as if
converted, the gain on redemption is deducted from net income attributable
to common shareholders for purposes of calculating per share data, resulting
in a net loss attributable to common shareholders for the year ended
December 31, 1996 of $2,213,000 or $0.88 per share.

(2) As adjusted for the four to one reverse stock split that occurred on
September 9, 1996.

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

17
<PAGE> 19

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, 1994, 1995
and 1996, and at September 30, 1997, and results of operations and cash flows
for each of the years ended December 31, 1994, 1995 and 1996 and the unaudited
nine month periods ended September 30, 1996 and 1997. The Company's historical
Consolidated Financial Statements and notes thereto included elsewhere in this
Prospectus 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

The Company's revenues, profitability and future rate of growth will be
substantially dependent upon its drilling success in the San Juan and Delaware
Basins, and prevailing prices for oil and gas, which are in turn dependent upon
numerous factors that are beyond 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 Common Stock in a
public offering. The Company received proceeds of approximately $13,189,000.
Approximately $1,987,000 of the net proceeds were used to purchase and retire
all outstanding shares of the Company's Series A Convertible Preferred Stock.
The Company had a working capital surplus of $5,365,000 at December 31, 1996,
compared to working capital deficits of $1,732,000 and $476,000 at September 30,
1997, and December 31, 1995, respectively. The increase in working capital at
December 31, 1996 was primarily due to higher cash balances as a result of the
equity offerings by the Company and Laguna in 1996. Over the course of the first
nine months of 1997, the Company's working capital decreased due to the
Company's expenditures to develop and exploit its oil and gas properties and
Laguna's depletion of its working capital. See "-- Laguna."

In March 1996, the Company established a revolving line of credit (the
"Facility") with Bank One, Texas, N.A. (the "Bank"). The borrowing base under
the Facility is subject to redetermination every six months, or at such other
times as the Bank may determine, and is currently $10,830,000. 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 secured by substantially all of the Company's oil and
gas properties. The Facility expires March 31, 1999. At November 14, 1997, the
principal amount outstanding under the Facility was $9,609,000, leaving
$1,221,000 available under the Facility. The Company will repay the amount
outstanding under the Facility with a portion of the proceeds of this Offering.
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.

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, or 80,000 shares, were to be redeemed for
$800,000. The Company extended an offer to all holders of the Series B Stock to
convert their shares into shares of Common Stock at a conversion price of $9.00,
rather than the $11.31 conversion price otherwise then in effect. The market
price of a share of the Common Stock during the term of the offer ranged from
$7.88 to $8.50. Holders of 252,675 shares of Series B Stock elected to convert
their shares into 280,747 shares of Common Stock. In addition, the Company
redeemed 12,125 shares of Series B Stock at $10.00 per share. After these
transactions, 135,200 shares of Series B Stock remain outstanding and the
Company has no further obligation to redeem any shares until April 2000, when it
will be required to redeem all Series B Stock outstanding in excess of 80,000
shares. The Series B Stock is convertible to Common Stock

18
<PAGE> 20

automatically if the Common Stock trades at a price in excess of 140% of the
then applicable conversion price for each day in a period of 10 consecutive
trading days. The conversion price, as adjusted to reflect this Offering, is
currently $10.52. See "Description of Capital Stock and Other
Securities -- Series B Mandatorily Redeemable Preferred Stock."

Capital expenditures related to the Company's drilling and development
programs totaled $2,462,000 in 1996 and $10,280,000 during the first nine months
of 1997. The Company expects to spend approximately $14,000,000 for drilling and
development in all of 1997. The Company's current budget for drilling and
development capital expenditures in 1998 is approximately $24,700,000. During
fiscal 1996, the Company completed two of the three wells drilled and
recompleted one well. During the first nine months of 1997, the Company
completed 18 of the 20 development wells it drilled. The Company recompleted 13
wells during the first nine months of 1997, all of which are on production. In
addition, the Company completed a gas sweetening plant in the East Blanco Field,
which will allow acceleration of the Company's Ojo Alamo recompletion program.
The Company expects to drill a total of 31 wells and recomplete 26 wells in all
of 1997. The Company currently plans to drill 53 wells and recomplete six wells
in 1998.

The Company believes that, with the net proceeds of this Offering,
borrowings available under the Facility, and the operating cash flows that are
expected to be generated by the application of such funds to the Company's
drilling program, the Company will have sufficient capital to fund the continued
development of its current properties and to meet the Company's liquidity
requirements through 1998.

RESULTS OF OPERATIONS

<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------ ---------------
1994 1995 1996 1996 1997
------ ------ ------ ------ ------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
OPERATING RESULTS FROM OIL AND GAS OPERATIONS:
Oil and gas revenues........................................ $4,629 $4,800 $5,854 $4,098 $5,806
Production tax and marketing expense........................ 542 582 715 499 739
Lease operating expense..................................... 1,482 1,286 1,534 1,012 1,419
Depletion................................................... 2,330 2,162 1,924 1,546 1,698
NET PRODUCTION:
Oil (MBbl)(1)............................................... 146 173 174 135 131
Natural gas (MMcf)(1)....................................... 1,648 1,238 1,286 934 1,553
Total (MBOE)................................................ 421 379 388 291 390
AVERAGE SALES PRICE REALIZED(2):
Oil (per Bbl)............................................... $14.81 $16.45 $18.05 $17.21 $20.15
Natural gas (per Mcf)....................................... $ 1.50 $ 1.58 $ 2.11 $ 1.90 $ 2.04
Per BOE..................................................... $11.00 $12.66 $15.09 $14.08 $14.89
AVERAGE COST DATA (PER BOE):
Production tax and marketing expense........................ $ 1.29 $ 1.54 $ 1.84 $ 1.71 $ 1.89
Lease operating expense..................................... $ 3.52 $ 3.39 $ 3.96 $ 3.48 $ 3.64
Depletion................................................... $ 5.53 $ 5.70 $ 4.96 $ 5.31 $ 4.35
</TABLE>

- ---------------

(1) Includes 48 MBbl and 961 MMcf and 26 MBbl and 692 MMcf in 1994 and 1995,
respectively, delivered pursuant to the terms of a volumetric production
payment agreement.

(2) Includes effects of hedging. See "-- Hedging Activities."

Nine Months Ended September 30, 1997 Compared with the Nine Months Ended
September 30, 1996

Revenues. Total revenues increased 31% to $5,928,000 for the nine months
ended September 30, 1997, from $4,532,000 for the nine months ended September
30, 1996. Oil and gas sales increased 42% to $5,806,000 for the nine months
ended September 30, 1997, from $4,098,000 for the nine months ended September
30, 1996, due to higher oil and gas prices realized and higher gas production in
the 1997 period. Average oil prices realized per barrel increased 17% to $20.15
for the nine months ended September 30, 1997, from $17.21 for the comparable
1996 period, and average gas prices realized per Mcf increased 7% to $2.04 in

19
<PAGE> 21

the 1997 period from $1.90 for the nine months ended September 30, 1996. Oil
production decreased 3%, to 131,000 barrels for the nine months ended September
30, 1997 from 135,000 barrels for the nine months ended September 30, 1996;
however, gas production increased 66% to 1,553,000 Mcf for the nine months ended
September 30, 1997 from 934,000 Mcf for the same period a year ago. Oil
production was constrained by a delay in planned drilling during the first five
months of fiscal 1997 while additional land acquisitions were made. However, the
normal production declines for the nine months ended September 30, 1997 were
mostly offset by new production. The gas production increases are due to the
Company's successful drilling and recompletion program in 1997. During the nine
months ended September 30, 1996, the Company sold 400,000 of its shares of
Laguna common stock and realized a gain of $329,000.

Oil and Gas Production Expenses. Oil and gas production expenses, including
production tax and marketing expenses, increased 43% to $2,158,000 for the nine
months ended September 30, 1997 from $1,511,000 for the comparable 1996 period,
due to new wells coming on line as a result of the 1997 drilling program. Oil
and gas production expenses per BOE increased $0.34, or 7%, to $5.53 for the
nine months ended September 30, 1997 from $5.19 for the nine months ended
September 30, 1996. Production tax and marketing expense increased $0.18 per
BOE, or 11%, during the nine months ended September 30, 1997 as a result of
higher oil and gas prices. Lease operating expense increased $0.16 per BOE, or
5%, during the nine months ended September 30, 1997 primarily as a result of
non-recurring repair and maintenance costs totaling approximately $416,000, or
$1.07 per BOE, during the nine months ended September 30, 1997, compared to
non-recurring repair and maintenance costs of $194,000, or $0.67 per BOE, for
the comparable period in 1996. Of the non-recurring repair and maintenance costs
incurred during the nine months ended September 30, 1997, approximately
$151,000, or $0.39 per BOE, related to remediation expenses. The remediation was
essentially completed in the third quarter of 1997. No remediation expenses were
incurred in the 1996 period.

Mining Project Expenses. Mining project expenses increased 34% to $871,000
for the nine months ended September 30, 1997 from $648,000 for the comparable
1996 period. In June 1997, pending an improvement in the financial markets,
Laguna started a program to conserve capital by curtailing its mining operations
in Costa Rica, and reducing its work force. Under Costa Rican Labor Law, Laguna
is obligated to make certain payments to Costa Rican employees who are
dismissed. The Company has estimated this amount at $134,000, and has included
it in mining project expenses for the nine months ended September 30, 1997.
Additionally, mining project expenses were higher during the nine months ended
September 30, 1997 compared to the same period in 1996 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 increased 12% to $1,873,000 for the nine months ended September 30,
1997 from $1,671,000 for the nine months ended September 30, 1996. Depletion per
BOE decreased 18% to $4.35 for the nine months ended September 30, 1997 from
$5.31 for the nine months ended September 30, 1996, primarily due to an increase
in proved reserves.

Impairment of Oil and Gas Properties. Impairment of oil and gas properties
was $59,000 for the nine months ended September 30, 1997 compared to $-0- for
the nine months ended September 30, 1996. In 1996, the Company acquired a 2.25%
working interest in an exploration venture to drill one or more wells offshore
Belize. The joint venture drilled a dry hole during the first quarter of 1997.
Accordingly, the Company reduced the carrying amount of its capitalized costs.
During the nine months ended September 30, 1996, the Company's oil and gas
activities were conducted entirely in the United States.

General and Administrative Expenses. Total general and administrative
expenses increased 38% to $1,730,000 for the nine months ended September 30,
1997 from $1,252,000 for the same period in 1996, due to the hiring of
additional personnel because of expanded operations and less sharing of expenses
with Laguna now that Laguna is operating independently. During the first nine
months of 1997, the Company capitalized $253,000 of general and administrative
expenses directly related to its drilling program. No such costs were
capitalized during fiscal 1996. Laguna's general and administrative expenses are
included in mining project expenses on the consolidated statements of
operations.

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<PAGE> 22

Interest and Other Expenses. Interest and other expenses decreased 46% to
$381,000 for the nine months ended September 30, 1997 from $702,000 for the nine
months ended September 30, 1996. The decrease was primarily due to lower
outstanding borrowings under the Company's credit facility in the 1997 period.

Minority Interest. Minority interest in loss of consolidated subsidiary
represents the minority interest share in the Laguna loss and increased to
$427,000 in the nine months ended September 30, 1997 from $92,000 for the same
period in 1996 primarily due to increases in the minority interest in Laguna
beginning in June 1996, but not fully reflected until 1997.

Income Taxes. The Company incurred net operating losses ("NOLs") for U.S.
Federal income tax purposes in 1997 and 1996, 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 the consolidated statements of operations for the nine months ended
September 30, 1997 and 1996.

Extraordinary Loss. The Company incurred an extraordinary loss of $160,000
during the nine months ended September 30, 1996, as a result of the refinancing
of its credit facility with a new lender.

Net Loss. Net loss decreased 46% to $717,000 for the nine months ended
September 30, 1997 from $1,320,000 for the same period a year ago, as a result
of the factors discussed above. The Company paid dividends of $134,000 and
realized accretion of $21,000 during the nine months ended September 30, 1997
compared to dividends of $240,000 and accretion of $41,000 during the nine
months ended September 30, 1996. Beginning in April 1997, preferred dividend
payments were reduced as a result of the conversion into common stock and
redemption of Series B Preferred Stock, as discussed in Note 4 of the
Consolidated Financial Statements. The excess of the fair value of the common
stock issued at the $9.00 conversion price over the fair value of the common
stock that would have been issued at the $11.31 conversion price, totaling
$403,000, has been reflected on the statements of operations for the nine months
ended September 30, 1997 as an increase to the net loss attributable to common
shareholders. Net loss attributable to common shareholders decreased 20% to
$1,275,000 for the nine months ended September 30, 1997 from $1,601,000 for the
nine months ended September 30, 1996.

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

Revenues. Total revenues for the year ended December 31, 1996 increased 21%
to $6,366,000 from $5,270,000 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

21
<PAGE> 23

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 26% to $1,845,000 from $1,467,000
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
income attributable to common shareholders for the year ended December 31, 1996
was $1,530,000 compared to a net loss of $2,289,000 for the year ended December
31, 1995. This increase was the result of a $3,743,000 gain on the redemption of
the Series A Convertible Preferred Stock in October 1996.

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 $5,270,000 from $4,735,000 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

22
<PAGE> 24

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 9% to $1,467,000 from $1,342,000
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% to $2,289,000 from $1,889,000 for the year ended December 31,
1994.

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<PAGE> 25

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.

The Company recognized hedging gains (losses) of ($490,000), $34,000 and
$43,000 for the years ended December 31, 1996, 1995 and 1994, respectively, and
recognized hedging losses of $217,000 and $401,000 for the nine months ended
September 30, 1997 and 1996, respectively. These gains (losses) are included in
oil and gas sales in the Company's consolidated statements of operations.

At September 30, 1997, the Company had outstanding swap agreements covering
9,000 barrels of oil per month for the period from October 1997 to December 1997
at fixed prices ranging from $19.99 to $20.39; 90,000 Mmbtu of gas per month for
the period from October 1997 to December 1997 at fixed prices ranging from $1.50
to $1.79; and 90,000 Mmbtu of gas per month at fixed prices ranging from $1.77
to $2.44 for the period from October 1997 to August 1998. The Company will
receive the difference between the fixed price per unit of production and a
price based on an agreed upon third party index if the index price is lower. If
the index price is higher, the Company will pay the difference. The Company's
current swaps are settled monthly.

LAGUNA

In 1996, Laguna completed a financing in Canada, resulting in net proceeds
of $4,339,000. This financing was intended to allow Laguna to go forward without
additional financing from the Company.

The Company has engaged a Canadian investment banking firm to explore
strategic alternatives relating to the Company's interest in Laguna, which may
include a sale of the Company's Laguna stock, a reorganization or merger of
Laguna with a third party, or other transaction. No assurance can be given that
any such transaction will be arranged, or as to the terms of any arrangement
that may be made. In connection with any potential disposition of the Company's
interest in Laguna, the Company may incur a loss on the recovery of its
investment. Pending the receipt of an offer to purchase Laguna, or the
negotiation of the terms of a merger or other transaction, no estimate of
whether such a loss will be incurred, or the amount of such loss, if any, can be
made. Should a transaction be completed that would reduce the Company's
investment in Laguna below a 50% interest, the Company would deconsolidate the
financial position and results of operations of Laguna and would record its
investment in Laguna using the equity method of accounting.

CHANGE OF INDEPENDENT ACCOUNTANTS

In July 1997, the Company solicited bids for audit work on its financial
statements for the next three years. As a result of that process, the Audit
Committee of the Company's Board of Directors selected Arthur Andersen LLP as
its independent certified public accounting firm for such period. There were no
disagreements with the Company's prior accounting firm, Price Waterhouse LLP, on
any matter of accounting principles or practices, financial statement
disclosure, or auditing scope or procedure, and Price Waterhouse LLP's reports
did not contain any adverse or qualified opinions during such accounting firm's
engagement. The Company had no prior business dealings or consultations with
Arthur Andersen LLP.

24
<PAGE> 26

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.

25
<PAGE> 27

BUSINESS AND PROPERTIES

GENERAL

BUSINESS STRATEGY

CURRENT OPERATIONS

In the San Juan Basin, the Company operates in the East Blanco, Gavilan and
Otero Fields. Since July 1997, the Company has recompleted five wells in the
East Blanco Field establishing what the Company believes is the San Juan Basin's
first commercial gas production from the Ojo Alamo Sandstone. Based on

26
<PAGE> 28

these recompletion results and other geologic evaluations, the Company has
identified more than 80 Ojo Alamo drilling or recompletion locations on the
Company's acreage. The Company plans to drill 31 wells and recomplete six wells
in the Ojo Alamo during 1998. The Company also plans to drill one well in the
Otero Field during 1998. As of September 30, 1997, the Company's estimated
proved reserves in the San Juan Basin were 6,186 MBOE or approximately 68% of
the Company's total estimated proved reserves.

SELECTED FIELDS AND AREAS OF INTEREST

San Juan Basin, Northwestern New Mexico

The Company has been active in the San Juan Basin since 1984, where its
primary areas of interest are the East Blanco, Gavilan and Otero areas. At
September 30, 1997, the Company owned interests in approximately 35,400 gross
(23,100 net) acres of oil and gas leases in the San Juan Basin. Wells on these
leases produce from a variety of zones in the Ojo Alamo, Pictured Cliffs,
Mesaverde, Mancos and Dakota formations. The Company has budgeted capital
expenditures of approximately $14.1 million in the San Juan Basin for 1998. The
actual amount expended in 1998 may vary, possibly substantially, from the
budgeted amount due to circumstances not currently foreseeable, including
changes in plans as drilling results indicate the desirability of increases or
decreases in emphasis on certain properties, new acquisitions, and other
factors.

East Blanco Area, Rio Arriba County, New Mexico. This area has been under
development by the Company since 1986. In a transaction completed in January
1997, the Company increased its ownership interest in this area to an average
80% working interest in a 23,400 acre block and became operator of the acreage.
All production in the area has been natural gas. East Blanco wells typically
contain reserves in more than one productive zone, primarily in the Pictured
Cliffs Sandstone at approximately 4,000 feet and the Ojo Alamo Sandstone at
approximately 3,200 feet. The wells also penetrate the Fruitland Coal Formation,
at approximately 3,800 feet, which is productive in fields adjacent to East
Blanco. During 1997, the Company recompleted 11 gas producing wells in the Ojo
Alamo Sandstone. The Company has identified approximately 100 potential drilling
and recompletion locations on its East Blanco acreage. In 1998, the Company
plans to drill or recomplete 37 wells in the Ojo Alamo, several of which will be
drilled deeper to explore the Pictured Cliffs Sandstone, Fruitland Coal and
Mesaverde Group. As of September 30, 1997, the Company's estimated proved
reserves in the East Blanco Area were 6,088 MBOE, or approximately 67% of the
Company's total estimated proved reserves. At November 21, 1997, the Company's
East Blanco Field Ojo Alamo interests were producing approximately 9.5 million
cubic feet of gas per day from a total of eight wells. Four additional wells
were completed, but were not on production due to gas sweetening plant capacity
limitations. The Company is in the process of increasing the processing capacity
of the gas sweetening plant to 24 million cubic feet per day. That work is
scheduled to be completed in March 1998.

Gavilan Field, Rio Arriba County, New Mexico. The Company owns and operates
seven wells on approximately 1,200 gross (1,150 net) acres in this field, with
an average 34% working interest. Current production is primarily natural gas
from the Mancos Shale at approximately 6,900 feet and from the Menefee

27
<PAGE> 29

Formation at approximately 5,400 feet. In 1997, the Company re-entered one well
and established gas production from the Pictured Cliffs Sandstone.

Otero Field, Rio Arriba County, New Mexico. The Company owns and operates
three wells on approximately 4,500 gross (3,900 net) acres in this field, with
an average 90% working interest. The wells produce oil from the Mancos Shale at
approximately 4,700 feet. In 1997, the Company drilled and completed an oil well
in a 700 feet-thick interval in the Mancos Shale, and plans to drill one well in
this field in 1998, which will commingle production from the Pictured Cliffs,
Mesaverde, and Mancos.

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, Bone Spring Limestone, Strawn and
Morrow Formations. These formations each contain multiple potentially productive
zones. The Cherry Canyon and Brushy Canyon Formations and the Bone Spring
Limestone primarily produce oil at shallow to medium drilling depths, while the
deeper Strawn and Morrow generally produce natural gas. The Company's primary
properties in the Delaware Basin are in the White City, Black River, South
Carlsbad, Lea Northeast, and Quail Ridge 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 (19,200 net) acres of
oil and gas leases in the Delaware Basin. The Company has budgeted capital
expenditures of approximately $10.6 million in the Delaware Basin for 1998. The
actual amount expended in 1998 may vary, possibly substantially, from the
budgeted amount due to circumstances not currently foreseeable, including
changes in plans as drilling results indicate the desirability of increases or
decreases in emphasis on certain properties, new acquisitions, and other
factors.

White City, Black River, and South Carlsbad Fields, Eddy County, New
Mexico. The Company owns and operates a total of approximately 11,600 gross
(4,400 net) acres in these fields, with an average working interest of 34%.
These adjacent fields have been the focus of much of the Company's recompletion
and development activities since 1993. In 1997, the Company initiated a
multiple-well drilling program to evaluate the shallow Cherry Canyon and Brushy
Canyon Formations, which contain multiple potential zones between 2,500 and
5,300 feet. During 1997, the Company has drilled or recompleted nine wells in
the program resulting in the discovery of new widespread oil accumulations
within the multiple zones in the Cherry Canyon and Brushy Canyon Formations.
Evaluation and exploitation of these oil accumulations will proceed in 1998 with
the drilling of eight wells. The Company also continues its Morrow exploitation
program, which began in 1996. A new Morrow well is currently being drilled to a
depth of 11,850 feet. While drilling, this well tested gas from a Wolfcamp zone
at 9,430 feet and from the uppermost zone in the Morrow Formation at a depth of
11,120 feet. An additional Morrow well is planned for 1998, which will also
explore for the various up-hole zones with oil and gas potential in the Cherry
Canyon, Brushy Canyon, Wolfcamp, Canyon, Strawn and Atoka Formations. As of
September 30, 1997, the Company's estimated proved reserves in these three
fields were 871 MBOE, or approximately 10% of the Company's total estimated
proved reserves.

Lea Northeast Field, Lea County, New Mexico. The Company owns and operates
approximately 2,400 gross (1,400 net) acres in this field, with an average
working interest of approximately 64%. The Company continues its active drilling
program to develop the Cherry Canyon play in this field which was begun in 1994.
Additional deeper oil zones were targeted in this program for drilling in 1997,
and during 1997 nine wells have been drilled or recompleted to exploit and
explore oil zones in the Cherry Canyon, Brushy Canyon and Bone Spring. This
drilling resulted in further extending the productive limits of the Cherry
Canyon between 5,700 and 6,000 feet, extending the productive limits of the Bone
Spring at 10,150 feet, as well as the discovery of a new Bone Spring oil
accumulation at 9,700 feet. This drilling also identified oil potential in a new
Brushy Canyon zone at 7,300 feet. For 1998, the Company has planned six wells to
continue the exploitation and exploration of these multiple zones throughout the
Lea Northeast Field and into adjacent Company acreage. The Company intends to
drill additional wells in Lea Northeast during 1997 and has delineated 30
additional drill locations in the field. As of September 30, 1997, the Company's
estimated proved reserves in Lea Northeast Field were 644 MBOE or approximately
7% of the Company's total estimated proved reserves.

28
<PAGE> 30

Quail Ridge, Lea County, New Mexico. Adjacent to Lea Northeast, the
Company controls an approximate 3,200 gross (1,300 net) acre block on which it
operates wells producing from the Bone Spring and Morrow. The Quail Ridge Field
has primarily produced gas from the Morrow at depths of approximately 13,500
feet. The Company currently has an interest in 11 wells in this area and
operates six of them. During 1997, the Company drilled four wells here,
including a successful 13,700 foot well to the Morrow, which has extended the
productive limits of the Morrow in the Quail Ridge Field. In addition, this well
tested oil from the Strawn while drilling at 12,220 feet, and identified
multiple potential oil zones in the Cherry Canyon and Brushy Canyon Formations.
For 1998, the Company has planned six wells to continue the exploration and
exploitation of oil and gas in the Cherry Canyon, Brushy Canyon, Bone Spring,
Strawn and Morrow. The Company controls an approximate 36% working interest in
this acreage.

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 21 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 36% in Lovington
Northeast and 53% 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 64%. In 1997, the Company
drilled and completed one Cherry Canyon development well in the Brushy Draw
Field.

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,
the Company has properties in the states of Colorado, Oklahoma, Wyoming, North
Dakota and Alabama. While the Company intends to continue to produce its
existing wells in those states, it currently does not expect to engage in any
development activities in those areas.

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 September 30, 1997.

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
---------------- ----------------
AREA GROSS NET GROSS NET
---- ------ ------ ------ ------
<S> <C> <C> <C> <C>
San Juan Basin........................................... 10,948 4,623 24,452 18,477
Delaware Basin........................................... 23,002 18,975 1,560 312
Other.................................................... 10,225 3,953 2,931 50
------ ------ ------ ------
Total........................................... 44,175 27,551 28,943 18,839
====== ====== ====== ======
</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.

29
<PAGE> 31

PROVED RESERVES

The following table sets forth summary information concerning the Company's
estimated proved oil and gas reserves as of June 30, 1996 and December 31, 1996,
based upon reports prepared by GeoQuest and September 30, 1997, based upon a
report prepared by Ryder Scott. All calculations have been made in accordance
with the rules and regulations of the 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%. See "Risk
Factors -- Uncertainty of Estimates of Reserves and Future Net Revenues."

- ---------------

(1) Includes reserves attributable to an acquisition that was consummated on
January 1, 1997.

DRILLING ACTIVITY

The following table sets forth, for each of the last three years and for
the nine months ended September 30, 1997, the development drilling activities
conducted by the Company:

<TABLE>
<CAPTION>
WELLS
----------------------------------------------------
GROSS WELLS NET WELLS
------------------------ -------------------------
PRODUCTIVE DRY TOTAL PRODUCTIVE DRY TOTAL
---------- --- ----- ---------- ---- -----
<S> <C> <C> <C> <C> <C> <C>
1994....................................... 4 0 4 1.75 0 1.75
1995(1).................................... 8 1 9 4.94 0.68 5.62
1996....................................... 4 1 5 2.69 0.34 3.03
Nine months ended September 30, 1997(2).... 17 4 21 10.36 1.20 11.56
</TABLE>

- ---------------

(1) Includes one gross (0.3 net) productive exploratory well.
(2) Includes one gross (.025 net) dry exploratory well.

PRODUCTIVE WELLS

The following table summarizes the Company's gross and net interests in
productive wells at September 30, 1997. 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 37 41 3.15 27.96 31.10
Delaware Basin.............................. 114 65 179 44.64 14.56 59.21
Other....................................... 15 8 23 1.60 0.64 2.24
Total.............................. 133 110 243 49.39 43.16 92.55
</TABLE>

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

30
<PAGE> 32

PRODUCTION AND SALES

The following table sets forth information concerning the Company's total
oil and gas production and sales for each of the last three fiscal years and for
the nine months ended September 30, 1996 and 1997.

<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED ENDED
DECEMBER 31, SEPTEMBER 30,
------------------------ ---------------
1994 1995 1996 1996 1997
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
NET PRODUCTION:
Oil (MBbl)(1)........................................... 146 173 174 135 131
Natural gas (MMcf)(1)................................... 1,648 1,238 1,286 934 1,553
Total (MBOE)............................................ 421 379 388 291 390
AVERAGE SALES PRICE REALIZED(2):
Oil (per Bbl)........................................... $14.81 $16.45 $18.05 $17.21 $20.15
Natural gas (per Mcf)................................... $ 1.50 $ 1.58 $ 2.11 $ 1.90 $ 2.04
Per BOE................................................. $11.00 $12.66 $15.09 $14.08 $14.89
AVERAGE COST (PER BOE):
Production tax and marketing expense.................... $ 1.29 $ 1.54 $ 1.84 $ 1.71 $ 1.89
Lease operating expense................................. $ 3.52 $ 3.39 $ 3.96 $ 3.48 $ 3.64
Depletion............................................... $ 5.53 $ 5.70 $ 4.96 $ 5.31 $ 4.35
</TABLE>

- ---------------

(1) Includes 48 MBbl and 961 MMcf and 26 MBbl and 692 MMcf in 1994 and 1995,
respectively, delivered pursuant to the terms of a volumetric production
payment agreement.

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

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.

COMPETITION

The oil and natural gas industry is intensely competitive. Competition is
particularly intense in the acquisition of prospective oil and natural gas
properties and oil and gas reserves. The Company's competitive position depends
on its geological, geophysical and engineering expertise, its financial
resources, its ability to develop its properties and its ability to select,
acquire and develop proved reserves. The Company competes with a substantial
number of other companies having larger technical staffs and greater financial
and operational resources. Many such companies not only engage in the
acquisition, exploration, development and production of oil and natural gas
reserves, but also carry on refining operations, generate electricity and market
refined products. The Company also competes with major and independent oil and
gas companies in the marketing and sale of oil and gas to transporters,
distributors and end users. There is also competition between the oil and
natural gas industry and other industries supplying energy and fuel to
industrial, commercial and individual consumers. The Company also competes with
other oil and natural gas companies in attempting to secure drilling rigs and
other equipment necessary for drilling and completion of wells. Such equipment
may be in short supply from time to time. Finally, companies not previously
investing in oil and natural gas may choose to acquire reserves to establish a
firm supply or simply as an investment. Such companies will also provide
competition for the Company. The Company's business is affected not only by such
competition, but

31
<PAGE> 33

also by general economic developments, governmental regulations and other
factors that affect its ability to market its oil and natural gas production.
The prices of oil and natural gas realized by the Company are both highly
volatile and generally dependent on world supply and demand. Declines in crude
oil prices or natural gas prices adversely impact the Company's activities. The
Company's financial position and resources may also adversely affect the
Company's competitive position. Lack of available funds or financing
alternatives will prevent the Company from executing its operating strategy and
from deriving the expected benefits therefrom. For further information
concerning the Company's financial position, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations."

REGULATION

State Regulation. The Company's operations are subject to regulation at the
state level. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. The Company's operations are also subject to various
conservation laws and regulations. These include the size of drilling and
spacing units or proration units and the density of wells which may be drilled
and the unitization or pooling of oil and gas properties. In addition, state
conservation laws establish maximum rates of production from oil and gas wells,
generally prohibit the venting or flaring of gas and impose certain requirements
regarding the ratability of production. These regulatory burdens may affect
profitability, and the Company is unable to predict the future cost or impact of
complying with such regulations.

Federal Regulation. Various aspects of the Company's oil and natural gas
operations are regulated by administrative agencies of the Federal government.
The Federal Energy Regulatory Commission ("FERC") regulates the transportation
and sale for resale of natural gas in interstate commerce pursuant to the
Natural Gas Act of 1938 ("NGA") and the Natural Gas Policy Act of 1978 ("NGPA").
In the past, the Federal government has regulated the prices at which oil and
gas could be sold. While sales by producers of natural gas, and all sales of
crude oil, condensate and natural gas liquids can currently be made at
uncontrolled market prices, Congress could reenact price controls in the future.
Deregulation of wellhead sales in the natural gas industry began with the
enactment of the NGPA in 1978. In 1989, Congress enacted the Natural Gas
Wellhead Decontrol Act (the "Decontrol Act"). The Decontrol Act removed all NGA
and NGPA price and nonprice controls affecting producer wellhead sales of
natural gas effective January 1, 1993.

Commencing in April 1992, the FERC issued Order No. 636, and its progeny,
which require interstate pipelines to provide transportation separate, or
"unbundled," from the pipelines' sales of gas. Also, Order No. 636 requires
pipelines to provide open-access transportation on a basis that is equal for all
gas supplies. Although Order No. 636 does not directly regulate the Company's
activities, the FERC has stated that it intends for Order No. 636 to foster
increased competition within all phases of the natural gas industry. Numerous
parties have filed petitions for review of Order No. 636, as well as orders in
individual pipeline restructuring proceedings. In July 1996, Order No. 636 was
generally upheld on appeal. It is difficult to predict when all appeals of Order
No. 636 will be completed or their impact on the Company.

The FERC has recently announced several important transportation-related
policy statements and proposed rule changes, including the appropriate manner in
which interstate pipelines release capacity under Order No. 636 and, more
recently, the price which shippers can charge for their release capacity. In
1995, the FERC issued a policy statement on how interstate natural gas pipelines
can recover the costs of new pipeline facilities. In January 1996, the FERC
issued a policy statement and a request for comments concerning alternatives to
its traditional cost-of-service ratemaking methodology. A number of pipelines
have obtained FERC authorization to charge negotiated rates as one such
alternative. In February 1997, the FERC announced a broad inquiry into issues
facing the natural gas industry to assist the FERC in establishing regulatory
goals and priorities in the post-Order No. 636 environment. While any resulting
FERC action regarding these matters would affect the Company only indirectly,
the FERC's current rules and policy statements may have the effect of enhancing
competition in natural gas markets. The Company cannot predict

32
<PAGE> 34

what action the FERC will take on these matters, however, the Company does not
believe that it will be treated materially differently than other natural gas
producers and marketers with which it competes.

Commencing in October 1993, the FERC issued a series of rules (Order Nos.
561 and 561-A) establishing an indexing system under which oil pipelines will be
able to change their transportation rates, subject to prescribed ceiling levels.
The indexing system, which allows or may require pipelines to make rate changes
to track changes in the Producer Price Index for Finished Goods, minus one
percent, became effective January 1, 1995.

Substantially all of the Company's operations are located on oil and gas
leases, which are administered by the United States Department of the Interior
Minerals Management Service ("MMS"). Such leases are issued through competitive
bidding, contain relatively standardized terms and require compliance with
detailed MMS regulations. The MMS is conducting an inquiry into certain contract
agreements from which producers on MMS leases have received settlement proceeds
that the MMS contends are royalty-bearing and the extent to which producers have
paid the appropriate royalties on those proceeds. The Company believes that this
inquiry will not have a material impact on its financial condition, liquidity or
results of operations.

The MMS has issued a notice of proposed rulemaking in which it proposes to
amend its regulations governing the calculation of royalties and the valuation
of crude oil produced from federal leases. This proposed rule would modify the
valuation procedures for both arm's length and non-arm's length crude oil
transactions to decrease reliance on posted oil prices and assign a value to
crude oil that better reflects its market value, establish a new MMS form for
collecting differential data, and amend the valuation procedure for the sale of
federal royalty oil. The Company cannot predict what action the MMS will take on
this matter, nor can it predict how the Company will be affected by any change
to this regulation.

In April 1997, after two years of study, the MMS withdrew proposed changes
to the way it values natural gas for royalty payments. These proposed changes
would have established an alternative market-based method to calculate royalties
on certain natural gas sold to affiliates or pursuant to non-arm's length sales
contracts. Informal discussions among the MMS and industry officials are
continuing, although it is uncertain whether, and what changes may be proposed
regarding natural gas royalty valuation. In addition, the MMS has recently
approved its intention to issue a proposed rule that would require all but the
smallest producers to be capable of reporting production information
electronically by the end of 1998.

Additional proposals and proceedings that might affect the oil and gas
industry are pending before the FERC and the courts. The Company cannot predict
when or whether any such proposals may become effective. In the past, the
natural gas industry has been heavily regulated. There is no assurance that the
regulatory approach currently pursued by the FERC will continue indefinitely.
Notwithstanding the foregoing, the Company does not anticipate that compliance
with existing federal, state and local laws, rules and regulations will have a
material or significantly adverse effect upon the capital expenditures, earnings
or competitive position of the Company or its subsidiaries. No material portion
of the Company's business is subject to renegotiation of profits or termination
of contracts or subcontracts at the election of the Federal government.

OPERATING HAZARDS AND ENVIRONMENTAL MATTERS

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 or loss of
life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, clean-up responsibilities,
regulatory investigation and penalties, and suspension or curtailment of
operations.

The Company's operations relating to the exploration, development and
production of oil and natural gas are subject to extensive federal, state and
local laws governing the discharge of materials into the environment or
otherwise relating to the protection of the environment. Numerous governmental
departments issue rules and regulations to implement and enforce such laws which
are often difficult and costly to comply with and

33
<PAGE> 35

which carry substantial civil and criminal penalties for failure to comply.
These laws, rules, and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities, and concentration of
various substances that can be released into the environment in connection with
drilling and production activities, limit or prohibit drilling activities on
certain lands lying within wilderness, wetlands, frontier and other protected
areas, require some form of remedial action to prevent pollution from former
operations, such as pit cleanups and plugging abandoned wells, and impose
substantial liabilities for pollution resulting from the Company's operations.
In addition, these laws, rules and regulations may restrict the rate of oil and
natural gas production below the rate that would otherwise exist. The regulatory
burden on the oil and natural gas industry increases its cost of doing business
and consequently affects its profitability. These laws, rules and regulations
affect the operations of the Company and compliance with the underlying
environmental requirements generally could have a material adverse effect upon
the capital expenditures, earnings or competitive position of the Company. While
the Company believes that it is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on the Company,
changes in environmental law have the potential to adversely affect the
Company's operations.

The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to be responsible for the release of "hazardous substances"
into the environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that disposed or
arranged for the disposal of the hazardous substances at the site where the
release occurred. Under CERCLA, such persons may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment, for damages to natural resources and for the
costs of certain health studies and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the release of hazardous substances or other
pollutants into the environment. Furthermore, although petroleum, including
crude oil and natural gas, is exempt from CERCLA, at least two separate courts
have ruled that certain wastes associated with the production of crude oil may
be classified as hazardous substances under CERCLA and, thus, the Company could
become subject to the burdensome cleanup and liability standards established
under the federal Superfund program if significant concentrations of such wastes
were determined to be present at the Company's properties or to have been
produced as a result of the Company's operations.

The Company generates wastes that may be subject to the Federal Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S.
Environmental Protection Agency and various state agencies have limited the
approved methods of disposal for certain hazardous and nonhazardous wastes.
Furthermore, it is possible that certain wastes generated by the Company's oil
and natural gas operations that are currently exempt from management as
hazardous wastes may in the future be designated as "hazard wastes" under RCRA
or other applicable statutes and therefore be subject to more rigorous and
costly operating, disposal and cleanup requirements.

The Company currently owns or leases numerous properties that for many
years have been used for the exploration and production of oil and gas. Although
the Company has utilized operating and disposal practices that were standard in
the industry at the time, hydrocarbons or other wastes may have been disposed of
or released on or under the properties owned or leased by the Company or on or
under other locations where such wastes have been taken for disposal. In
addition, many of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other wastes was not under
the Company's control. These properties and the wastes disposed thereon may be
subject to CERCLA, RCRA, and analogous state laws. Under such laws, the Company
could be required to remove or remediate previously disposed wastes (including
waste disposed of or released by prior owners or operators) or property
contamination (including groundwater contamination by prior owners or operators)
or to perform remedial plugging operations to prevent future contamination.

Although the Company maintains insurance against some, but not all, of the
risks described above, including insuring the costs of clean-up operations,
public liability and physical damage, there is no assurance

34
<PAGE> 36

that such insurance will be adequate to cover all such costs or that such
insurance will continue to be available in the future or that such insurance
will be available at premium levels that justify its purchase. The occurrence of
a significant event not fully insured or indemnified against could have a
material adverse effect on the Company's financial condition and operations.

CORPORATE OFFICES; EMPLOYEES

The Company's principal office is located at 999 18th Street, Suite 1700,
Denver, Colorado 80202. The Company's phone number is (303) 293-2333. The
Company employs 19 full time employees and one part time employee at this
office. The Company maintains an oil field operations office in Carlsbad, New
Mexico, where it employs nine individuals.

LAGUNA

The Company owns an approximate 56% interest in Laguna, a gold mining
company whose common shares are listed on The Toronto Stock Exchange under the
trading symbol "LGC." The Company has engaged a Canadian investment banking firm
to explore strategic alternatives relating to the Company's interest in Laguna,
which may include a sale of the Company's Laguna stock, a reorganization or
merger of Laguna with a third party, or other transaction. No assurance can be
given that any such transaction will be arranged, or as to the terms of any
arrangement that may be made. In connection with any potential disposition of
the Company's interest in Laguna, the Company may incur a loss on the recovery
of its investment. Pending the receipt of an offer to purchase Laguna, or the
negotiation of the terms of a merger or other transaction, no estimate of
whether such a loss will be incurred, or the amount of such loss, if any, can be
made. Should a transaction be completed that would reduce the Company's
investment in Laguna below a 50% interest, the Company would deconsolidate the
financial position and results of operations of Laguna and would record its
investment in Laguna using the equity method of accounting. The Company has no
contractual obligation to finance Laguna's future operations and has no
intention to do so. See "Risk Factors."

35
<PAGE> 37

MANAGEMENT

The following are the members of the Company's Board of Directors and the
Company's executive officers:

<TABLE>
<CAPTION>
NAME AGE TITLE(S)
---- --- --------
<S> <C> <C>
George O. Mallon, Jr.......... 53 Director, Chairman of the Board and President of the
Company; Chairman of Mallon Oil and Director of Laguna
Kevin M. Fitzgerald........... 43 Director and Executive Vice President of the Company;
President of Mallon Oil
Roy K. Ross................... 46 Director, Executive Vice President, Secretary and General
Counsel of the Company, Mallon Oil and Laguna
Frank Douglass................ 64 Director
Roger R. Mitchell............. 65 Director
Francis J. Reinhardt, Jr...... 66 Director
Alfonso R. Lopez.............. 49 Vice President-Finance and Treasurer
</TABLE>

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

George O. Mallon, Jr. has been the President and Chairman of the Board of
the Company since December 1988. He formed Mallon Oil in 1979 and served as its
President until December 1988, when he became that company's Chairman of the
Board. Mr. Mallon was a co-founder of Laguna in 1980 and served as its President
until April 1986. He is now a director of Laguna. 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 has been Executive Vice President of the Company since
June 1990. He joined Mallon Oil in 1983 as Petroleum Engineer and served as Vice
President of Engineering from 1987 through December 1988, when he became
President of that company. Mr. Fitzgerald was Vice President, Oil and Gas
Operations for the Company from 1988 through October 1990, when he was named
Executive Vice President. Mr. Fitzgerald is also a director of Mallon Oil. Mr.
Fitzgerald earned a B.S. degree in Petroleum Engineering from the University of
Oklahoma in 1978.

Roy K. Ross has been Executive Vice President and General Counsel of the
Company since 1992. He was named Secretary of the Company 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 and
Laguna. 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.

Frank Douglass has been a director of the Company since 1988. He is a
Senior Partner in the Texas law firm of Scott, Douglass & McConnico, LLP, where
he has 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 the Company since 1990. He joined
the Company in January 1989 as a Vice President with responsibility for investor
relations, broker-dealer liaison, and special marketing projects. He was
President of Mallon Securities Corporation, a limited broker-dealer firm wholly
owned by Mallon Oil, from 1982 until that firm was dissolved in October 1990. In
August 1991, Mr. Mitchell left the employment of the Company to start First
Federated Telepartners, a private telecommunications business headquartered in
Chicago. In December 1992, Mr. Mitchell sold his interest in First Federated
Telepartners and retired, although he continues to provide consulting services
to various businesses on a part-time basis. 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 the Company 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

36
<PAGE> 38

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 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 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

The following is information concerning certain of the Company's employees
who are instrumental to the Company's success:

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 Colorado School of Mines in 1979 and is a registered
professional engineer.

Randy Stalcup has been the Vice President-Land of Mallon Oil since April
1994. Prior to joining the Company, Mr. Stalcup was employed by Beard Oil
Company for 13 years, where he was the 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 has been Vice President-Geology of Mallon Oil since
December 1996. Prior to joining the Company on a full time basis, Mr. Bond was
an independent geological consultant to the Company since July 1994. Mr. Bond
has 24 years of experience in the petroleum industry, both domestically and
internationally. Prior to joining the Company, he was president of 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. has been Vice President-Operations of Mallon Oil
since 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 C. Winkler is Production Superintendent 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 25 years of experience in drilling, completion and
production operations, completed his Associates of Engineering Certificate from
Central Wyoming College in 1996.

37
<PAGE> 39

PRINCIPAL SHAREHOLDERS

The following table sets forth information concerning the beneficial
ownership of the Common Stock as of November 21, 1997, by (i) the Company's
chief executive officer; (ii) each of the Company's directors; (iii) each
shareholder known by the Company to own of record or beneficially more than 5%
of the Company's outstanding Common Stock; and (iv) all directors and executive
officers as a group.

<TABLE>
<CAPTION>
PERCENT OWNED
--------------------
NUMBER OF BEFORE AFTER
NAME AND ADDRESS OF BENEFICIAL OWNER(1) SHARES OFFERING OFFERING
--------------------------------------- --------- -------- --------
<S> <C> <C> <C>
George O. Mallon, Jr...................................... 309,349(2) 6.6% 4.4%
Kevin M. Fitzgerald....................................... 74,778(3) 1.6 1.1%
Roy K. Ross............................................... 27,876(4) * *
Frank Douglass............................................ 18,361(5) * *
Roger R. Mitchell......................................... 49,348(6) 1.0% *
Francis J. Reinhardt, Jr.................................. 42,442(7) * *
Cambridge Investments Limited............................. 470,800(8) 10.0% 6.7%
All officers and directors as a group (7 persons)......... 525,154(9) 10.9% 7.4%
</TABLE>

- ---------------

* Less than 1%

(1) The address of Messrs. Mallon, Fitzgerald and Ross is 999 18th Street, Suite
1700, Denver, Colorado 80202. The address of Mr. Mitchell is 5436 Lake Edge
Drive, Holly Spring, North Carolina 27540. The address of Mr. Douglass is
4350 Beltway Drive, Dallas, Texas 75244-3110. The address of Mr. Reinhardt
is 650 Madison Avenue, 23rd Floor, New York, New York 10022. The address of
Cambridge Investments Limited is 600 Montgomery Street, 27th Floor, San
Francisco, California 94111.

(2) Includes 2,166 shares owned by Mr. Mallon's wife. Includes 7,278 shares that
may be acquired upon the exercise of vested stock options. Does not include
142,000 shares covered by stock options that have not vested.

(3) Includes 56,028 shares that may be acquired upon the exercise of vested
stock option. Does not include 88,500 shares covered by stock options that
have not vested.

(4) Includes 21,137 shares that may be acquired upon the exercise of vested
stock options. Does not include 58,500 shares covered by stock options that
have not vested.

(5) Includes 10,000 shares that may be acquired upon the exercise of vested
stock options.

(6) Includes 12,000 shares that may be acquired upon the exercise of vested
stock options.

(7) Includes 8,000 shares that may be acquired upon the exercise of vested stock
options.

(8) Based on the most recent Schedule 13D on file with the Commission.

(9) Includes 2,166 shares owned by Mr. Mallon's wife. Includes 107,943 shares
that may be acquired upon the exercise of vested stock options. Does not
include 301,000 shares covered by stock options that have not vested.

TRANSACTIONS WITH RELATED PARTIES

The Company serves as operator of certain oil and gas properties in which
some of the officers and directors of the Company have working interests. Such
individuals pay their pro-rata share of all costs relating to the properties, on
the same basis as other unaffiliated interest owners.

During the year ended December 31, 1996, the Company paid $191,000 of
consulting and other fees to the investment banking firm of Carl H. Pforzheimer
& Co., of which Mr. Reinhardt is a partner.

38
<PAGE> 40

DESCRIPTION OF CAPITAL STOCK AND OTHER SECURITIES
GENERAL

The Company's Articles of Incorporation (the "Articles") authorize the
Company to issue 25,000,000 shares of Common Stock, par value $.01 per share,
and 10,000,000 shares of Preferred Stock, par value $.01 per share. The shares
of the Company's preferred stock are issuable from time to time in one or more
series and with such designations, powers, preferences and rights, and
qualifications, limitations or restrictions thereof, as may be determined by the
Board, consistent with the Articles and with the laws of the State of Colorado.
Unless otherwise indicated, all Common Stock amounts have been adjusted to give
effect to a four to one reverse stock split that occurred on September 9, 1996.

COMMON STOCK

The Company had 4,695,264 shares of Common Stock outstanding prior to this
Offering, which were held by approximately 650 shareholders of record. Each
share of Common Stock entitles the shareholder to one vote. Holders of Common
Stock are not entitled to cumulative voting in the election of directors and
have no preemptive or subscription rights. Subject to the rights of holders of
any outstanding shares of Preferred Stock, shares of Common Stock are entitled
to share equally in dividends paid from the funds legally available for the
payment thereof, when, as and if declared by the Board. Subject to the rights of
holders of any outstanding shares of Preferred Stock, holders of Common Stock
are also entitled to share ratably in the assets of the Company available for
distribution to holders of Common Stock upon liquidation or dissolution of the
Company, whether voluntary or involuntary. The Common Stock is listed on the
Nasdaq National Market under the symbol "MLRC." The Company's transfer agent is
Securities Transfer Corporation, Dallas, Texas.

OPTIONS

At November 21, 1997, options to purchase an aggregate of 564,026 shares of
the Common Stock were issued and outstanding. These options were issued under
the Company's 1988 and 1997 Equity Participation Plans to various of the
Company's employees, directors, and to various consultants.

WARRANTS

The Company has outstanding warrants to purchase an aggregate of 268,762
shares of Common Stock, as described below.

Warrants to purchase an aggregate of 77,735 shares of Common Stock at an
adjusted exercise price of $8.04 per share were issued to the holders of
Laguna's Series A Preferred Stock in connection with the private placement of
that stock. The warrants expire June 30, 2000.

In August 1995, the Company issued warrants to purchase an aggregate of
31,027 shares of Common Stock at an adjusted exercise price of $8.06 per share
to an affiliate of Midland Bank plc, New York Branch, as an "equity kicker" in
connection with the establishment of a now terminated line of credit with that
bank. The warrants expire on August 24, 2000.

In October 1996, in connection with an offering of Common Stock, the
Company issued warrants to purchase 160,000 shares of Common Stock to the
managing underwriter, with an exercise price of $7.80 per share. The warrants
expire on October 16, 1999.

PREFERRED STOCK

The Board is authorized under the Articles to issue up to 10,000,000 shares
of Preferred Stock from time to time in one or more series and to fix (without
shareholder action) the voting rights and other special rights, including,
without limitation, the conversion rights, rights and terms of redemption
(including sinking fund provisions), and dividend and liquidation rights of each
series.

Shareholders will not have any preemptive rights with respect to any of the
authorized but unissued shares of Common Stock and Preferred Stock. Issuance of
shares of Preferred Stock could impact the voting rights of the holders of
Common Stock by creating a series of shares with disproportionately higher
voting rights and by the creation of class or series voting rights on particular
matters. The issuance of shares of Preferred Stock with conversion rights or
which are redeemable for shares of Common Stock could increase

39
<PAGE> 41

the potential number of shares of Common Stock outstanding. It is probable that
when shares of Preferred Stock are issued they will have rights prior to the
Common Stock as to dividends and as to the distribution of assets in the event
of liquidation. In addition, the Board may provide that the holders of any
series of Preferred Stock will be entitled, in addition to their preferential
rights, to participate with the holders of Common Stock in dividends and in
distributions in liquidation. The authorized shares of preferred stock are
available for issuance at such times and for such purposes as the Board may deem
advisable, without further action by the shareholders. The Board, without
shareholder approval, can issue Preferred Stock with voting and conversion
rights that could adversely affect the voting power of holders of Common Stock.
The issuance of Preferred Stock may have the effect of delaying, deferring or
preventing a change in control of the Company. The Company has no present plans
to issue any additional shares of Preferred Stock.

SERIES B MANDATORILY REDEEMABLE PREFERRED STOCK

In April 1994, the Company sold 400,000 shares of its Series B Preferred
Stock to several institutional investors in private transactions for an
aggregate of $4 million. The Series B Preferred Stock is convertible to Common
Stock at any time at the option of the holder. In April 1997, a total of 264,800
shares of the Series B Preferred Stock were either redeemed or converted into
shares of Common Stock. The conversion price, as adjusted to reflect this
Offering, is currently $10.52, which means a total of 128,517 shares of Common
Stock are issuable upon the conversion of the outstanding shares of Series B
Preferred Stock. The Series B Preferred Stock is convertible to Common Stock
automatically if the Common Stock trades at a price in excess of 140% of the
conversion price (meaning the target price is currently $15.65 per share) for
each day in a period of 10 consecutive trading days. The Series B Preferred
Stock provides for a preferential 8% dividend, payable quarterly. The Series B
Preferred Stock has a preference on liquidation of $1,352,000 (the face value
outstanding after April 1997). The Series B Preferred Stock is redeemable at the
Company's election, at any time. The optional redemption price is $10.00 per
preferred share (the original purchase price), plus a decreasing early
redemption premium if it is redeemed before April 1, 2001. Starting April 1,
1997, 20% of the Series B Preferred Stock must be redeemed each year. No early
redemption premium is payable in connection with such mandatory redemptions.
After the April 1997 transactions, the Company has no further obligation to
redeem any shares until April 2000. Except as otherwise required by law, holders
of Series B Preferred Stock have no voting rights, except upon default. In the
event of a default, holders of the Series B Preferred Stock have the right to
elect two additional directors to the Company's Board during the duration of the
default.

CERTAIN VOTING REQUIREMENTS

The Articles require a super-majority vote of the Company's shareholders to
approve certain business combinations or other significant corporate
transactions involving the Company and a substantial shareholder of the Company.
The Articles require the affirmative vote of the holders of a majority of the
outstanding shares entitled to vote to approve a merger, consolidation or
dissolution of the Company or a disposition of all or substantially all of the
Company's assets, under ordinary circumstances. The Articles raise the required
affirmative vote to 80% of the total number of votes entitled to be cast to
approve these and other significant corporate transactions ("Business
Combinations") if a "9% Shareholder" (as defined) is a party to the transaction
or its percentage equity interest in the Company or any subsidiary of the
Company will be increased by the transaction. A majority of the whole Board may,
in all such cases, determine not to require such 80% affirmative vote, but only
if 80% of the "Continuing Directors" (as defined) so determine. The required 80%
approval of any such business combination must include at least a majority of
all votes entitled to be cast with respect to voting shares not beneficially
owned by any 9% Shareholder.

A "9% Shareholder" generally is defined as the "beneficial owner" as
defined in Rule 13d-3 under the Securities Exchange Act of 1934 (the "Exchange
Act") of 9% or more of the outstanding shares of Company stock entitled to vote
generally in the election of directors ("voting shares"). A Business Combination
includes: a merger or consolidation involving the Company or any of its
subsidiaries (as defined) and a 9% Shareholder; a sale, lease or other
disposition of a substantial part of the assets of the Company or any of its

40
<PAGE> 42

subsidiaries (that is, assets constituting in excess of 10% of the book value of
the total consolidated assets of the Company) to a 9% Shareholder; an issuance
of equity securities of the Company or any of its subsidiaries to a 9%
Shareholder for consideration aggregating $5 million or more; liquidation or
dissolution of the Company (if as of the record date for the determination of
shareholders entitled to vote with respect thereto any person is a 9%
Shareholder); and a reclassification or recapitalization of securities
(including any reverse stock split) of the Company or any of its subsidiaries or
a reorganization, in any case having the effect, directly or indirectly, of
increasing the percentage interest of a 9% Shareholder in any class of equity
securities of the Company or such subsidiary.

A "continuing director" is defined as one designated in the original
Articles or one designated as a continuing director (prior to his initial
election or appointment) by a majority of the whole board of directors, but only
if a majority of the whole board shall then consist of continuing directors, or,
if a majority of the whole board does not then consist of continuing directors,
by a majority of the then continuing directors. Each of the directors identified
in this Prospectus is a continuing director.

These provisions are intended to provide safeguards to the Company's public
shareholders in the event another entity first gains working control of the
Company and then wishes to accomplish a combination of the two businesses, or
otherwise eliminate the holdings of the public.

Accordingly, these provisions are intended to provide some assurance that
adequate time and needed information will be available to the public
shareholders and the Board in order that a considered judgment may be made with
respect to a business combination, taking into account such matters as the
proposed price and form of consideration, the tax implications to public
shareholders and the impact of the business combination upon the employees of
the Company. This result is intended to be accomplished by encouraging another
entity that is interested in a business combination with or acquisition of the
Company to negotiate the terms of the business combination or acquisition in
advance of its acquisition of a substantial number of shares of the Company.

Under those circumstances in which the provisions would apply, a minority
of the Company's shareholders may prevent the consummation of a transaction
favored by a majority of shareholders. As a practical matter, the requirement of
an 80% vote may also mean that the type of business combination to which these
provisions are addressed might not be accomplished by the controlling entity
while there remains any widely dispersed public market in the Company's voting
shares. Because the affirmative vote of at least 80% of the total votes entitled
to be cast (rather than the votes actually cast at a meeting) would be required,
the failure of shareholders to vote also could result in the defeat of a
proposed transaction. These provisions could operate to the disadvantage of
present management by restricting its flexibility in the conduct of corporate
affairs.

These provisions may not be amended, altered, changed or repealed without
the affirmative vote of 80% or more of the votes entitled to be cast by all
holders of voting shares (which 80% vote must include the affirmative vote of a
majority of the votes entitled to be cast by all holders of voting shares not
beneficially owned by any 9% Shareholder). This vote requirement will not apply
to any amendment, alteration, change or repeal recommended to the shareholders
by 75% of the whole Board, provided that a majority of the members of the Board
acting upon such matter are continuing directors. Under such circumstances, an
amendment, alternation, change or repeal may be approved by a simple majority of
the votes entitled to be cast.

SHAREHOLDER RIGHTS PLAN

On April 22, 1997, the Board of Directors of the Company declared a
dividend distribution of one Right for each outstanding share of Common Stock to
shareholders of record at the close of business on April 25, 1997. Each Right
entitles the registered holder to purchase from the Company one share of Common
Stock at a Purchase Price of $40.00 per share, subject to adjustment. The
description and terms of the Rights are set forth in a Shareholder Rights Plan
(the "Rights Plan") between the Company and Securities Transfer Corporation as
Rights Agent.

41
<PAGE> 43

Initially, the Rights will be attached to all Common Stock certificates
representing shares then outstanding, and no separate Rights Certificates will
be distributed. The Rights will separate from the Common Stock and a
Distribution Date will occur upon the earlier of (i) 10 days following a public
announcement that a person or group of affiliated or associated persons (an
"Acquiring Person") has acquired, or obtained the right to acquire, beneficial
ownership of 20% or more of the outstanding shares of Common Stock (the "Stock
Acquisition Date"), or (ii) 10 business days following the commencement of a
tender offer or exchange offer that would result in a person or group
beneficially owning 20% or more of such outstanding shares of Common Stock.
Until the Distribution Date, (i) the Rights will be evidenced by the Common
Stock certificates and will be transferred with and only with such Common Stock
certificates, and (ii) the surrender for transfer of any certificates for Common
Stock will also constitute the transfer of the Rights associated with the Common
Stock represented by such certificate.

The Rights are not exercisable until the Distribution Date and will expire
at the close of business on April 22, 2001, unless earlier redeemed by the
Company as described below.

As soon as practicable after the Distribution Date, Rights Certificates
will be mailed to holders of record of the Common Stock as of the close of
business on the Distribution Date and, thereafter, the separate Rights
Certificates alone will represent the Rights. Except as otherwise determined by
the Board of Directors, only shares of Common Stock issued prior to the
Distribution Date will be issued with Rights.

If any person becomes an Acquiring Person other than pursuant to a
Qualifying Offer (as defined below), each holder of a Right will thereafter have
the right to receive, upon exercise, Common Stock (or, in certain circumstances,
cash, property or other securities of the Company) having a value equal to two
times the exercise price of the Right. Notwithstanding any of the foregoing, all
Rights that are, or (under certain circumstances specified in the Rights Plan)
were, beneficially owned by any Acquiring Person will be null and void. However,
Rights are not exercisable in any event until such time as the Rights are no
longer redeemable by the Company as set forth below.

A "Qualifying Offer" means a tender offer or exchange offer for all
outstanding shares of Common Stock at a price and on terms determined by at
least a majority of the Continuing Directors (as defined below) who are not
officers or employees of the Company and who are not related (as specified in
the Rights Plan) to the Person making such offer, after receiving advice from
one or more investment banking firms, to be fair to and in the best interests of
the Company and its shareholders.

If at any time following the Stock Acquisition Date (i) the Company is
acquired in a merger or other business combination transaction in which the
Common Stock is changed or exchanged or in which the Company is not the
surviving corporation (other than a merger that follows a Qualifying Offer and
satisfies certain other requirements), or (ii) 50% or more of the Company's
assets or earning power is sold or transferred, each holder of a Right (except
Rights that have been previously voided as set forth above) shall thereafter
have the right to receive, upon exercise, common stock of the acquiring company
having a value equal to two times the exercise price of the Right. The events
set forth in this paragraph and in the third preceding paragraph are referred to
as the "Triggering Events."

The Purchase Price payable, and the number of shares of Common Stock or
other securities or property issuable, upon exercise of the Rights are subject
to adjustment from time to time to prevent dilution (i) in the event of a stock
dividend on, or a subdivision, combination or reclassification of, the Common
Stock, (ii) if holders of the Common Stock are granted certain rights or
warrants to subscribe for Common Stock or convertible securities at less than
the current market price of the Common Stock, or (iii) upon the distribution to
holders of the Common Stock of evidences of indebtedness or assets (excluding
regular quarterly cash dividends) or of subscription rights or warrants (other
than those referred to above).

With certain exceptions, no adjustment in the Purchase Price will be
required until cumulative adjustments amount to at least 1% of the Purchase
Price. No fractional shares will be issued and, in lieu thereof, an adjustment
in cash will be made based on the market price of the Common Stock on the last
trading date prior to the date of exercise.

42
<PAGE> 44

At any time until ten days following the Stock Acquisition Date, the
Company may redeem the Rights in whole, but not in part, at a price of $.01 per
Right (payable in cash, Common Stock or other consideration deemed appropriate
by the Board of Directors). Under certain circumstances set forth in the Rights
Plan, the decision to redeem shall require the concurrence of a majority of the
Continuing Directors. Immediately upon the action of the Board of Directors
ordering redemption of the Rights or at such other time as may be specified by
the Board when it orders redemption, with, where required, the concurrence of
the Continuing Directors, the Rights will terminate and the only right of the
holders of Rights will be to receive the $.01 redemption price.

The term "Continuing Directors" for purposes of the Rights Plan means any
member of the Board of Directors of the Company who was a member of the Board
prior to the Stock Acquisition Date, and any person who is subsequently elected
to the Board if such person is recommended or approved by a majority of the
Continuing Directors, but shall not include an Acquiring Person, or an affiliate
or associate of an Acquiring Person, or any representative of the foregoing
entities.

Until a Right is exercised, the holder thereof, as such, will have no
rights as a shareholder of the Company, including, without limitation, the right
to vote or to receive dividends. While the distribution of the Rights will not
be taxable to shareholders or to the Company, shareholders may, depending upon
the circumstances, recognize taxable income if the Rights become exercisable for
Common Stock (or other consideration) of the Company or for common stock of the
acquiring company as set forth above.

Other than those provisions relating to the principal economic terms of the
Rights, any of the provisions of the Rights Plan may be amended by the Board of
Directors of the Company prior to the Distribution Date. After the Distribution
Date, the Rights Plan may be amended by the Board (in certain circumstances,
with the concurrence of the Continuing Directors) in order to cure any
ambiguity, to make changes that do not adversely affect the interests of holders
of Rights (excluding the interests of any Acquiring Person), or to shorten or
lengthen any time period under the Rights Plan; provided, however, that no
amendment to adjust the time period governing redemption shall be made at a time
when the Rights are not redeemable.

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<PAGE> 45

UNDERWRITING

The Underwriters named below, for whom ABN AMRO Chicago Corporation and
Gaines, Berland Inc. are acting as Representatives (the "Representatives"), have
severally agreed to purchase from the Company the respective number of shares of
Common Stock set forth opposite their names:

<TABLE>
<CAPTION>
NUMBER OF SHARES
UNDERWRITER OF COMMON STOCK
----------- ----------------
<S> <C>
ABN AMRO Chicago Corporation................................
Gaines, Berland Inc.........................................

---------
Total.............................................. 2,300,000
=========
</TABLE>

The Underwriting Agreement provides that the obligations of the several
Underwriters thereunder are subject to approval of certain legal matters by
counsel and to various other considerations. The nature of the Underwriters'
obligations is such that they are committed to purchase and pay for all of the
above shares of Common Stock if any are purchased.

The Underwriters, through the Representatives, have advised the Company
that they propose to offer the Common Stock initially at the public offering
price set forth on the cover page of this Prospectus, that the Underwriters may
allow to selected dealers a concession of $ per share, and that such
dealers may reallow a concession of $ per share to certain other
dealers. After the public offering, the offering price and other selling terms
may be changed by the Underwriters. The Common Stock is included for quotation
on the Nasdaq National Market under the symbol "MLRC."

The Company has granted to the Underwriters a 30-day over-allotment option
to purchase up to an aggregate of 345,000 additional shares of Common Stock,
exercisable at the public offering price less the underwriting discount. If the
Underwriters exercise such over-allotment option, then each of the Underwriters
will have a firm commitment, subject to certain conditions, to purchase
approximately the same percentage thereof as the number of shares of Common
Stock to be purchased by it as shown in the above table bears to the 2,300,000
shares of Common Stock offered hereby. The Underwriters may exercise such option
only to cover over-allotments made in connection with the sale of the shares of
Common Stock offered hereby.

The Company and the officers and directors of the Company have agreed that
they will not sell or dispose of any shares of Common Stock of the Company for a
period of 90 days after the later of the date on which the Registration
Statement is declared effective by the Commission or the first date on which the
shares are bona fide offered to the public, without the prior written consent of
the Representatives.

The Company has agreed to indemnify the Underwriters against certain
liabilities, losses and expenses, including liabilities under the Securities Act
of 1933, as amended (the "Securities Act") or to contribute to payments that the
Underwriters may be required to make in respect thereof.

In connection with the Offering, the Underwriters may purchase and sell the
Common Stock in the open market. These transactions may include over-allotment
and stabilizing transactions, "passive" market making and purchases to cover
syndicate short positions created in connection with the offering. Stabilizing
transactions consist of certain bids or purchases for the purpose of preventing
or retarding a decline in the market price of the Common Stock and syndicate
short positions involve the sale by the Underwriters of a greater number of
shares of Common Stock than they are required to purchase from the Company in
the offering. The Underwriters also may impose a penalty bid, whereby selling
concessions allowed to syndicate members or other broker-dealers in respect of
the shares of Common Stock sold in the offering for their

44
<PAGE> 46

account may be reclaimed by the syndicate if such shares of Common Stock are
repurchased by the syndicate in stabilizing or covering transactions. These
activities may stabilize, maintain or otherwise affect the market price of the
Common Stock, which may be higher than the price that might otherwise prevail in
the open market, and these activities, if commenced, may be discontinued at any
time. These transactions may be effected on the Nasdaq National Market, in the
over-the-counter market, or otherwise.

As permitted by Rule 103 under the Exchange Act, certain Underwriters (and
selling group members, if any) that are market makers ("passive market makers")
in the Common Stock may make bids for or purchases of the Common Stock in the
Nasdaq National Market until such time, if any, when a stabilizing bid for such
securities has been made. Rule 103 generally provides that (1) a passive market
maker's net daily purchases of the Common Stock may not exceed 30% of its
average daily trading volume in such securities for the two full consecutive
calendar months (or any 60 consecutive days ending within the 10 days)
immediately preceding the filing date of the registration statement of which
this Prospectus forms a part, (2) a passive market maker may not effect
transactions or display bids for the Common Stock at a price that exceeds the
highest independent bid for the Common Stock by persons who are not passive
market makers and (3) bids made by passive market makers must be identified as
such.

LEGAL MATTERS

The legality of the securities offered hereby will be passed on for the
Company by Holme Roberts & Owen LLP, Denver, Colorado. Certain legal matters in
connection with the sale of such securities will be passed on for the
Underwriters by Vinson & Elkins L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements as of December 31, 1996 and 1995 and
for each of the three years in the period ended December 31, 1996 included in
this Prospectus have been so included in reliance on the report of Price
Waterhouse LLP, independent accountants, given on the authority of said firm as
experts in auditing and accounting. In July 1997, the Company solicited bids for
audit work on its financial statements for the next three years. As a result of
that process, the Audit Committee of the Company's Board of Directors selected
Arthur Andersen LLP as its independent accountants for such period. There were
no disagreements with Price Waterhouse LLP on any matter of accounting
principles or practices, financial statement disclosure, or auditing scope or
procedure, and Price Waterhouse LLP's reports did not contain any adverse or
qualified opinions during such accounting firm's engagement. The Company had no
prior business dealings or consultations with Arthur Andersen LLP.

Information set forth in this Prospectus relating to the Company's
estimated proved oil and gas reserves at June 30, 1996 and December 31, 1996,
the related calculations of future net production revenues and net present value
thereof have been derived from independent petroleum engineering reports
prepared by GeoQuest Reservoir Technologies, Inc., independent petroleum
engineers, and is included herein in reliance on such firm as an expert in
preparing such information.

Information set forth in this Prospectus relating to the Company's
estimated proved oil and gas reserves at September 30, 1997, the related
calculations of future net production revenues and net present value thereof
have been derived from an independent petroleum engineering report prepared by
Ryder Scott Company Petroleum Engineers, independent petroleum engineers, and is
included herein in reliance on such firm as an expert in preparing such
information. A summary of the Ryder Scott Report is included herein as Annex A.

45
<PAGE> 47

AVAILABLE INFORMATION

The Company has filed with the Commission a registration statement on Form
S-2 (the "Registration Statement," which term encompasses all amendments,
exhibits, annexes and schedules thereto) under the Securities Act with respect
to the Common Stock offered hereby. This Prospectus, which constitutes a part of
the Registration Statement, does not contain all the information set forth in
the Registration Statement, to which reference is hereby made. Statements made
in this Prospectus as to the contents of any contract, agreement or other
document referred to are not necessarily complete. With respect to each such
contract, agreement or other document filed as an exhibit to the Registration
Statement and the exhibits thereto, reference is hereby made to the exhibit for
a more complete description of the matter involved, and each statement made
herein shall be deemed qualified in its entirety by such reference.

The Company is subject to the informational requirements of the Exchange
Act and in accordance therewith files periodic reports, proxy and information
statements and other information filed with the Commission. The Registration
Statement filed by the Company with the Commission, as well as such reports,
proxy and information statements and other information filed by the Company with
the Commission, are available at the web site that the Commission maintains at
http:www.sec.gov. and can be inspected and copied at the public reference
facilities maintained by the Commission at Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549, and at the regional offices of the
Commission located at 7 World Trade Center, New York, New York 10048, and the
Chicago Regional Office, Northwestern Atrium Center, 500 West Madison Street,
Suite 1400, Chicago, Illinois 60661. Copies of such material, when filed, may
also be obtained from the Public Reference Section of the Commission at 450
Fifth Street, N.W., Washington, D.C. 20549 at prescribed rates. The Common Stock
is quoted on the Nasdaq National Market and such reports, proxy and information
statements and other information concerning the Company are available at the
offices of the Nasdaq National Market located at 1735 K Street, N.W.,
Washington, D.C. 20006.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

Incorporated by reference in this Prospectus are (i) the Company's Annual
Report on Form 10-K for the fiscal year ended December 31, 1996, (ii) the
Company's Quarterly Reports on Form 10-Q for the quarters ended March 31, June
30, and September 30, 1997 and (iii) the Company's Current Reports on Form 8-K
dated January 15, February 27, March 18, April 22, May 6, May 15, June 25,
August 11, August 14, August 28, September 9, October 15, October 17, and
November 14, 1997, filed previously with the Commission pursuant to Section 13
of the Exchange Act. Any statement contained in a document incorporated by
reference herein shall be deemed to be modified or superseded for purposes of
this Prospectus to the extent that a statement contained herein modifies or
supersedes such statement. Any statement so modified or superseded shall not be
deemed, except as so modified or superseded, to constitute a part of this
Prospectus.

The Company will provide without charge to each person, including any
beneficial owner of Common Stock, to whom a copy of this Prospectus has been
delivered, on the written or oral request of such person, a copy of any or all
of the foregoing documents incorporated by reference in this Prospectus, other
than exhibits to such documents unless such exhibits are specifically
incorporated by reference into the information that this Prospectus
incorporates. Written or oral requests for such copies should be directed to Roy
K. Ross, Secretary, Mallon Resources Corporation, 999 18th Street, Suite 1700,
Denver, Colorado 80202 (telephone: (303) 293-2333).

46
<PAGE> 48

GLOSSARY OF 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.

BOE. Barrels of oil equivalent, determined using the ratio of six Mcf of natural
gas (including natural gas liquids) to one Bbl of crude oil or condensate.

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.

MBOE. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet.

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

MMBOE. One million barrels of oil equivalent.

MMBtu. One million Btus.

MMcf. One million cubic feet.

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

Pre-tax SEC 10 Value 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 Commission.

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.

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.

47
<PAGE> 49

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

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.

48
<PAGE> 50

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Audited Consolidated Financial Statements
Report of Independent Accountants......................... F-2
Consolidated Balance Sheets as of December 31, 1996 and
1995................................................... F-3
Consolidated Statements of Operations for the Years ended
December 31, 1996, 1995
and 1994............................................... F-4
Consolidated Statements of Shareholders' Equity for the
Years ended December 31, 1996, 1995 and 1994........... F-5
Consolidated Statements of Cash Flows for the Years ended
December 31, 1996, 1995
and 1994............................................... F-6
Notes to Consolidated Financial Statements................ F-7

Unaudited Interim Consolidated Financial Statements
Consolidated Balance Sheets as of September 30, 1997 and
December 31, 1996...................................... F-24
Consolidated Statements of Operations for the Nine Months
Ended September 30, 1997 and 1996...................... F-25
Consolidated Statements of Cash Flows for the Nine Months
Ended September 30, 1997 and 1996...................... F-26
Notes to Consolidated Financial Statements................ F-27
</TABLE>

F-1
<PAGE> 51

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholders of
Mallon Resources Corporation

In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, of shareholders' equity and of
cash flows present fairly, in all material respects, the financial position of
Mallon Resources Corporation and its subsidiaries at December 31, 1996 and 1995,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which 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, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.

PRICE WATERHOUSE LLP

Denver, Colorado
March 18, 1997

F-2
<PAGE> 52

MALLON RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31,
------------------
1996 1995
------- -------
<S> <C> <C>
Current assets:
Cash and cash equivalents................................. $ 2,771 $ 1,269
Short-term investments.................................... 2,786 --
Accounts receivable:
Oil and gas sales....................................... 1,879 1,065
Joint interest participants, net of allowance of $8 and
$0, respectively....................................... 827 376
Related parties......................................... 20 22
Other................................................... 45 --
Inventories............................................... 251 53
Other..................................................... 104 143
------- -------
Total current assets............................... 8,683 2,928
------- -------
Property and equipment:
Oil and gas properties, full cost method.................. 46,175 43,751
Mining properties and equipment........................... 10,114 6,248
Other equipment........................................... 559 508
------- -------
56,848 50,507
Less accumulated depreciation, depletion and amortization... (24,406) (22,085)
------- -------
32,442 28,422
------- -------
Notes receivable-related parties............................ 17 63
Other, net.................................................. 258 222
------- -------
Total Assets................................................ $41,400 $31,635
======= =======
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable.................................... $ 1,614 $ 2,309
Undistributed revenue..................................... 1,502 711
Drilling advances......................................... 100 271
Accrued taxes and expenses................................ 77 90
Current portion of capital lease obligation............... 25 23
------- -------
Total current liabilities.......................... 3,318 3,404
------- -------
Long-term debt.............................................. 3,269 10,000
Notes payable, other........................................ 230 --
Capital lease obligation, net of current portion............ 12 37
Drilling advances........................................... 368 315
Accrued expenses............................................ 41 --
------- -------
Total non-current liabilities...................... 3,920 10,352
------- -------
Total liabilities........................................... 7,238 13,756
------- -------
Commitments and contingencies............................... -- --
Minority interest........................................... 8,358 2,275
Series B Mandatorily Redeemable Convertible Preferred Stock,
$0.01 par value, 500,000 shares authorized, 400,000 shares
issued and outstanding, respectively; liquidation
preference and mandatory redemption of $4,000,000......... 3,900 3,844
Shareholders' equity:
Series A Convertible Preferred Stock, $0.01 par value,
1,467,890 shares authorized, 0 and 1,100,918 shares
issued and outstanding, respectively; liquidation
preference $6,000,000................................... -- 5,730
Common Stock, $0.01 par value, 25,000,000 shares
authorized; 4,384,562 and 1,950,226 shares issued and
outstanding, respectively............................... 44 19
Additional paid-in capital................................ 56,707 38,965
Accumulated deficit....................................... (34,847) (32,954)
------- -------
Total shareholders' equity......................... 21,904 11,760
------- -------
Total Liabilities and Shareholders' Equity......... $41,400 $31,635
======= =======
</TABLE>

The accompanying notes are part of these consolidated financial statements.

F-3
<PAGE> 53

MALLON RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
---------------------------
1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
Revenues:
Oil and gas sales......................................... $ 5,854 $ 3,380 $ 2,263
Deferred revenue amortization............................. -- 1,420 2,366
Gain on termination of volumetric production payment...... -- 355 --
Gain on sale of subsidiary stock.......................... 329 -- --
Interest and other........................................ 183 115 106
------- ------- -------
6,366 5,270 4,735
------- ------- -------
Costs and expenses:
Oil and gas production.................................... 2,249 1,868 2,024
Mining project expenses................................... 1,014 838 459
Depreciation, depletion and amortization.................. 2,095 2,340 2,409
Impairment of oil and gas properties...................... 264 -- --
General and administrative................................ 1,845 1,467 1,342
Interest and other........................................ 842 433 132
------- ------- -------
8,309 6,946 6,366
------- ------- -------
Minority interest in loss of consolidated subsidiary........ 266 -- --
------- ------- -------
Loss before extraordinary item.............................. (1,677) (1,676) (1,631)
Extraordinary loss on early retirement of debt.............. (160) (253) --
------- ------- -------
Net loss.................................................... (1,837) (1,929) (1,631)
Dividends on preferred stock and accretion.................. (376) (360) (258)
Gain on redemption of preferred stock....................... 3,743 -- --
------- ------- -------
Net income (loss) attributable to common shareholders....... $ 1,530 $(2,289) $(1,889)
======= ======= =======
Per share:
Loss attributable to common shareholders before
extraordinary item...................................... $ (0.82) $ (1.05) $ (0.99)
Extraordinary loss........................................ (0.06) (0.13) --
------- ------- -------
Net loss attributable to common shareholders.............. $ (0.88) $ (1.18) $ (0.99)
======= ======= =======
Weighted average common shares outstanding.................. 2,512 1,947 1,916
======= ======= =======
</TABLE>

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

F-4
<PAGE> 54

MALLON RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
SERIES A
PREFERRED STOCK COMMON STOCK ADDITIONAL
------------------ ----------------- PAID-IN ACCUMULATED
SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT TOTAL
---------- ------ --------- ------ ---------- ----------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1993...... 1,100,918 $5,730 1,899,743 $19 $38,604 $(29,324) $15,029
Employee stock options
exercised................... -- -- 1,250 -- -- -- --
Stock issued to directors..... -- -- 769 -- 11 -- 11
Stock issued for property and
equipment................... -- -- 16,675 -- 300 -- 300
Employee stock options
granted..................... -- -- -- -- 32 -- 32
Other......................... -- -- -- -- 66 -- 66
Dividends on preferred
stock....................... -- -- -- -- (228) -- (228)
Accretion of preferred
stock....................... -- -- -- -- -- (30) (30)
Net loss...................... -- -- -- -- -- (1,631) (1,631)
---------- ------ --------- --- ------- -------- -------
Balance, December 31, 1994...... 1,100,918 5,730 1,918,437 19 38,785 (30,985) 13,549
Employee stock options
exercised................... -- -- 1,250 -- -- -- --
Stock issued to directors..... -- -- 1,539 -- 12 -- 12
Stock issued for property..... -- -- 14,000 -- 112 -- 112
Stock issued for loan fees.... -- -- 15,000 -- 112 -- 112
Employee stock options
granted..................... -- -- -- -- 89 -- 89
Issuance of warrants.......... -- -- -- -- 175 -- 175
Dividends on preferred
stock....................... -- -- -- -- (320) -- (320)
Accretion of preferred
stock....................... -- -- -- -- -- (40) (40)
Net loss...................... -- -- -- -- -- (1,929) (1,929)
---------- ------ --------- --- ------- -------- -------
Balance, December 31, 1995...... 1,100,918 $5,730 1,950,226 $19 $38,965 $(32,954) $11,760
Employee stock options
exercised................... -- -- 10,570 -- -- -- --
Stock issued to directors..... -- -- 2,016 -- 12 -- 12
Stock issued to consultants... -- -- 121,750 2 792 -- 794
Employee stock options
granted..................... -- -- -- -- 306 -- 306
Issuance of common stock in
public offering............. -- -- 2,300,000 23 13,166 -- 13,189
Purchase of Series A preferred
stock....................... (1,100,918) (5,730) -- -- 3,743 -- (1,987)
Other......................... -- -- -- -- 43 -- 43
Dividends on preferred
stock....................... -- -- -- -- (320) -- (320)
Accretion of preferred
stock....................... -- -- -- -- -- (56) (56)
Net loss...................... -- -- -- -- -- (1,837) (1,837)
---------- ------ --------- --- ------- -------- -------
Balance, December 31, 1996...... -- $ -- 4,384,562 $44 $56,707 $(34,847) $21,904
========== ====== ========= === ======= ======== =======
</TABLE>

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

F-5
<PAGE> 55

MALLON RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
---------------------------
1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
Cash flows from operating activities:
Net loss.................................................. $(1,837) $(1,929) $(1,631)
Adjustments to reconcile net loss to net cash provided by
(used in) operating activities:
Amortization of deferred revenues....................... -- (1,420) (2,366)
Depreciation, depletion and amortization................ 2,095 2,340 2,409
Impairment of oil and gas properties.................... 264 -- --
Minority interest in loss of consolidated subsidiary.... (266) -- --
Gain on sale of subsidiary stock........................ (329) -- --
Stock compensation expense.............................. 327 101 43
Termination of volumetric production payment............ -- (5,586) --
Gain on termination of volumetric production payment.... -- (355) --
Non-cash portion of extraordinary loss.................. 160 90 --
Write-off of notes receivable-related parties........... 46 -- --
Other................................................... -- (8) --
Changes in operating assets and liabilities:
Increase in:
Accounts receivable................................. (1,443) (328) (257)
Inventory and other current assets.................. (176) (77) (100)
Increase (decrease) in:
Trade accounts payable and undistributed revenue.... 890 183 1,549
Accrued taxes and expenses.......................... 28 28 14
Drilling advances................................... (118) 64 104
------- ------- -------
Net cash used in operating activities....................... (359) (6,897) (235)
------- ------- -------
Cash flows from investing activities:
Increase in short-term investments........................ (2,786) -- --
Additions to property and equipment....................... (4,109) (3,820) (2,079)
Proceeds from sale of subsidiary stock.................... 372 -- --
Increase in notes receivable-related parties.............. -- (20) (2)
------- ------- -------
Net cash used in investing activities....................... (6,523) (3,840) (2,081)
------- ------- -------
Cash flows from financing activities:
Proceeds from long-term debt.............................. 10,570 10,000 --
Payments of long-term debt................................ (17,324) (3) (31)
Payments on net profits interest.......................... -- -- (2,075)
Issuance of preferred stock, net of issuance costs........ -- -- 3,774
Issuance of preferred stock in subsidiary, net of issuance
costs................................................... -- 2,275 --
Debt issue costs paid..................................... (83) (159) --
Issuance of warrants...................................... -- 125 --
Net proceeds from sale of common stock in public
offering................................................ 13,189 -- --
Purchase of Series A preferred stock...................... (1,987) -- --
Net proceeds from sale of subsidiary special warrants..... 4,339 -- --
Payment of preferred dividends............................ (320) (320) (228)
------- ------- -------
Net cash provided by financing activities................... 8,384 11,918 1,440
------- ------- -------
Net increase (decrease) in cash and cash equivalents........ 1,502 1,181 (876)
Cash and cash equivalents, beginning of year................ 1,269 88 964
------- ------- -------
Cash and cash equivalents, end of year...................... $ 2,771 $ 1,269 $ 88
======= ======= =======
Supplemental cash flow information:
Cash paid for interest.................................... $ 837 $ 525 $ 175
======= ======= =======
Non-cash transactions:
Issuance of common stock in exchange for:
Property and equipment................................ $ -- $ 112 $ 300
Loan origination fee.................................. $ -- $ 112 $ --
Consultants' accounts payable......................... $ 794 $ -- $ --
Issuance of warrants for loan origination fee........... $ -- $ 50 $ --
Acquisition of equipment under capital lease............ $ -- $ 63 $ --
Acquisition of Red Rock Ventures, Inc. for subsidiary
common stock and notes payable......................... $ 2,230 $ -- $ --
</TABLE>

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

F-6
<PAGE> 56

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

NOTE 1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION AND NATURE OF OPERATIONS:

Mallon Resources Corporation (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"). The Company also has interests in gold and silver
exploration through its majority-owned subsidiary, Laguna Gold Company
("Laguna"). 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. Mining operations, conducted through Laguna in Costa Rica,
are in the pre-production stage.

REVERSE STOCK SPLIT:

On September 9, 1996, a four-to-one reverse stock split of the Company's
issued and outstanding shares of common stock was effected. Common stock,
paid-in capital and earnings per share information have been restated to give
retroactive effect to the reverse stock split.

PRINCIPLES OF CONSOLIDATION:

The consolidated financial statements include the accounts of Mallon Oil,
Laguna, and all of their 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. Short-term
investments include U.S. Treasury bills and notes with maturities greater than
ninety days, but not exceeding one year.

FAIR VALUE OF FINANCIAL INSTRUMENTS:

The Company's on-balance sheet financial instruments consist of cash, cash
equivalents, short-term investments, accounts 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, 1996 and 1995, 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 off-balance sheet
financial instruments consist of derivative instruments which are intended to
manage commodity price risk (see Note 12).

INVENTORIES:

Inventories, which consist of oil and gas lease and well equipment, and
mining materials and supplies, 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. All such costs are accumulated in
two cost centers, the continental United States and offshore Belize.

F-7
<PAGE> 57

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

Proceeds on disposal of properties are ordinarily accounted for as
adjustments of capitalized costs, with no profit or loss recognized, unless such
adjustment would significantly alter the relationship between capitalized costs
and proved oil and gas reserves. Costs capitalized, net of accumulated
depreciation, depletion and amortization, cannot exceed the estimated future net
revenues, net of the related income tax effects, discounted at 10%, of the
Company's proved reserves.

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, 1996 and 1995,
estimated salvage values equaled or exceeded estimated abandonment costs.

MINERAL PROPERTIES AND EQUIPMENT:

The Company expenses general prospecting costs and the costs of acquiring
and exploring unevaluated mining properties. When it appears likely that a
mineral property can be economically developed, the costs incurred to develop
such property, including costs to further delineate the ore body, are
capitalized. When commercially profitable ore reserves are developed and
operations commence, deferred costs will be amortized using the
units-of-production method. Upon abandonment or sale of projects, all
capitalized costs relating to the specific project are expensed in the year
abandoned or sold and any gain or loss is recognized.

Mining equipment is depreciated using the units-of-production method,
except during suspended operations. When not in production, this equipment is
depreciated at approximately 2% per year.

OTHER PROPERTY AND EQUIPMENT:

Other property and equipment is recorded at cost and depreciated over the
estimated useful lives (three to seven 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.

IMPAIRMENT OF LONG-LIVED ASSETS:

In the fourth quarter of 1995, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of". SFAS No. 121
prescribes 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, and an estimate of future undiscounted net cash flows is less than
the carrying amount of the asset. Impairment is recorded based on an estimate of
future discounted net cash flows. The adoption of SFAS No. 121 had no effect on
the Company's financial position or results of 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.

F-8
<PAGE> 58

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

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 purchaser is considered
minimal and the Company does not 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.

DEFERRED REVENUES:

Revenues received in advance of production are classified as deferred
revenue. The deferred revenue is amortized as production and delivery occur.

STOCK-BASED COMPENSATION:

As required, the Company adopted SFAS No. 123, "Accounting for Stock-Based
Compensation" in 1996. As permitted under SFAS No. 123, the Company has elected
to continue to measure compensation cost using the intrinsic value based method
of accounting prescribed by APB Opinion No. 25, "Accounting for Stock Issued to
Employees." The Company has made pro forma disclosures of net income and
earnings per share as if the fair value based method of accounting as defined in
SFAS No. 123 had been applied (see Note 10).

FOREIGN CURRENCY TRANSLATION:

Management has determined that the U.S. dollar is the functional currency
for the Company's Costa Rican operations. Accordingly, the assets, liabilities
and results of operations of the Costa Rican subsidiaries are measured in U.S.
dollars. Transaction gains and losses are not material for any of the periods
presented.

HEDGING ACTIVITIES:

The Company's use of derivative financial instruments is limited to
management of commodity price risk. Gains and losses on such transactions are
matched to product sales and charged or credited to oil and gas sales when the
hedged commodity is sold (see Note 12).

PER SHARE DATA:

Per share data is calculated using the weighted average number of common
shares and common share equivalents outstanding during each period. Common share
equivalents are excluded from the calculation in loss periods because they are
anti-dilutive. The Company had losses in 1994, 1995 and for the first three
quarters of 1996. The gain on the redemption of the Series A Convertible
Preferred Stock (the "Series A Stock") in the fourth quarter of 1996 resulted in
net income attributable to common shareholders for the quarter and the year
ended December 31, 1996. Consequently, the Series A Stock, which is a common
stock equivalent, is included in the per share calculation as if converted on
October 1, 1996 and outstanding through the redemption date. However, because
the Series A Stock is reflected as if converted, the gain on redemption is
deducted from net income attributable to common shareholders for purposes of
calculating per share data, resulting in a net loss attributable to common
shareholders for the year ended December 31, 1996 of $2,213,000.

F-9
<PAGE> 59

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

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 and mineral reserves, fair value of financial
instruments, future cash flows associated with long-lived assets, valuation
allowance for deferred tax assets, and useful lives for 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 and the mining
businesses (including operating risks and hazards and the regulations imposed
thereon), risks and uncertainties related to the volatility of the prices of oil
and gas and minerals, uncertainties related to the estimation of reserves of oil
and gas and minerals and the value of such reserves, the effects of competition
and extensive environmental regulation, the uncertainties related to foreign
operations, 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 years' amounts in the consolidated financial statements have
been reclassified to conform to the presentation used in 1996 and 1997.

NOTE 2. OIL AND GAS PROPERTIES

During 1995, the Company's oil and gas activities were conducted entirely
in the United States. In 1996, Mallon Oil 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 capitalized costs of approximately $264,000.
Subsequent to December 31, 1996, the joint venture drilled a dry hole.
Accordingly, the Company reduced the carrying amount of its capitalized costs by
$264,000 at December 31, 1996. This amount is reflected as impairment of oil and
gas properties in the Company's consolidated statements of operations.

NOTE 3. LAGUNA GOLD COMPANY

Laguna's principal precious metals property is the Rio Chiquito project
located in Guanacaste Province, Costa Rica, where it holds exploration and
exploitation concessions. The project was initially owned 90% by Laguna and 10%
by Red Rock Ventures, Inc. ("Red Rock"). As discussed below, Laguna purchased
Red Rock in 1996 and now owns 100% of the project.

At December 31, 1995, the Company owned all of the issued and outstanding
shares of Laguna's common stock. In June 1995, the Company privately placed
25,000 shares of Laguna's Series A Convertible Preferred Stock (the "Laguna
Series A Stock") for net proceeds of $2,275,000. After the Laguna Series A Stock
placement, the Company's share of Laguna was reduced from 100% to 80%.

In May 1996, Laguna sold 5,000,000 Special Warrants for $1.00 per Warrant
in a private placement for proceeds of $4,339,000, net of offering costs of
$661,000. As discussed below, in September 1996, the Special Warrants were
registered with the Ontario (Canada) Securities Commission.

F-10
<PAGE> 60

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

In June 1996, Laguna acquired Red Rock for 2,000,000 shares of Laguna's
common stock, valued at $1.00 per share, and Convertible Secured Promissory
Notes in the aggregate principal amount of $230,000, for a total consideration
of $2,230,000. The notes bear interest at 5% per annum. Principal and accrued
interest are due December 31, 2000. The notes are convertible into shares of
Laguna's common stock, at the holder's option. The initial conversion price,
which is subject to anti-dilution adjustments, is $1.10. The note is
collateralized by a general security agreement encumbering all of the assets of
Laguna. Red Rock's sole asset at the time of the merger was a 10% interest in
the Rio Chiquito gold project, in which Laguna held a 90% interest and now holds
100%. After the issue of the 2,000,000 shares of Laguna's common stock to Red
Rock, the Company's share of Laguna was reduced from 80% to 72%. The acquisition
was accounted for as a purchase.

In September 1996, Laguna completed the registration of the sale of the
Special Warrants with the Ontario (Canada) Securities Commission. The completion
of this registration caused the conversion of all of the 25,000 outstanding
shares of the Laguna Series A Stock into 3,600,000 shares of common stock. Also
in September 1996, the Company sold 400,000 of its shares of Laguna common stock
and realized a gain of $329,000. After the conversion of the Special Warrants
into Laguna common stock and the sale by the Company of Laguna common stock, the
Company owned 14,000,000 of Laguna's 25,000,000 shares of issued and outstanding
common stock, or 56%. Laguna's common stock is listed on The Toronto Stock
Exchange. Approximately 8,400,000 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.

NOTE 4. NOTES PAYABLE AND LONG-TERM DEBT

In February 1995, the Company established a $2,500,000 line of credit
pursuant to a loan agreement with three private investors. Borrowings under this
line bore interest at 11%. In August 1995, the Company established a $15,000,000
revolving line of credit facility with a commercial bank, which bore interest at
the London Interbank Offered Rate (LIBOR) plus 2.5% (8% at December 31, 1995).
The proceeds from this facility were used to retire the Company's previous
$2,500,000 line of credit and to terminate its volumetric production payment
(see Note 6). The Company paid a $125,000 prepayment penalty in order to retire
the $2,500,000 line of credit, and such amount, along with the remaining
unamortized loan origination fees of the initial line of credit, is included in
the $253,000 extraordinary loss on early retirement of debt for the year ended
December 31, 1995. As a part of the fee for the $15,000,000 facility, the
Company issued warrants, valued at $2.00 each, to purchase 25,000 shares of the
Company's common stock at a price of $10 per share. At December 31, 1995, the
total amount outstanding under the facility was $10,000,000.

In March 1996, the Company established a $35,000,000 credit facility (the
"Facility") with Bank One, Texas, N.A. (the "Bank"). The significant terms of
the Facility, as it has been amended, are as follows:

- 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, at June 30 and December 31, or at such other times as the
Bank may determine.

- The interest rate on amounts drawn under the Revolver is, at the
Company's election, either the Bank's base rate plus 0.75%, or LIBOR plus
2.5% (7.875% as of December 31, 1996). Amounts outstanding under the
Drilling Line bear interest at the greater of 12.5% or the Bank's base
rate plus 4%.

- A monthly reduction in the commitment under the Revolver, subject to
borrowing base redeterminations, is required. However, debt service
payments equal to the amount of the monthly reduction are not required
unless the balance outstanding under the Facility exceeds the reduced
commitment amount.

F-11
<PAGE> 61

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

- Amounts drawn under the Drilling Line are repayable from 100% of the net
revenues generated by wells drilled with such funds. If the borrowing
base under the Revolver increases, such additional amounts must be
borrowed and used to reduce amounts outstanding under the Drilling Line.
Once repaid, amounts drawn under the Drilling Line may not be reborrowed.

- The Company paid the bank a $50,000 fee in connection with the Facility
and must pay a fee of 0.375% per annum on the daily average of the unused
amount of the borrowing base. If the borrowing base is increased, the
Company will pay a fee of 0.50% per annum of the amount of such increase
over the previously established borrowing base. A commitment fee of 0.75%
per annum was payable on the unused portion of the Drilling Line.

- The Facility is collateralized by substantially all of the Company's oil
and gas properties.

- 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 Company is restricted
with respect to additional debt, payment of cash dividends on common
stock, loans or advances to others, certain investments, sale or discount
of receivables, hedging transactions, sale of assets and transactions
with affiliates.

- The Facility expires on March 31, 1999.

Initial amounts drawn under the Revolver were used to retire the Company's
prior line of credit and related accrued interest. The remaining $160,000
balance of unamortized loan origination fees on the prior line of credit was
written off and is reflected as extraordinary loss on early retirement of debt
for the year ended December 31, 1996. The initial borrowing base under the
Revolver was $10,500,000. At June 30, 1996, the borrowing base was redetermined
and reduced to $8,820,000. At the time of this redetermination, the amount
outstanding under the Revolver was $10,231,000, or $1,411,000 in excess of the
redetermined borrowing base. Under the terms of the Facility, as amended, the
Company drew $2,000,000 under the Drilling Line and applied it to reduce amounts
outstanding under the Revolver to an amount less than 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 Company's common
stock sale (see Note 9). The outstanding balance under the Facility at December
31, 1996 is $3,269,000. Effective January 1997, the Borrowing Base was increased
to $10,000,000 and the reduction in the commitment under the Revolver was
established at $140,000 per month, beginning July 31, 1997. The Company is not
required to make debt service payments equal to the amount of the monthly
reduction in the commitment unless the outstanding balance under the Facility
exceeds the reduced commitment amount. At December 31, 1996, the Company was in
compliance with the covenants of the Facility.

NOTE 5. DRILLING ADVANCES

In 1988 the Company sold a portion of its working interest in certain gas
properties located in the East Blanco Field to a group of investors. In
conjunction with the sale, investors prepaid to the Company their share of
future drilling and completion costs. The Company has not yet expended all of
the prepaid funds, which are included in drilling advances at December 31, 1996
and 1995. The Company plans to recomplete four existing wells and install a gas
sweetening plant in 1997, which will reduce the balance of prepaid funds. Most
of the advances have been included in non-current liabilities at December 31,
1996 and 1995.

NOTE 6. DEFERRED REVENUE

In connection with its September 1993 acquisition of producing oil and gas
properties, the Company sold a volumetric production payment burdening the
Company's interest in the acquired properties for net proceeds of $10,000,000.
The proceeds received were recorded as deferred revenue. The production payment
covered approximately 4,354,000 MMBtu of natural gas at an indicated average
price of $1.65 and 215 MBbls barrels

F-12
<PAGE> 62

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

of oil at an indicated average price of $13.01 per barrel to be delivered over
eight years. The Company was responsible for production costs associated with
operating the properties subject to the production payment agreement. In August
1995, the volumetric production payment was terminated and the Company paid a
settlement of $5,586,000 to Enron Reserve Acquisition Corp. This settlement
resulted in a $355,000 gain to the Company for the year ended December 31, 1995.

NOTE 7. COMMITMENTS AND CONTINGENCIES

OPERATING LEASES:

The Company leases office space, vehicles and software under non-cancelable
leases which expire in 2002. Rental expense is recognized on a straight-line
basis over the terms of the leases. The total minimum rental commitments at
December 31, 1996 are as follows:

<TABLE>
<CAPTION>
(IN THOUSANDS)
<S> <C>
1997........................................................ $ 130
1998........................................................ 170
1999........................................................ 141
2000........................................................ 141
2001........................................................ 141
Thereafter.................................................. 23
--------------
$ 746
==============
</TABLE>

Rent expense was $125,000, $83,000 and $74,000 for the years ended December
31, 1996, 1995 and 1994, respectively.

CONTINGENCIES:

In 1993, the Minerals Management Service commenced an audit of royalties
payable on certain oil and gas properties in which the Company owns an interest.
The operator of the properties contested certain deficiencies. In March 1997,
the matter was resolved in the operator's favor.

NOTE 8. 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 bears an 8% dividend
payable quarterly, and is convertible into shares of the Company's common stock
at an adjusted conversion price of $11.31 per share. Mandatory redemption of
this stock begins on April 15, 1997, when 20% of the total outstanding shares is
redeemable. An additional 20% per year will be redeemed on each April 15
thereafter until all $4,000,000 of the Series B Stock has been redeemed.
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 $320,000, $320,000
and $228,000 were paid in 1996, 1995 and 1994, respectively. Accretion of
preferred stock issue costs was $56,000, $40,000 and $30,000 in 1996, 1995 and
1994, respectively.

Mandatory redemption of the Company's Series B Stock was to begin in April
1997, when 20% of the outstanding shares, or 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.

F-13
<PAGE> 63

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

NOTE 9. 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.

In October 1996, the Company purchased all of the 1,100,918 shares
outstanding at December 31, 1995 of the Company's Series A Convertible Preferred
Stock from Bank of America National Savings and Trust Association for a purchase
price of approximately $1,886,000. In connection with the purchase, the Company
also paid fees and expenses of $101,000. The difference between the carrying
value of the Series A Stock and the purchase price was credited to additional
paid-in capital.

COMMON STOCK:

The Company has reserved approximately 353,670 shares of common stock for
issuance upon possible conversion of the Series B Stock.

In October 1996, the Company sold 2,300,000 shares of its common stock in a
public offering at $6.50 per share. The Company received proceeds of
approximately $13,189,000, net of offering costs of $1,761,000. The net proceeds
will be used primarily to finance the drilling and development of the Company's
New Mexico oil and gas properties and a portion was used to retire all
outstanding shares of its Series A Convertible Preferred Stock (see above). In
connection with the public offering, the Company issued to the underwriters a
warrants to purchase 160,000 shares of the Company's common stock at $7.80 per
share at any time between October 16, 1997 and October 16, 1999.

As discussed in Note 3, Laguna issued 25,000 shares of Series A Stock in
June 1995. Each share of Laguna Series A Stock included detachable warrants to
purchase shares of the Company's common stock. At December 31, 1996, the Company
had reserved approximately 76,590 shares of common stock, at an adjusted
exercise price of $8.16 per share, for issuance upon possible exercise of the
warrants. The warrants expire in June 2000.

NOTE 10. STOCK COMPENSATION

At December 31, 1996, the Company had three stock-based compensation plans,
including one for Laguna. 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, "Accounting for Stock
Issued to Employees". Under that method, the difference between the exercise
price and the estimated 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 $327,000, $101,000 and $43,000 for 1996, 1995
and 1994, respectively.

Under the Mallon Resources Corporation 1988 Equity Participation Plan (the
"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
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 Equity Plan. The options vest over a
period of up to four years and expire over a maximum of ten years from the date
of grant.

Under the Laguna Gold Company Equity Participation Plan (the "Laguna Equity
Plan"), shares of Laguna common stock have been reserved for issuance in order
to provide for incentive compensation and awards to employees and consultants.
The number of shares reserved is the lesser of 10% of the number of

F-14
<PAGE> 64

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

shares of Laguna common stock outstanding from time to time, or 8,000,000
shares. The Laguna Equity Plan provides that stock options, stock bonuses, stock
appreciation rights and other forms of stock-based compensation may be granted
in accordance with the provisions of the Plan. The options vest over a period of
up to four years, and expire over a maximum of ten years from the date of grant.
The options vest in full if controlling interest in Laguna or substantially all
of its assets are sold, or if Laguna is merged into another company, or if
control of Laguna's Board is obtained by a person or persons not expressly
approved by a majority of the members of the Board. To date, no options have
been exercised.

The following table summarizes activity with respect to the outstanding
stock options under the Equity Plan and the Laguna Equity Plan:

<TABLE>
<CAPTION>
COMPANY LAGUNA
------------------------- ---------------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE
SHARES EXERCISE PRICE SHARES EXERCISE PRICE
------- -------------- --------- --------------
<S> <C> <C> <C> <C>
Outstanding at December 31, 1993......... 45,155 $0.04 -- $ --
Granted................................ 17,250 0.04 -- --
Exercised.............................. (1,250) 0.04 -- --
Forfeited.............................. (60) 0.04 -- --
------- ----- --------- -----
Outstanding at December 31, 1994......... 61,095 0.04 -- --
Granted................................ -- -- 1,620,000 0.01
Exercised.............................. (1,250) -- -- --
Forfeited.............................. -- -- -- --
------- ----- --------- -----
Outstanding at December 31, 1995......... 59,845 0.04 1,620,000 0.01
Granted................................ 21,944 0.04 880,000 1.00
Exercised.............................. (10,570) 0.04 -- --
Forfeited.............................. (1,643) -- -- --
------- ----- --------- -----
Outstanding at December 31, 1996......... 69,576 $0.04 2,500,000 $0.36
======= ===== ========= =====
</TABLE>

The weighted average remaining contractual life of the options outstanding
under the Equity Plan and the Laguna Equity Plan at December 31, 1996 is
approximately 7 years and 8.5 years, respectively.

Included in the amounts above are 19,500 options exercisable at $.04 per
share and expiring in 10 years, granted under the Equity Plan in June 1990, that
do not vest until the market price of the Company's common stock exceeds certain
prices ranging from $32.00 to $48.00, for more than 120 consecutive days. When
the stock reaches the required price levels for vesting, the Company will accrue
compensation expense based on the difference between the market price of the
stock at that date and the exercise price. No compensation expense was recorded
for these options during the years ended December 31, 1996, 1995 and 1994.

In 1992, the Company granted to a consultant options to purchase 12,500 of
the Company's common shares at $26 per share, exercisable from November 1993
through October 1997. In 1994, the Company

F-15
<PAGE> 65

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

granted this individual an additional 6,250 options to purchase the Company's
shares at $16 per share, exercisable from January 1995 to December 1998. All of
the 18,750 options granted are outstanding at December 31, 1996. These options
are not part of the Equity Plan.

The Stock Compensation Plan for Outside Directors provides that the
Company's outside directors will be compensated by periodically granting them
shares of the Company's $0.01 par value common stock worth $1,000 for each board
meeting, but no less than $4,000 per year, for each outside director. The
Company expensed $12,000, $12,000 and $11,000 for the years 1996, 1995 and 1994,
respectively, in relation to the Stock Compensation Plan.

Had compensation expense for the Company's 1996 and 1995 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>
1996 1995
----------------------- -----------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA
----------- --------- ----------- ---------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Net loss................................... $(1,837) $(1,869) $(1,929) $(1,840)
Net income (loss) attributable to common
shareholders (See Note 1)................ 1,530 1,498 (2,289) (2,200)
Net loss per share attributable to common
shareholders............................. (0.88) (0.89) (1.18) (1.13)
</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>
1996 1995
----------------- -----------------
COMPANY LAGUNA COMPANY LAGUNA
------- ------ ------- ------
<S> <C> <C> <C> <C>
Risk-free interest rate............................ 5.8% 6.5% N/A 7.6%
Expected life (in years)........................... 4 4 N/A 4
Expected volatility................................ 61.0% 76.0% N/A 0.0%
Expected dividends................................. 0.0% 0.0% N/A 0.0%
Weighted average fair value of options granted..... $1.66 $0.52 N/A $0.11
</TABLE>

NOTE 11. 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, 1996, 1995
and 1994, the Company made matching contributions of $16,000, $13,000 and
$8,000, respectively. No discretionary contributions were made during any of the
three years ended December 31, 1996.

The Company maintains a program which provides bonus compensation to
employees from lease 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,
1996, 1995 and 1994, a total of $74,000, $69,000 and $59,000, respectively, was
distributed to employees.

F-16
<PAGE> 66

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

NOTE 12. HEDGING ACTIVITIES

The Company is exposed to off-balance-sheet risks associated with energy
swap agreements at December 31, 1996 arising from movements in the prices of oil
and natural gas and from the unlikely event of non-performance by the
counterparty to the swap agreements.

In order to hedge against the effects of declines in oil and natural gas
prices, the Company enters into energy swap agreements with third parties and
accounts for the agreements as hedges based on analogy to the criteria set forth
in SFAS No. 80, "Accounting for Futures Contracts". In a typical swap agreement,
the Company receives the difference between a fixed price per unit of production
and a price based on an agreed-upon third party index if the index price is
lower. If the index price is higher, the Company pays the difference. The
Company's current swaps are settled on a monthly basis.

The following table indicates the Company's outstanding energy swaps at
December 31, 1996:

<TABLE>
<CAPTION>
MARKET PRICE
PRODUCT PRODUCTION FIXED PRICE DURATION REFERENCE
------- ---------- ----------- ---------- ------------
<S> <C> <C> <C> <C>
Oil.................. 9,000 Bbls/month $23.36 - 19.99 1/97-12/97 NYMEX WTI
Gas.................. 60,000 MMBtu/month $ 2.54 - 1.62 1/97-12/97 El Paso Natural Gas (Permian)
Gas.................. 30,000 MMBtu/month $ 2.42 - 1.50 1/97-12/97 El Paso Natural Gas (San Juan)
</TABLE>

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, and are included in oil and gas sales in the Company's
consolidated statements of operations. At December 31, 1996, the estimated net
amount the Company would have had to pay to terminate the agreements was
approximately $299,000.

NOTE 13. MAJOR CUSTOMERS

Sales to customers in excess of 10% of total revenues for the years ended
December 31, 1996, 1995 and 1994 were:

<TABLE>
<CAPTION>
1996 1995 1994
------ ------ ------
(IN THOUSANDS)
<S> <C> <C> <C>
Customer A.................................................. $ -- $2,213 $2,579
Customer B.................................................. -- -- 298
Customer C.................................................. -- 1,319 573
Customer D.................................................. 1,750 -- --
Customer E.................................................. 1,513 -- --
</TABLE>

F-17
<PAGE> 67

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

NOTE 14. 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, 1996, 1995 or 1994.

Deferred tax assets (liabilities) are comprised of the following as of
December 31, 1996 and 1995:

<TABLE>
<CAPTION>
1996 1995
------- -------
(IN THOUSANDS)
<S> <C> <C>
Deferred Tax Assets (Liabilities):
Net operating loss carryforward........................... $ 6,019 $ 4,996
Other..................................................... 308 170
------- -------
Total deferred tax assets.......................... 6,327 5,166
------- -------
Mining properties basis differences....................... (1,686) (1,784)
Oil, gas and other properties basis differences........... (1,285) (1,600)
------- -------
Total deferred tax liabilities..................... (2,971) (3,384)
------- -------
Net deferred tax assets................................... 3,356 1,782
Less valuation allowance.................................. (3,356) (1,782)
------- -------
Net deferred tax assets (liabilities).............. $ -- $ --
======= =======
</TABLE>

At December 31, 1996, for U.S. Federal income tax purposes, the Company had
a net operating loss ("NOL") carryforward of approximately $16,100,000, which
expires in varying amounts between 2005 and 2011. This NOL carryforward is in
addition to net operating losses arising from the operations of Laguna prior to
1989 which can be utilized only to the extent of Laguna's future taxable income.

NOTE 15. SEGMENT INFORMATION

The Company operates in two business segments: oil and gas exploration and
production primarily in the United States, and gold and silver mining primarily
in Costa Rica. Information regarding total assets by business segment and
geographic location for the Company as of December 31, 1996, 1995, and 1994 is
as follows:

<TABLE>
<CAPTION>
1996 1995 1994
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Total assets:
Oil and gas............................................... $29,044 $24,791 $23,746
Mining.................................................... 12,356 6,844 4,480
------- ------- -------
$41,400 $31,635 $28,226
======= ======= =======
United States............................................... $31,824 $25,867 $23,777
Costa Rica and other...................................... 9,576 5,768 4,449
------- ------- -------
$41,400 $31,635 $28,226
======= ======= =======
</TABLE>

F-18
<PAGE> 68

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

The following tables summarize the Company's revenues, operating loss,
depreciation, depletion and amortization and capital expenditures by business
segment for the years ended December 31, 1996, 1995, and 1994:

<TABLE>
<CAPTION>
1996 1995 1994
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Revenues:
Oil and gas............................................... $ 6,236 $ 5,270 $ 4,735
Mining.................................................... 130 -- --
------- ------- -------
$ 6,366 $ 5,270 $ 4,735
======= ======= =======
Operating loss:
Oil and gas............................................... $ (304) $(1,176) $(1,427)
Mining.................................................... (1,130) (500) (204)
------- ------- -------
$(1,434) $(1,676) $(1,631)
======= ======= =======
Depreciation, depletion and amortization:
Oil and gas............................................... $ 2,016 $ 2,288 $ 2,373
Mining.................................................... 79 52 36
------- ------- -------
$ 2,095 $ 2,340 $ 2,409
======= ======= =======
Capital expenditures:
Oil and gas............................................... $ 2,473 $ 2,736 $ 2,242
Mining.................................................... 3,866 1,259 137
------- ------- -------
$ 6,339 $ 3,995 $ 2,379
======= ======= =======
</TABLE>

The following tables summarize the Company's revenues and net loss by
geographic area for the years ended December 31, 1996, 1995 and 1994:

<TABLE>
<CAPTION>
1996 1995 1994
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Revenues:
United States............................................. $ 6,366 $ 5,270 $ 4,735
Costa Rica and other...................................... -- -- --
------- ------- -------
$ 6,366 $ 5,270 $ 4,735
======= ======= =======
Net loss:
United States............................................. $ (702) $(1,800) $(1,427)
Costa Rica and other...................................... (1,135) (129) (204)
------- ------- -------
$(1,837) $(1,929) $(1,631)
======= ======= =======
</TABLE>

NOTE 16. RELATED PARTY TRANSACTIONS

The accounts receivable from related parties consists primarily of joint
interest billings to directors, officers, shareholders, employees and affiliated
entities for drilling and operating costs incurred on oil and gas properties in
which these related parties participate with Mallon Oil and Mallon Oil
partnerships as working interest owners. These amounts will generally be settled
in the ordinary course of business, without interest.

Notes receivable of $63,000 at December 31, 1995 consist of loans to
employees, which bear interest at prime plus 2%. Notes receivable and accrued
interest of $46,000 were written off in 1996.

Certain oil and gas properties located in Alabama, in which the Company has
working interests, are operated by a company owned by an individual who also
owns, beneficially, less than 3% of the Company's outstanding common stock at
December 31, 1996, but in excess of 5% of such stock at December 31, 1995. As

F-19
<PAGE> 69

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

of December 31, 1996 and 1995, the Company had a payable to the related company
of $35,000 and $25,000, respectively, which is included in other long-term
accrued expenses and accounts payable at December 31, 1996 and 1995,
respectively. In addition, at December 31, 1996, the Company has a receivable of
$135,000 from this company, which is recorded in other long-term assets in the
consolidated balance sheet.

Red Rock was owned, in part, by an estate that owned, beneficially, less
than 5% of the Company's outstanding common stock at December 31, 1996 but in
excess of 5% of such stock at December 31, 1995. The Company had payables to the
shareholder of $-0- and $100,000 as of December 31, 1996 and 1995, respectively,
which are included in accounts payable in the consolidated balance sheet. See
Note 3 regarding the acquisition of Red Rock by Laguna.

During the years ended December 31, 1996 and 1995, the Company paid legal
fees of $2,000 and $31,000, respectively, to a law firm of which a director of
the Company is a senior partner. Additionally, in 1994, consulting fees valued
at $300,000 were paid to a member of the same firm in the form of 16,675 shares
of the Company's common stock. In January 1995, an additional 14,000 shares
valued at $112,000 were issued for services to the same individual. Also in
1995, fees of $32,000 were paid to this individual.

In February 1995, the Company entered into a Loan Agreement establishing a
$2,500,000 line of credit facility pursuant to which it could borrow funds from
three entities, two of which are affiliates of an individual who owns,
beneficially, in excess of 5% of the Company's outstanding common stock. This
line of credit was retired in August 1995.

The Company had a consulting agreement with an investment banking firm in
which a director is a partner for investment banking services of $240,000 in
1995, of which $90,000 was payable at December 31, 1995 and paid in 1996. In
addition, in 1996, the Company paid the firm a commission and other expenses of
$101,000 in connection with the Company's purchase of its Series A Preferred
Stock.

F-20
<PAGE> 70

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

NOTE 17. SUPPLEMENTARY INFORMATION ON OIL AND GAS OPERATIONS

Certain historical costs and operating information relating to the
Company's oil and gas producing activities for the years ended December 31,
1996, 1995 and 1994 are as follows:

<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
CAPITALIZED COSTS RELATING TO OIL AND GAS ACTIVITIES:
Oil and gas properties................................... $ 46,175 $ 43,751 $ 41,127
Accumulated depreciation, depletion and amortization..... (23,361) (21,173) (19,011)
-------- -------- --------
22,814 22,578 22,116
Deferred revenues attributable to the volumetric
production payment..................................... -- -- (7,452)
-------- -------- --------
$ 22,814 $ 22,578 $ 14,664
======== ======== ========
COSTS INCURRED IN OIL AND GAS PRODUCING ACTIVITIES:
Property acquisition costs............................... $ 60 $ 131 $ 648
Termination of volumetric production payment............. -- 5,586 --
Exploration costs........................................ 264(1) 180 --
Development costs........................................ 2,138 2,379 1,736
Full cost pool credits................................... (38) (66) (142)
-------- -------- --------
$ 2,424 $ 8,210 $ 2,242
======== ======== ========
RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING
ACTIVITIES:
Oil and gas sales........................................ $ 5,854 $ 3,380 $ 2,263
Deferred revenue amortization............................ -- 1,420 2,366
Lease operating expense.................................. (2,249) (1,868) (2,024)
Depletion................................................ (1,924) (2,162) (2,330)
Impairment of oil and gas properties..................... (264)(1) -- --
-------- -------- --------
Results of operations from oil and gas producing
activities............................................. $ 1,417 $ 770 $ 275
======== ======== ========
</TABLE>

F-21
<PAGE> 71

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

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 an independent
consulting petroleum engineering firm for the years ended December 31, 1996,
1995 and 1994. 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, 1993............................... 859 22,336
Extensions, discoveries and additions................... 664 448
Production.............................................. (98) (687)
Revisions............................................... 119 (5,803)
----- ------
Reserves, December 31, 1994............................... 1,544 16,294
Acquisition of reserves in place........................ 136 2,246
Extensions, discoveries and additions................... 163 1,129
Production.............................................. (147) (546)
Revisions............................................... 117 798
----- ------
Reserves, December 31, 1995............................... 1,813 19,921
Extensions, discoveries and additions................... 75 667
Production.............................................. (174) (1,286)
Revisions............................................... (7) 4,983
----- ------
Reserves, December 31, 1996............................... 1,707 24,285
===== ======
Pro forma reserves at December 31, 1996(2)................ 1,707 28,388
===== ======
PROVED DEVELOPED RESERVES
December 31, 1994......................................... 811 11,733
===== ======
December 31, 1995......................................... 1,238 14,702
===== ======
December 31, 1996......................................... 1,225 18,403
===== ======
Pro forma at December 31, 1996(2)......................... 1,225 20,521
===== ======
</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 Statement of Financial Accounting Standards No. 69, for the years
ended December 31, 1996, 1995 and 1994:

<TABLE>
<CAPTION>
1996 1995 1994
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Future cash in-flows........................................ $129,963 $ 66,178 $ 50,964
Future production and development costs..................... (46,374) (30,522) (28,435)
Future income taxes......................................... (18,150) -- --
-------- -------- --------
Future net cash flows....................................... 65,439 35,656 22,529
Discount at 10%............................................. (29,428) (14,618) (8,771)
-------- -------- --------
Standardized measure of discounted future net cash flows,
end of year............................................... $ 36,011 $ 21,038 $ 13,758
======== ======== ========
Pro forma standardized measure of discounted future net cash
flows, end of year(2)..................................... $ 38,320
========
</TABLE>

F-22
<PAGE> 72

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEARS ENDED DECEMBER 1996, 1995 AND 1994

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 Company's oil and gas hedging
agreements at December 31, 1996, described in Note 12, do not have a material
effect on the determination of future oil and gas sales. In 1995 and 1994, the
tax basis of the oil and gas properties plus the NOL carryforward exceeded
future net revenues. Consequently, no income taxes were provided for in those
years.

The following are the principal sources of changes in the standardized
measure of discounted future net cash flows for the years ended December 31,
1996, 1995 and 1994:

<TABLE>
<CAPTION>
1996 1995 1994
------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure, beginning of year..................... $21,038 $13,758 $18,188
Net revisions to previous quantity estimates and other...... 3,266 (1,852) (4,523)
Extensions, discoveries, additions, and changes in timing of
production, net of related costs.......................... 2,204 1,631 3,959
Purchase of reserves in place............................... -- 5,701 --
Net change in future development costs...................... 580 (127) (1,065)
Sales of oil and gas produced, net of production costs...... (3,605) (1,512) (239)
Net change in prices and production costs................... 20,487 2,063 (5,341)
Accretion of discount....................................... 2,029 1,376 1,819
Net change in income taxes.................................. (9,988) -- 960
------- ------- -------
Standardized measure, end of year........................... $36,011 $21,038 $13,758
======= ======= =======
Pro forma standardized measure, end of year(2).............. $38,320
=======
</TABLE>

- ---------------

(1) Offshore Belize -- all other items relate to U.S. operations.

(2) In December 1996, the Company entered into a purchase and sale agreement to
acquire certain oil and gas properties for cash consideration of $1,300,000
(see Note 18). The Company assumed operations of those properties on
December 31, 1996 and the ownership changed on January 1, 1997. Pro forma
proved reserves include 4,103 Mmcf and pro forma proved developed reserves
include 2,118 Mmcf, and pro forma standardized measure includes $2,309,000,
as if the ownership had changed on December 31, 1996.

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 18. SUBSEQUENT EVENT

In January 1997, the Company acquired certain oil and gas properties for a
total consideration of $1,300,000 and conveyance of its interest in certain
other oil and gas properties. The cash consideration will be paid as follows:
$500,000 at closing in January 1997, and $400,000 each at January 1, 1998 and
January 1, 1999.

F-23
<PAGE> 73

MALLON RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

ASSETS

<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1997 1996
------------- ------------
(UNAUDITED)
<S> <C> <C>
Current assets:
Cash and cash equivalents................................. $ 424 $ 2,771
Short-term investments.................................... 698 2,786
Accounts receivable:
Oil and gas sales....................................... 1,006 1,879
Joint interest participants, net of allowance of $8 and
$8, respectively....................................... 1,595 827
Related parties......................................... 57 20
Other................................................... 11 45
Inventories............................................... 332 251
Other..................................................... 80 104
-------- --------
Total current assets................................ 4,203 8,683
-------- --------
Property and equipment:
Oil and gas properties, full cost method.................. 57,766 46,175
Mining properties and equipment........................... 11,348 10,114
Other equipment........................................... 708 559
-------- --------
69,822 56,848
Less accumulated depreciation, depletion and
amortization............................................ (26,308) (24,406)
-------- --------
43,514 32,442
-------- --------
Notes receivable-related parties............................ 18 17
Other, net.................................................. 347 258
-------- --------
Total Assets................................................ $ 48,082 $ 41,400
======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Trade accounts payable.................................... $ 4,512 $ 1,614
Undistributed revenue..................................... 701 1,502
Drilling advances......................................... 151 100
Accrued taxes and expenses................................ 158 77
Current portion of capital lease obligation............... 19 25
Current portion of installment obligation, less
unamortized discount of $6 and $-0-, respectively....... 394 --
-------- --------
Total current liabilities........................... 5,935 3,318
-------- --------
Long-term bank debt......................................... 8,369 3,269
Installment obligation, less unamortized discount of $27 and
$-0-, respectively........................................ 372 --
Notes payable, other........................................ 230 230
Capital lease obligation, net of current portion............ -- 12
Drilling advances........................................... 308 368
Accrued expenses............................................ 50 41
-------- --------
Total non-current liabilities....................... 9,329 3,920
-------- --------
Total liabilities........................................... 15,264 7,238
-------- --------
Commitments and contingencies
Minority interest........................................... 7,921 8,358
Series B Mandatorily Redeemable Convertible Preferred Stock,
$0.01 par value, 500,000 shares authorized, 135,200 and
400,000 shares issued and outstanding, respectively,
liquidation preference and mandatory redemption of
$1,352,000 and $4,000,000, respectively................... 1,314 3,900
Shareholders' equity:
Common Stock, $0.01 par value, 25,000,000 shares
authorized; 4,695,264 and 4,384,562 shares issued and
outstanding, respectively............................... 47 44
Additional paid in capital................................ 59,121 56,707
Accumulated deficit....................................... (35,585) (34,847)
-------- --------
Total shareholders' equity.......................... 23,583 21,904
-------- --------
Total Liabilities and Shareholders' Equity.......... $ 48,082 $ 41,400
======== ========
</TABLE>

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

F-24
<PAGE> 74

MALLON RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE
NINE MONTHS
ENDED
SEPTEMBER 30,
------------------
1997 1996
------- -------
<S> <C> <C>
Revenues:
Oil and gas sales......................................... $ 5,806 $ 4,098
Gain on sale of subsidiary stock.......................... -- 329
Interest and other........................................ 122 105
------- -------
5,928 4,532
------- -------
Costs and expenses:
Oil and gas production.................................... 2,158 1,511
Mining project expenses................................... 871 648
Depreciation, depletion and amortization.................. 1,873 1,671
Impairment of oil and gas properties...................... 59 --
General and administrative................................ 1,730 1,252
Interest and other........................................ 381 702
------- -------
7,072 5,784
------- -------
Minority interest in loss of consolidated subsidiary........ 427 92
------- -------
Loss before extraordinary item.............................. (717) (1,160)
Extraordinary loss on early retirement of debt.............. -- (160)
------- -------
Net loss.................................................... (717) (1,320)
Dividends on preferred stock and accretion.................. (155) (281)
Preferred stock conversion inducement....................... (403) --
------- -------
Net loss attributable to common shareholders................ $(1,275) $(1,601)
======= =======
Per share:
Net loss attributable to common shareholders before
extraordinary item...................................... $ (0.28) $ (0.71)
Extraordinary loss........................................ -- (0.08)
------- -------
Net loss attributable to common shareholders.............. $ (0.28) $ (0.79)
======= =======
Weighted average shares outstanding......................... 4,576 2,032
======= =======
</TABLE>

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

F-25
<PAGE> 75

MALLON RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)

<TABLE>
<CAPTION>
FOR THE NINE MONTHS
ENDED SEPTEMBER 30,
--------------------
1997 1996
-------- --------
<S> <C> <C>
Cash flows from operating activities:
Net loss.................................................. $ (717) $ (1,320)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Depreciation, depletion and amortization................ 1,873 1,671
Impairment of oil and gas properties.................... 59 --
Gain on sale of subsidiary stock........................ -- (329)
Amortization of discount on notes payable............... 33 --
Minority interest in loss of consolidated subsidiary.... (427) (92)
Stock compensation expense.............................. 111 293
Non-cash portion of extraordinary loss.................. -- 160
Write-off of notes receivable -- related parties........ -- 32
Changes in operating assets and liabilities:
(Increase) decrease in:
Accounts receivable................................ 102 123
Inventory and other assets......................... (171) (21)
Increase (decrease) in:
Trade accounts payable and undistributed revenue... 2,097 (236)
Accrued taxes and expenses......................... 89 125
Drilling advances.................................. (9) 19
-------- --------
Net cash provided by operating activities................... 3,040 425
-------- --------
Cash flows from investing activities:
Decrease (increase) in short-term investments............. 2,088 (2,814)
Additions to property and equipment....................... (12,246) (2,752)
Proceeds from sale of subsidiary stock.................... -- 372
Proceeds from sale of property and equipment.............. -- 11
Purchase of subsidiary stock.............................. (55) --
Increase (decrease) in notes receivable-related parties... (1) --
-------- --------
Net cash used in investing activities....................... (10,214) (5,183)
-------- --------
Cash flows from financing activities:
Proceeds from long-term debt.............................. 5,100 10,570
Payment of long-term debt................................. (18) (10,017)
Debt issue costs paid..................................... -- (83)
Net proceeds from sale of subsidiary special warrants..... -- 4,325
Payment of preferred dividends............................ (134) (240)
Redemption of preferred stock............................. (121) --
-------- --------
Net cash provided by financing activities................... 4,827 4,555
-------- --------
Net decrease in cash and cash equivalents................... (2,347) (203)
Cash and cash equivalents, beginning of period.............. 2,771 1,269
-------- --------
Cash and cash equivalents, end of period.................... $ 424 $ 1,066
======== ========
Supplemental cash flow information:
Cash paid for interest.................................... $ 341 $ 637
======== ========
Non-cash transactions:
Issuance of common stock in exchange for consultants'
accounts payable....................................... $ -- $ 791
======== ========
Installment obligation (less unamortized discount) in
exchange for property and equipment.................... $ 733 $ --
======== ========
Acquisition of Red Rock Ventures, Inc. for subsidiary
common stock and notes payable......................... $ -- $ 2,230
======== ========
</TABLE>

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

F-26
<PAGE> 76

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996

(UNAUDITED)

NOTE 1. GENERAL

The Company engages in oil and gas exploration and production through its
wholly-owned subsidiary, Mallon Oil Company ("Mallon Oil"). The Company also has
interests in gold and silver exploration through its majority-owned subsidiary,
Laguna Gold Company ("Laguna"). At September 30, 1997, the Company owned
approximately 56% of Laguna. 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. Mining operations, conducted through
Laguna in Costa Rica, are in the pre-production stage. All significant
intercompany balances and transactions have been eliminated from the
consolidated financial statements.

These unaudited consolidated financial statements have been prepared in
accordance with generally accepted accounting principles for interim financial
information and with the instructions to Form 10-Q and Article 10 of Regulation
S-X. Accordingly, they do not include all of the information and footnotes
required by generally accepted accounting principles for complete financial
statements. In the opinion of management, such interim statements reflect all
adjustments (consisting of normal recurring adjustments) necessary to present
fairly the financial position and the results of operations and cash flows for
the interim periods presented. The results of operations for these interim
periods are not necessarily indicative of the results to be expected for the
full year. These interim statements should be read in conjunction with the
consolidated financial statements and notes thereto included in the Company's
Annual Report on Form 10-K for the year ended December 31, 1996.

A reclassification from operating service revenue to oil and gas production
expense was made to the statements of operations for the nine months ended
September 30, 1996 to conform to the September 30, 1997 presentation. In
addition, certain reclassifications were made to the September 30, 1996
statement of cash flows to conform to the September 30, 1997 presentation.

NOTE 2. LONG-TERM BANK DEBT

Effective September 1997, the borrowing base under the Company's revolving
credit facility was increased to $10,830,000. Beginning November 30, 1997, the
borrowing base will decrease by $170,000 per month. The Company is not required
to make debt service payments unless the outstanding balance under the facility
exceeds the borrowing base, as adjusted. At September 30, 1997, the amount
outstanding under the facility was $8,369,000, leaving the amount available
under the facility at $2,461,000.

NOTE 3. OIL AND GAS PROPERTIES

In January 1997, the Company acquired certain oil and gas properties for
consideration of $1,300,000 in cash and conveyance of its interest in certain
other oil and gas properties. Cash consideration of $500,000 was paid at closing
in January 1997 and installment obligations of $400,000 will be paid on each of
January 1, 1998 and January 1, 1999. The installment obligations include an
imputed interest rate of 6%. There was no gain or loss relative to the
conveyance of the interest in the oil and gas properties.

NOTE 4. MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED STOCK

Mandatory redemption of the Company's Series B Preferred Stock (the "Series
B Stock") was to begin in April 1997, when 20% of the outstanding shares, or
80,000 shares, were to be redeemed for $800,000. The Company 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 then in effect. In April 1997, holders of 252,675
shares of Series B Stock elected to convert their shares into 280,747 shares of
the Company's common stock. The excess of the fair value of the common stock
issued at

F-27
<PAGE> 77

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996

the $9.00 conversion price over the fair value of the common stock that would
have been issued at the $11.31 conversion price, totaling $403,000, has been
reflected on the statements of operations for the six months ended June 30, 1997
as an increase to the net loss attributable to common shareholders for preferred
stock conversion inducement. In addition, the Company redeemed 12,125 shares of
Series B Stock at $10.00 per share. After these transactions, 135,200 shares of
Series B Stock remain outstanding and the Company has no further obligation to
redeem any shares until April 2000. The Series B Stock is convertible to common
stock automatically if the common stock trades at a price in excess of 140% of
the then applicable conversion price for each day in a period of 10 consecutive
trading days. The conversion price, as adjusted, is currently $11.18 per share.

NOTE 5. EARNINGS PER SHARE

In February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 128, "Earnings per Share," which
establishes new standards for computing and presenting earnings per share. The
new Statement is intended to simplify the standard for computing earnings per
share and will require the presentation of basic and diluted earnings per share
on the face of the income statement, including all prior periods presented. The
Statement is effective for financial statements issued for periods ending after
December 15, 1997, and earlier adoption is not permitted. Had the calculation of
earnings per share been prepared in accordance with the provisions of SFAS No.
128 for the nine months ended September 30, 1997 and 1996, earnings per share
would have been the same as what was reported on the consolidated statements of
operations.

NOTE 6. SHAREHOLDER RIGHTS PLAN

In April 1997, the Company's Board of Directors declared a dividend on its
shares of Common Stock (the "Common Shares") of preferred share purchase rights
(the "Rights") as part of a Shareholder Rights Plan (the "Plan"). The Plan is
designed to insure that all shareholders of the Company receive fair value for
their Common Shares in the event of a proposed takeover of the Company and to
guard against the use of partial tender offers or other coercive tactics to gain
control of the Company without offering fair value to the Company's
shareholders. 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 at this time, but the Rights
will become part of each Common Share. All Rights expire on April 22, 2001.

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 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

F-28
<PAGE> 78

MALLON RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1997 AND 1996

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 7. LAGUNA

In June 1997, pending an improvement in the financial markets, Laguna
started a program to conserve capital by curtailing its mining operations in
Costa Rica and reducing its work force. Under Costa Rican Labor Law, Laguna is
obligated to make certain payments to Costa Rican employees who are dismissed.
The Company has estimated this amount at $134,000, and has included it on the
Company's statements of operations in mining project expenses for the nine
months ended September 30, 1997. Laguna made payments of approximately $103,000
during the third quarter of 1997 related to this liability. No payments were
made in October 1997.

The value of the Company's interest in Laguna will be affected by the
business results of Laguna and by changes in the markets for gold and junior
gold mining companies. 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 not in the United States, 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.
The Company does not have any obligation or intention to finance Laguna's future
operations.

NOTE 8. COMMON STOCK OFFERING

The Company has filed a registration statement with the Securities and
Exchange Commission for a public offering of 2,300,000 shares of its common
stock. The registration statement has not yet become effective. If completed,
the net proceeds from the offering would be used to fund exploitation and
development activities and to repay indebtedness under the Company's line of
credit.

F-29
<PAGE> 79

ANNEX A

OCTOBER 16, 1997
Mallon Oil Company
999 18th Street
Suite 1700
Denver, CO 80202

Gentlemen:

At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold and royalty interests
of Mallon Oil Company ("Mallon") as of September 30, 1997. The subject
properties are located in the States of Alabama, Colorado, North Dakota, New
Mexico, Oklahoma Texas and Wyoming. The income data were estimated using the
Securities and Exchange Commission (SEC) guidelines for future cost and price
parameters.

The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. September 30, 1997 hydrocarbon prices were
used in the preparation of this report as required by SEC guidelines; however,
actual future prices may vary significantly from September 30, 1997 prices.
Therefore, volumes of reserves actually recovered and amounts of income actually
received may differ significantly from the estimated quantities presented in
this report. The results of this study are summarized below.

SEC PARAMETERS
ESTIMATED NET RESERVES AND INCOME DATA
CERTAIN LEASEHOLD AND ROYALTY INTERESTS OF
MALLON OIL COMPANY

<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1997
-----------------------------------------------------------
PROVED
-----------------------------------------------------------
DEVELOPED
--------------------------- TOTAL TOTAL
PRODUCING NON-PRODUCING UNDEVELOPED PROVED
----------- ------------- -------------- ------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate--Barrels........ 898,369 108,690 331,091 1,338,150
Gas--MMCF...................... 16,088 8,925 21,158 46,171
INCOME DATA
Future Gross Revenue........... $46,404,969 $17,173,273 $ 42,737,400 $106,315,642
Deductions..................... $15,298,006 $ 6,595,605 $ 20,949,903 $ 42,843,514
----------- ----------- ------------ ------------
Future Net Income (FNI)........ $31,106,973 $10,577,678 $ 21,787,497 $ 63,472,148
Discounted FNI @ 10%........ $20,573,503 $ 5,867,890 $ 11,247,564 $ 37,688,957
</TABLE>

Liquid hydrocarbons are expressed in 42 gallon barrels. All gas volumes are
sales gas expressed in millions of cubic feet (MMCF) at the official temperature
and pressure bases of the areas in which the gas reserves are located.

The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs and development costs. The future net income
is before the deduction of state and federal income taxes and general
administrative overhead, and has not been adjusted for outstanding loans that
may exist nor does it include any adjustment for cash on hand or undistributed
income. No attempt was made to quantify or otherwise account for any accumulated
gas production imbalances that may exist. Liquid hydrocarbon reserves account
for approximately 19 percent and gas reserves account for the remaining 81
percent of total future gross revenue from proved reserves.

A-1
<PAGE> 80

RESERVES INCLUDED IN THIS REPORT

The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10(a) as
clarified by subsequent Commission Staff Accounting Bulletins. Our definitions
of proved reserves are attached.

The proved developed non-producing reserves included herein are comprised
of the behind pipe category. The various reserve status categories are attached.

ESTIMATES OF RESERVES

In general, the reserves included herein were estimated by performance
methods or the volumetric method; however, other methods were used in certain
cases where characteristics of the data indicated such other methods were more
appropriate in our opinion. The reserves estimated by the performance method
utilized extrapolations of various historical data in those cases where such
data were definitive in our opinion. Reserves were estimated by the volumetric
method or offset analogy in those cases where there were inadequate historical
performance data to establish a definitive trend or where the use of production
performance data as a basis for the reserve estimates was considered to be
inappropriate.

Approximately 29 percent of the reserves were determined by performance
analysis. The remaining 71 percent were determined by volumetric analysis,
offset analogy or a combination of volumetrics and offset analogy.

Mallon Oil Company has recently started to develop the Ojo Alamo reservoir
in the East Blanco Field, Rio Arriba County, New Mexico. This is a new reservoir
and no equivalent offset analogy data were available. Reserves were estimated by
volumetric and the estimates of future production were based on the results of
well simulations prepared by Mallon Oil Company. These reserves comprise
approximately 56 percent of the total reserves. Mallon Oil Company currently has
five Ojo Alamo producing wells.

Mallon Oil Company has an aggressive development program of fourteen
recompletions (or dual Ojo Alamo/Picture Cliff completions), sixteen new drill
wells, installation of an amine unit and expansion of the current gas gathering
system. BECAUSE OF THE LIMITED AMOUNT OF PERFORMANCE DATA CURRENTLY AVAILABLE
AND NO EQUIVALENT OFFSET ANALOGY DATA, THE POTENTIAL FOR FUTURE RESERVE
REVISIONS, EITHER UPWARD OR DOWNWARD, IS SIGNIFICANTLY GREATER THAN NORMAL.

The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.

FUTURE PRODUCTION RATES

Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
which are not currently producing. If no production decline trend has been
established, future production rates were held constant, or adjusted for market
conditions where appropriate, until a decline in ability to produce was
anticipated. An estimated rate of decline was then applied to depletion of the
reserves. If a decline trend has been established, this trend was used as the
basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
Mallon Oil Company.

The future production rates from wells now on production may be more or
less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production dates.

A-2
<PAGE> 81

HYDROCARBON PRICES

Mallon Oil Company furnished us with oil and condensate prices in effect at
September 30, 1997 and these prices were held constant to depletion of the
properties. In accordance with Securities and Exchange Commission guidelines,
changes in liquid prices subsequent to September 30, 1997 were not considered in
this report.

Mallon Oil Company furnished us with gas prices in effect at September 30,
1997 and with its forecasts of future gas prices which take into account SEC
guidelines, current spot market prices, contract prices, and fixed and
determinable prices escalations where applicable.

In accordance with SEC guidelines, the future gas prices used in this
report make no allowances for future gas price increases which may occur as a
result of inflation nor do they make any allowance for seasonal variations in
gas prices which may cause future yearly average gas prices to be somewhat
different than September 30, 1997 gas prices.

COSTS

Operating costs for the leases and wells in this report are supplied by
Mallon Oil Company and include only those costs directly applicable to the
leases or wells. When applicable, the operating costs include a portion of
general and administrative costs allocated directly to the leases and wells
under terms of operating agreements. No deduction was made for indirect costs
such as indirect general administration and overhead expenses, loan repayments,
interest expenses, and exploration and development prepayments that are not
charged directly to the leases or wells.

Development costs were furnished to by Mallon Oil Company and are based on
authorizations for expenditure for the proposed work or actual costs for similar
projects. At the request of Mallon Oil Company, their estimate of zero
abandonment after salvage value was used in this report. Ryder Scott has not
performed a detailed study of the abandonment costs nor the salvage value and
makes no warranty for Mallon Oil Company and estimate.

Current costs were held constant throughout the life of the properties.

GENERAL

While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration in
making this evaluation.

The estimates of reserves presented herein were based upon a detailed study
of the properties in which Mallon Oil Company owns an interest; however, we have
not made any field examination of the properties. No consideration was given in
this report to potential environmental liabilities which may exist nor were any
costs included for potential liability to restore and clean up damages, if any,
caused by past operating practices. Mallon Oil Company has informed us that they
have furnished us all of the accounts, records, geological and engineering data,
and reports and other data required for this investigation. The ownership
interests, prices, operating expenses, development costs and other factual data
furnished by Mallon Oil Company were accepted without independent verification.

Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation is
contingent on our estimates of reserves and future income for the subject
properties.

A-3
<PAGE> 82

This report was prepared for the exclusive use and sole benefit of Mallon
Oil Company. The data, work papers, and maps used in this report are available
for examination by authorized parties in our offices. Please contact us if we
can be of further service.

Very truly yours,

RYDER SCOTT COMPANY
PETROLEUM ENGINEERS

/s/ KEVIN E. GANGLUFF
------------------------------------
Kevin E. Gangluff, P.E.
Petroleum Engineer

A-4
<PAGE> 83

DEFINITIONS OF RESERVES

PROVED RESERVES (SEC DEFINITION)

Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing 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 escalation based on future
conditions.

Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. In certain instances,
proved reserves are assigned on the basis of a combination of core analysis and
electrical and other type logs which indicate the reservoirs are analogous to
reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir considered
proved includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.

Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.

Proved natural gas reserves are comprised of non-associated, associated and
dissolved gas. An appropriate reduction in gas reserves has been made for the
expected removal of natural gas liquids, for lease and plant fuel, and for the
exclusion of non-hydrocarbon gases if they occur in significant quantities and
are removed prior to sale. Estimates of proved reserves do not include crude
oil, natural gas, or natural gas liquids being held in underground or surface
storage.

Proved reserves are estimates of hydrocarbons to be recovered from a given
date forward. They may be revised as hydrocarbons are produced and additional
data become available.

A-5
<PAGE> 84

RESERVE STATUS CATEGORIES

Reserve status categories define the development and producing status of
wells and/or reservoirs.

PROVED DEVELOPED (SEC DEFINITION)

Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.

Developed reserves may be subcategorized as producing or non-producing
using the SPE/SPEE Definitions:

Producing

Producing reserves are expected to be recovered from completion intervals
open at the time of the estimate and producing. Improved recovery reserves are
considered to be producing only after an improved recovery project is in
operation.

Non-Producing

Non-producing reserves include shut-in and behind pipe reserves. Shut-in
reserves are expected to be recovered from completion intervals open at the time
of the estimate, but which had not started producing, or were shut-in for market
conditions or pipeline connection, or were not capable of production for
mechanical reasons, and the time when sales will start is uncertain. Behind pipe
reserves are expected to be recovered from zones behind casing in existing
wells, which will require additional completion work or a future recompletion
prior to the start of production.

PROVED UNDEVELOPED (SEC DEFINITION)

Proved undeveloped oil and gas reserves are 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. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
reasonable certainty that there is continuity of production from the existing
productive formation. Under no circumstances should estimates for proved
undeveloped reserves be attributable to any acreage for which an application of
fluid injection or other improved technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.

A-6
<PAGE> 85

======================================================

NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION IN CONNECTION WITH THIS OFFERING OTHER
THAN THOSE CONTAINED IN THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION
OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE
COMPANY OR ANY OF THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER
TO SELL OR SOLICITATION OF ANY OFFER TO BUY BY ANY ONE IN ANY JURISDICTION IN
WHICH SUCH OFFER TO SELL OR SOLICITATION IS NOT AUTHORIZED, OR IN WHICH THE
PERSON MAKING SUCH OFFER OR SOLICITATION IS NOT QUALIFIED TO DO, OR TO ANY
PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION. NEITHER THE
DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL UNDER ANY
CIRCUMSTANCES CREATE ANY IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS
CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF.
------------------------
TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary.................... 3
Cautionary Statement Regarding
Forward-Looking Statements.......... 8
Risk Factors.......................... 8
Use of Proceeds....................... 13
Price Range of Common Stock........... 13
Dividend Policy....................... 13
Dilution.............................. 14
Capitalization........................ 15
Selected Consolidated Financial
Data................................ 16
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 18
Business and Properties............... 26
Management............................ 36
Principal Shareholders................ 38
Transactions with Related Parties..... 38
Description of Capital Stock and Other
Securities.......................... 39
Underwriting.......................... 44
Legal Matters......................... 45
Experts............................... 45
Available Information................. 46
Incorporation of Certain Documents by
Reference........................... 46
Glossary of Terms..................... 47
Index to Consolidated Financial
Statements.......................... F-1
Annex A -- Summary Report of
Independent Petroleum Engineers..... A-1
</TABLE>

======================================================

2,300,000 SHARES
[MALLON RESOURCES LOGO]
COMMON STOCK

PROSPECTUS

ABN AMRO CHICAGO CORPORATION

GAINES, BERLAND INC.

December , 1997

======================================================
<PAGE> 86

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

The following table sets forth the costs and expenses, other than
underwriters' discounts and commissions, payable by the Company in connection
with the sale of Common Stock being registered all amounts are estimated except
the SEC Registration Fee and the NASD Filing Fee.

<TABLE>
<CAPTION>
APPROXIMATE
AMOUNT
-----------
<S> <C>
SEC Registration Fee........................................ $ 9,900
National Association of Securities Dealers, Inc. Fee........ 3,740
Nasdaq Listing Fee.......................................... 17,500
Blue Sky Qualification Fees and Expenses (including legal
fees)..................................................... 5,000
Printing Expenses........................................... 120,000
Legal Fees and Expenses..................................... 80,000
Auditors' Fees and Expenses................................. 60,000
Transfer Agent and Registrar Fees........................... 1,000
Miscellaneous Expenses...................................... 12,860
--------
Total.............................................. $310,000
========
</TABLE>

ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

The Company's Bylaws and Restated Articles of Incorporation provide that
the Company shall, to the full extent permitted by the Colorado Business
Corporation Articles, as amended from time to time, indemnify all directors and
officers of the Company. Sections 7-109-101 to 7-109-110 of the Colorado
Business Corporation Act provide in part that a corporation shall have the power
to indemnify any person who was or is a party or is threatened to be made a
party to any threatened, pending or completed action, suit or proceedings (other
than an action by or in the right of the corporation) by reason of the fact that
such person is or was a director, officer, employee or agent of the corporation
or is or was serving at the request of the corporation as a director, officer,
employee or agent of another corporation or other enterprise, against expenses
(including attorneys' fees), judgments, fines and amounts paid in settlement
actually and reasonably incurred by him in connection with such action, suit or
proceeding if he acted in good faith and in a manner he reasonably believed to
be in or not opposed to the best interests of the corporation, and with respect
to any criminal action or proceeding, had no reasonable cause to believe his
conduct was unlawful. Similar indemnity is authorized for such persons against
expenses (including attorneys' fees) actually and reasonably incurred in defense
or settlement of any threatened, pending or completed action or suit by or in
the right of the corporation, if such person acted in good faith and in a manner
he reasonably believed to be in or not opposed to the best interests of the
corporation, and provided further that (unless a court of competent jurisdiction
otherwise provides) such person shall not have been adjudged liable to the
corporation. Any such indemnification may be made only as authorized in each
specific case upon a determination by the shareholders or disinterested
directors that indemnification is proper because the indemnitee has met the
applicable standard of conduct. The indemnitee is presumed to be entitled to
indemnification and the Company has the burden of proof to overcome that
presumption. Where an officer or a director is successful on the merits or
otherwise in the defense of any action referred to above, the corporation must
indemnify him against the expenses which such officer or director actually or
reasonably incurred.

Additionally, the Restated Articles of Incorporation and Bylaws provide for
mandatory indemnification of directors to the fullest extent permitted by
Colorado law. This provision does not eliminate the liability of a director (i)
for a breach of the director's duty of loyalty to the Company or its
shareholders; (ii) for acts or omissions by the director not in good faith or
which involve intentional misconduct or a knowing violation of law; (iii) for
liability arising under Section 7-108-403 of the Colorado Business Corporation
Law (relating to distributions to shareholders in violation of the Colorado
Business Corporation Act); or (iv) for any transaction from which the director
derived an improper personal benefit.

II-1
<PAGE> 87

Section 7 of the Underwriting Agreement (filed as Exhibit 1.1 hereto)
provides that the Underwriters will indemnify and hold harmless the Company and
each director, officer or controlling person of the Company from and against any
liability caused by any statement or omission in the Registration Statement or
Prospectus based on certain information furnished to the Company by the
Underwriters for use in the preparation thereof.

ITEM 16. EXHIBITS

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DOCUMENT DESCRIPTION
------- -------- -----------
<S> <C> <C>
+1.1 -- Form of Underwriting Agreement between the Company and
the Underwriters.
*3.01 -- Amended and Restated Articles of Incorporation of the (1)
Company
*3.02 -- Bylaws of the Company (1)
*3.04 -- Statement of Designations -- Series B Preferred Stock (2)
*3.05 -- Shareholder Rights Agreement (3)
+5.1 -- Opinion of Holme Roberts & Owen LLP as to the legality of
issuance of the Company's Common Stock

MATERIAL CONTRACTS
*10.58 -- Bank One -- Loan Agreement dated March 20, 1996 (4)

EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
*10.1.5 -- 1997 Equity Participation Plan (5)

CONSENTS
++23.1 -- Consent of Price Waterhouse LLP
+23.2 -- Consent of Holme Roberts & Owen LLP (See Exhibit 5.1)
+23.3 -- Consent of GeoQuest Reservoir Technologies, Inc.
+23.4 -- Consent of Ryder Scott Company Petroleum Engineers.
+24. -- Powers of Attorney
</TABLE>

- ---------------

+ Filed with Mallon Resources Corporation Registration Statement on Form S-2
(Commission File No. 333-38195) filed on October 17, 1997.

++ Filed herewith.

* The exhibit numbers are the exhibit numbers assigned in the previous filings
with the Securities and Exchange Commission, which are identified in the
notes below.

(1) Incorporated by reference from Mallon Resources Corporation Exhibits to
Registration Statement on Form S-4 (SEC File No. 33-23076) filed on August
15, 1988.

(2) Incorporated by reference from Mallon Resources Corporation (Commission File
No. 0-17267) Form 8-K filed on August 24, 1995.

(3) Incorporated by reference from Mallon Resources Corporation (Commission File
No. 0-17267) Form 8-K filed on April 22, 1997.

(4) Incorporated by reference from Mallon Resources Corporation (Commission File
No. 0-17267) Form 8-K filed on March 20, 1996.

(5) Incorporated by reference from Mallon Resources Corporation (Commission File
No. 0-17267) definitive proxy statement for annual meeting of shareholders
held June 6, 1997.

All other schedules for which provision is made in the applicable
accounting regulations of the Securities and Exchange Commission are not
required under the related instructions, are inapplicable and therefore have
been omitted or the information required by the applicable schedule is included
in the notes to the financial statements.

II-2
<PAGE> 88

ITEM 17. UNDERTAKINGS.

Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
registrant, the registrant has been advised that in the opinion of the
Securities and Exchange Commission such indemnification is against public policy
as expressed in the Act and is, therefore, unenforceable. In the event that a
claim for indemnification against such liabilities (other than the payment by
the registrant of expenses incurred or paid by a director, officer or
controlling person of the registrant in the successful defense of any action,
suit or proceeding) is asserted by such director, officer or controlling person
in connection with the securities being registered, the registrant will, unless
in the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the Act and
will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act
of 1933, the information omitted from the form of prospectus filed as part
of this registration statement in reliance upon Rule 430A and contained in
a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or
(4) or 497(h) under the Securities Act shall be deemed to be part of this
registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities
Act of 1933, each post-effective amendment that contains a form of
prospectus shall be deemed to be a new registration statement relating to
the securities offered therein, and the offering of such securities at that
time shall be deemed to be the initial bona fide offering thereof.

II-3
<PAGE> 89

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant
has duly caused this Amendment No. 1 to Registration Statement to be signed on
its behalf by the undersigned, thereunto duly authorized, in Denver, Colorado,
on this 24 day of November, 1997.

MALLON RESOURCES CORPORATION

By: /s/ ROY K. ROSS

----------------------------------

Roy K. Ross

Executive Vice President

Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed below by the following persons in the
capacities and on the dates indicated.

<TABLE>
<CAPTION>
SIGNATURES TITLE DATE
---------- ----- ----
<C> <S> <C>

* Chairman of the Board, November 24, 1997
- ----------------------------------------------------- Director and President
George O. Mallon, Jr. (Principal Executive
Officer)

/s/ ROY K. ROSS Executive Vice President and November 24, 1997
- ----------------------------------------------------- Director
Roy K. Ross

* Executive Vice President and November 24, 1997
- ----------------------------------------------------- Director
Kevin M. Fitzgerald

* Treasurer (Principal November 24, 1997
- ----------------------------------------------------- Financial Officer)
Alfonso R. Lopez

* Controller (Principal November 24, 1997
- ----------------------------------------------------- Accounting Officer)
Carolena F. Chapman

* Director November 24, 1997
- -----------------------------------------------------
Frank Douglass

* Director November 24, 1997
- -----------------------------------------------------
Roger R. Mitchell

* Director November 24, 1997
- -----------------------------------------------------
Francis J. Reinhardt, Jr.

* /s/ ROY K. ROSS November 24, 1997
- -----------------------------------------------------
Roy K. Ross,
as Attorney-in-Fact
</TABLE>

II-4
<PAGE> 90

EXHIBIT INDEX

<TABLE>
<CAPTION>
SEQUENTIALLY
EXHIBIT NUMBERED
NUMBER DOCUMENT DESCRIPTION PAGE
------- -------- ----------- ------------
<S> <C> <C> <C>
+1.1 -- Form of Underwriting Agreement between the Company
and the Underwriters.
*3.01 -- Amended and Restated Articles of Incorporation of the (1)
Company
*3.02 -- Bylaws of the Company (1)
*3.04 -- Statement of Designations -- Series B Preferred Stock (2)
*3.05 -- Shareholder Rights Agreement (3)
+5.1 -- Opinion of Holme Roberts & Owen LLP as to the
legality of issuance of the Company's Common Stock

MATERIAL CONTRACTS
*10.58 -- Bank One -- Loan Agreement dated March 20, 1996 (4)

EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
*10.1.5 -- 1997 Equity Participation Plan (5)

- ---------------

+ Filed with Mallon Resources Corporation Registration Statement on Form S-2
(Commission File No. 333-38195) filed on October 17, 1997.

++ Filed herewith.

* The exhibit numbers are the exhibit numbers assigned in the previous filings
with the Securities and Exchange Commission, which are identified in the
notes below.

(1) Incorporated by reference from Mallon Resources Corporation Exhibits to
Registration Statement on Form S-4 (SEC File No. 33-23076) filed on August
15, 1988.

(2) Incorporated by reference from Mallon Resources Corporation (Commission File
No. 0-17267) Form 8-K filed on August 24, 1995.

(3) Incorporated by reference from Mallon Resources Corporation (Commission File
No. 0-17267) Form 8-K filed on April 22, 1997.

(4) Incorporated by reference from Mallon Resources Corporation (Commission File
No. 0-17267) Form 8-K filed on March 20, 1996.

(5) Incorporated by reference from Mallon Resources Corporation (Commission File
No. 0-17267) definitive proxy statement for annual meeting of shareholders
held June 6, 1997.

<PAGE> 1
EXHIBIT 23.1

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to the use in the Prospectus constituting part of
this Registration Statement on Form S-2 of our report dated March 18, 1997
relating to the financial statements of Mallon Resources Corporation, which
appears in such Prospectus. We also consent to the reference to us under the
heading "Experts" in such Prospectus.

PRICE WATERHOUSE LLP

November 24, 1997