MAGNUM HUNTER RESOURCES INC, 424B4, 1997-11-21

MAGNUM HUNTER RESOURCES INC
424B4, 1997-11-21
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1
Filed Pursuant to Rule 424(b)(4)
Registration No. 333-39073

PROSPECTUS

<TABLE>
<C> <C> <C>
6,600,000 SHARES
[Magnum Logo] MAGNUM HUNTER RESOURCES, INC.
COMMON STOCK
</TABLE>

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

Of the 6,600,000 shares of Common Stock, par value $.002 per share (the
"Common Stock"), of Magnum Hunter Resources, Inc. (the "Company") offered hereby
(the "Offering"), 6,500,000 are being sold by the Company and 100,000 are being
sold by the Selling Shareholder named herein. The Company will not receive any
of the proceeds from the sale of the Common Stock by the Selling Shareholder.
See "Principal and Selling Shareholders."

The Common Stock is listed on the American Stock Exchange under the symbol
"MHR." On November 20, 1997, the closing sale price of the Company's Common
Stock on the American Stock Exchange was $6.25 per share. See "Price Range of
Common Stock and Dividend Policy."

SEE "RISK FACTORS" BEGINNING ON PAGE 11 FOR A DISCUSSION OF CERTAIN 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>
<S> <C> <C> <C> <C>
==============================================================================================================================
UNDERWRITING
PRICE DISCOUNTS AND PROCEEDS TO SELLING
TO PUBLIC COMMISSIONS(1) PROCEEDS TO COMPANY(2) SHAREHOLDER
- ------------------------------------------------------------------------------------------------------------------------------
Per Share......................... $6.00 $0.36 $5.64 $5.64
- ------------------------------------------------------------------------------------------------------------------------------
Total(3).......................... $39,600,000 $2,376,000 $36,660,000 $564,000
==============================================================================================================================
</TABLE>

(1) The Company and the Selling Shareholder have agreed to indemnify the
several Underwriters against certain liabilities, including liabilities
under the Securities Act of 1933, as amended. See "Underwriting."

(2) Before deducting expenses of the Offering payable by the Company
estimated to be $280,000.

(3) The Company has granted the several Underwriters a 30-day option to
purchase up to an additional 990,000 shares of Common Stock on the same
terms and conditions as set forth above solely to cover
over-allotments, if any. If the Underwriters exercise such option in
full, the Price to Public, Underwriting Discounts and Commissions,
Proceeds to Company and Proceeds to Selling Shareholder will be, before
deducting expenses, $45,540,000, $2,732,400, $42,243,600 and $564,000,
respectively. See "Underwriting."
------------------------

The shares of Common Stock are offered severally by the Underwriters named
herein subject to prior sale, when, as and if delivered to and accepted by the
Underwriters subject to their right to reject any order in whole or in part, and
subject to certain other conditions. It is expected that delivery of the shares
of Common Stock will be made at the offices of Rauscher Pierce Refsnes, Inc.,
Dallas, Texas on or about November 26, 1997.

RAUSCHER PIERCE REFSNES, INC.
CIBC OPPENHEIMER
JOHNSON RICE & COMPANY L.L.C.
VAN KASPER & COMPANY
------------------------

THE DATE OF THIS PROSPECTUS IS NOVEMBER 21, 1997
<PAGE> 2

[ARTWORK CONSISTS OF A MAP OF TEXAS, OKLAHOMA AND NEW MEXICO INDICATING THE
COMPANY'S CORE OPERATING AREAS IN THE PERMIAN BASIN, PANOMA, WEST TEXAS AND
AUSTIN CHALK AREAS.]

CERTAIN PERSONS PARTICIPATING IN THE 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
COMMON STOCK, AND THE IMPOSITION OF A PENALTY BID IN CONNECTION WITH THE
OFFERING. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITING."

2
<PAGE> 3

PROSPECTUS SUMMARY

The following summary is qualified in its entirety by the more detailed
information, financial statements, and other data appearing elsewhere or
incorporated by reference in this Prospectus. Unless otherwise indicated, all
information in this Prospectus assumes the Underwriters' over-allotment option
will not be exercised. See "Underwriting." Unless the context otherwise
requires, all references herein to "Magnum Hunter" or the "Company" include
Magnum Hunter Resources, Inc. and its consolidated subsidiaries. Except as
otherwise indicated, "on a pro forma basis" means that the results for the
stated period or other information has been adjusted to reflect the consummation
of the Transactions (as defined). Certain capitalized terms relating to the oil
and gas business are defined in the "Glossary."

THE COMPANY

Magnum Hunter is an independent energy company engaged in the exploitation
and development, acquisition, exploration and operation of oil and gas
properties with a geographic focus in Texas, Oklahoma and New Mexico. In
December 1995 Magnum Petroleum, Inc. and Hunter Resources, Inc. ("Hunter")
combined their oil and gas reserves and other assets (the "Magnum Hunter
Combination") and the management of Hunter assumed operating control of the
Company. The new management implemented a business strategy that emphasized
acquisitions of long-lived Proved Reserves with significant exploitation and
development opportunities where the Company generally could control operations
of the properties. As part of this strategy, in June 1996 the Company acquired
from a subsidiary of Burlington Resources, Inc. ("Burlington") property
interests located in the Texas Panhandle and western Oklahoma (the "Panoma
Properties") for a net purchase price of $34.7 million. Additionally, in April
1997 the Company acquired from Burlington property interests located in west
Texas and southeast New Mexico (the "Permian Basin Properties") for a net
purchase price of $133.0 million. The Company presently intends to focus its
efforts on its substantial inventory of exploitation and development
opportunities, further acquisitions and, to a lesser extent, selected
exploratory drilling prospects. The Company has identified over 600 development
drilling locations (including both production and injection wells) on its
properties, substantially all of which are low-risk in-fill drilling
opportunities.

On a pro forma basis at December 31, 1996, the Company had an interest in
2,581 wells and had estimated Proved Reserves of 314.2 Bcfe with an SEC PV-10 of
$408.0 million. As adjusted to use market prices in effect on March 31, 1997,
the Proved Reserves were 300.5 Bcfe with an SEC PV-10 of $224.8 million on a pro
forma basis at December 31, 1996. Approximately 68% of these reserves were
classified as Proved Developed Producing Reserves and 86% were attributable to
the Panoma Properties and the Permian Basin Properties. On a pro forma basis at
December 31, 1996, the Company's Proved Reserves had an estimated Reserve Life
of 14.6 years and were 61% gas. The Company currently serves as operator for
approximately 71% of its properties. Additionally, the Company owns over 485
miles of gas gathering systems and a 50% interest in a gas processing plant that
is connected to the Company's largest gas gathering system, which was purchased
with the Panoma Properties.

Beginning with the Magnum Hunter Combination in December 1995, the Company
has made nine acquisitions for an aggregate net purchase price of $185.4
million. This strategy has added approximately 305.6 Bcfe of reserves
(determined as of the respective times of their acquisition) at an average cost
of $0.61 per Mcfe, as well as a 427 mile gas gathering system and a 50% interest
in a gas processing plant. As a result of its acquisitions, the Company has
achieved substantial growth as described below:

- Proved reserves increased to 314.2 Bcfe on a pro forma basis at year end
1996 (300.5 Bcfe on a pro forma basis at year end 1996 as adjusted for
March 31, 1997 market prices) from 36.7 Bcfe at year end 1995;

- SEC PV-10 increased to $408.0 million on a pro forma basis at year end
1996 ($224.8 million on a pro forma basis at year end 1996 as adjusted
for March 31, 1997 market prices) from $37.2 million at year end 1995;

- Average daily production increased to 50.8 MMcfe in third quarter 1997
from 0.8 MMcfe in fiscal 1995; and

- EBITDA (as defined) increased to $16.0 million for the nine months ended
September 30, 1997 from $(0.5) million in fiscal 1995.
3
<PAGE> 4

BUSINESS STRATEGY

The Company's objective is to increase its reserves, production, cash flow
and earnings utilizing a program of (i) exploitation and development of acquired
properties, (ii) strategic acquisitions, and (iii) a selective exploration
program.

The following are key elements of the Company's strategy:

- Exploitation and Development of Existing Properties. The Company has a
substantial inventory of exploitation projects including development
drilling, workovers and recompletions. The Company seeks to maximize the
value of its properties through development activities including in-fill
drilling, waterflooding and other enhanced recovery techniques.

- Management of Operating Costs. The Company emphasizes strict cost
controls in all aspects of its business and seeks to operate its
properties wherever possible. By operating approximately 71% of its
properties, the Company is generally able to control direct operating and
drilling costs as well as to manage the timing of development and
exploration activities.

- Property Acquisitions. Although the Company has an extensive inventory of
exploitation and development opportunities, it continues to pursue
strategic acquisitions which fit its objectives of having Proved Reserves
with development potential and operating control.

- Expansion of Gas Gathering, Processing and Marketing Operations. The
Company has implemented several programs to expand and increase the
efficiency of its gas gathering systems. The Company owns over 75% and
markets approximately 96% of the gas that moves through its gas gathering
systems and, therefore, directly benefits from any cost and productivity
improvements. The Company is also considering opportunities to acquire or
develop additional gas gathering, processing and marketing capability,
including a proposal to acquire a minority interest in a gas marketing
company.

- Exploration. The Company is systematically increasing its exploration
efforts, focusing on established geological trends where the Company can
employ its geological, geophysical and engineering expertise. The Company
is actively generating and evaluating prospects for the application of
3-D seismic and advanced drilling technologies.

RECENT ACQUISITIONS

Permian Basin Acquisition. On April 30, 1997 the Company acquired the
Permian Basin Properties from Burlington effective as of January 1, 1997 (the
"Permian Basin Acquisition"). The Permian Basin Properties consist of 47 field
areas in west Texas and southeast New Mexico. The net purchase price was $133.0
million after adjustments aggregating $10.5 million. The Permian Basin
Properties include 1,852 producing oil and gas wells on approximately 113,810
gross acres (82,175 net acres) on which the Company has identified, additional
exploitation and development opportunities and expects to have exploration
potential. Approximately 66% of the wells acquired are operated by the Company.
The estimated Proved Reserves attributable to the Permian Basin Properties as of
December 31, 1996 aggregated 191.6 Bcfe with an SEC PV-10 of $243.3 million,
including 60.4 Bcfe of Proved Undeveloped Reserves. As adjusted to use market
prices in effect on March 31, 1997, the Proved Reserves attributable to the
Permian Basin Properties as of December 31, 1996 aggregated 181.6 Bcfe with an
SEC PV-10 of $139.6 million, including 60.3 Bcfe of Proved Undeveloped Reserves.

Panoma Acquisition. In June 1996 the Company purchased the Panoma
Properties from Burlington for a net purchase price of $34.7 million (the
"Panoma Acquisition"). Assets acquired in the Panoma Acquisition included
interests in 520 gas wells in the Texas Panhandle and western Oklahoma and an
associated 427 mile gas gathering system. The Company operates the gas gathering
system and approximately 90% of the acquired gas wells. The estimated Proved
Reserves attributable to the Panoma Properties as of December 31, 1996
aggregated 77.3 Bcfe with an SEC PV-10 of $111.0 million. As adjusted to use
market prices in effect on March 31, 1997, the Proved Reserves attributable to
the Panoma Properties as of December 31, 1996 aggregated 74.2 Bcfe with an SEC
PV-10 of $53.3 million.
4
<PAGE> 5

McLean Plant Acquisition. In January 1997 the Company acquired for $2.5
million a 50% ownership interest in the McLean gas processing plant (the "McLean
Gas Plant"), which currently processes 100% of the gas produced from the Panoma
Properties (the "McLean Plant Acquisition"). This acquisition allows the Company
to capture a significant portion of the processing profits on gas produced from
the Panoma Properties that would otherwise go to third party processors.

DEVELOPMENT AND EXPLORATION ACTIVITIES
Development

The Company has a substantial inventory of exploitation projects including
development drilling, workovers and recompletions, and cost reduction programs.
The Company believes it can enhance the value of selected fields through in-fill
drilling and enhanced recovery projects. The Company has budgeted approximately
$30.0 million for exploitation and development activities in 1998. Major
activities include the following:

Westbrook. The Westbrook Field covers 45 square miles of the Permian
Basin in Mitchell County, Texas and produces from the Clearfork formation
at approximately 3,200 feet. The field is an active waterflood developed on
28 acre, 5-spot spacing. The Company has completed a field study confirming
the opportunity to increase the well density on its acreage within this
field to 10 acre line drive spacing by drilling approximately 250 injection
and producing wells. An engineering review has been completed and
geological studies are ongoing. Twenty new wells have been staked and are
being permitted with the state regulatory commission. One rig is expected
to begin drilling in November 1997 and use of a second rig will commence in
the first quarter of 1998. The Company has budgeted approximately $11.0
million for development of the Westbrook Field in 1998.

Panoma. The Company has identified 81 development drilling locations
in the Panoma Properties that straddle the Texas Panhandle and western
Oklahoma. Seventy of these locations are in the West Panhandle properties,
which have been developed on 640 acre spacing compared to 160 acre spacing
on other fields located in the area. Of these 70 locations, 31 wells have
been drilled to date and an additional 39 wells are expected to be
completed by mid-1998, effectively reducing spacing to 320 acres per well.
The Company has budgeted approximately $4.0 million for development of the
Panoma Properties through 1998.

Waterfloods. In addition to the Westbrook Field, the Company is
actively involved in five waterflood projects in Texas, four of which are
operated by the Company. The four Company-operated units have had 17 wells
drilled to date, with additional drilling expected during the remainder of
1997 and in 1998. One unit, the Chinquapin Strawn, has started water
injection; a second unit, Fargo West, will start in November 1997; and the
other two units, Magnum Levelland and Starnes Ranch, are estimated to
commence by February 1998. The Company expects response to injection within
one year on each unit. The Company has budgeted approximately $7.3 million
with respect to the five projects in 1998.

Exploration

Magnum Hunter is systematically increasing its exploration efforts,
focusing on established geological trends where the Company can employ its
geological, geophysical and engineering expertise. The Company has budgeted
approximately $6.0 million for exploration activities in 1998, including
geological and geophysical expenses. Two exploratory wells have been drilled in
1997 to date. One of these is located on a 7,500-acre lease block in Roger Mills
County, Oklahoma and was completed as a gas well flowing approximately 500 Mcfe
per day. Drilling of a confirmation well is scheduled to commence in November
1997 at a location approximately two miles west of the initial discovery. A
second exploratory well located on a 3,000 acre lease block in Fayette County,
Texas has encountered oil shows and is awaiting a completion rig to test one of
the objective horizons. The Company owns 25% and 20% working interests,
respectively, in these two prospects.

The Company expects to commence drilling additional exploratory wells
before year-end 1997 on prospects in Oklahoma and Texas. An exploratory well
will commence before year-end 1997 on the Mossy Grove prospect in Walker County,
Texas. The Company owns a 25% working interest in the proposed test well
5
<PAGE> 6

which is located on a 30,000 acre lease block. The primary objective is the Glen
Rose formation at approximately 11,800 feet. Magnum Hunter also owns a 50%
working interest in 2,500 acres on four recently generated prospects in Ellis
County, Oklahoma. The Company expects to commence the first exploratory well in
late 1997, with the Atoka formation as the primary objective. In Victoria
County, Texas the Company has purchased 1,000 mineral acres overlaying a shallow
Frio structure. Magnum Hunter owns a 100% interest in this prospect and plans to
commence an exploratory test well in late 1997 or early 1998. The Company is
actively generating and evaluating prospects for the application of 3-D seismic
and advanced drilling technologies.

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

The Company maintains its corporate headquarters at 600 East Las Colinas
Boulevard, Suite 1200, Irving, Texas 75039 and its telephone number is (972)
401-0752.
6
<PAGE> 7

THE OFFERING (1)

Common Stock offered by the
Company............................. 6,500,000 shares.

Common Stock offered by the Selling
Shareholder....................... 100,000 shares.

Total..................... 6,600,000 shares.

Common Stock outstanding after the
Offering (2)...................... 21,079,598 shares.

Use of Proceeds..................... To repay outstanding indebtedness under
the Credit Facility. The Company
intends to reborrow amounts under the
Credit Facility to fund some or all of
the following: (i) the exploitation and
development, potential acquisition, and
exploration of oil and gas properties;
(ii) the potential expansion of the
Company's gas gathering, processing and
marketing activities, including
acquisitions; and (iii) other general
corporate purposes. The Company will
not receive any proceeds from the sale
of shares of Common Stock by the
Selling Shareholder. See "Use of
Proceeds."

American Stock Exchange Symbol...... MHR.
- ---------------

(1) Does not include 990,000 shares of Common Stock subject to the Underwriters'
over-allotment option.

(2) Calculated as of September 30, 1997 and excludes (i) 243,500 shares of
Common Stock issuable upon exercise of various outstanding warrants; (ii)
1,168,589 shares of Common Stock issuable upon exercise of options granted
under the Company's stock option plan; (iii) 1,702,127 shares of Common
Stock issuable upon conversion of the TCW Preferred Stock (as defined); and
(iv) 145,000 shares of Common Stock issuable upon exercise of options
granted to certain of the Company's employees. Includes an aggregate of
846,256 shares of Common Stock issued upon the exercise of the Company's
public warrants, which were called for redemption on November 14, 1997. See
"Capitalization" and "Description of Capital Stock."

RISK FACTORS

See "Risk Factors" for a discussion of certain factors that should be
considered in evaluating an investment in the Common Stock.

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

As used herein, the term "Transactions" shall refer to (i) the Company's
offering (the "Debt Offering") of $140.0 million aggregate principal amount of
its 10% Senior Notes due 2007 (the "Notes") and the application of the net
proceeds thereof; (ii) the Permian Basin Acquisition (including the incurrence
of indebtedness under the Company's revolving line of credit (the "Credit
Facility") and the Company's previously existing term loan facility and the use
of proceeds therefrom); (iii) the Panoma Acquisition; (iv) the McLean Plant
Acquisition; (v) the issuance of the TCW Preferred Stock; and (vi) the
conversion or redemption of the Company's Series B and Series C Preferred Stock
into Common Stock, each as more fully described in the Unaudited Pro Forma
Combined Financial Data and the notes thereto.
7
<PAGE> 8

SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

The following table sets forth summary historical consolidated financial
data of the Company as of and for the two years ended December 31, 1996, for the
nine months ended September 30, 1996 and 1997 and as of September 30, 1997,
which have been derived from the Company's consolidated financial statements,
and unaudited summary pro forma data for the nine months ended September 30,
1997. The historical financial data of the Company for the nine months ended
September 30, 1996 and 1997 and as of September 30, 1997 have been derived from
the Company's unaudited interim consolidated financial statements. The pro forma
income statement and other data for the nine months ended September 30, 1997
give pro forma effect to the Transactions as if the Transactions had occurred on
January 1, 1997. The pro forma financial data do not purport to represent what
the Company's financial position or results of operations would actually have
been had the transactions in fact occurred on the assumed date and are not
necessarily indicative of future operating results or financial position. The
information contained in this table should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Selected Consolidated Financial Data," the Consolidated Financial
Statements and the notes thereto and the Unaudited Pro Forma Combined Financial
Data and the notes thereto included elsewhere in this Prospectus.

<TABLE>
<CAPTION>
YEAR ENDED NINE MONTHS ENDED SEPTEMBER 30,
DECEMBER 31, ---------------------------------
------------------ PRO FORMA
1995 1996 1996 1997 1997
------- -------- -------- --------- ----------
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating revenues:
Oil and gas............................ $ 617 $ 10,248 $ 6,357 $ 22,793 $ 35,420
Gas gathering, marketing and
processing.......................... -- 5,768 3,143 7,721 7,721
Oil field services and international
sales............................... 32 396 385 3,792 3,792
------- -------- -------- --------- --------
Total operating revenues....... 649 16,412 9,885 34,306 46,933
Operating costs and expenses:
Oil and gas production................. 268 4,390 2,305 8,521 11,560
Gas gathering, marketing and
processing.......................... -- 4,708 2,629 5,803 5,803
Oil field services and international
sales............................... 26 267 521 3,482 3,482
Depreciation and depletion............. 421 2,951 1,888 8,607 12,236
General and administrative............. 977 1,225 670 1,128 1,178
------- -------- -------- --------- --------
Total operating costs and
expenses..................... 1,692 13,541 8,013 27,541 34,259
------- -------- -------- --------- --------
Operating profit (loss).................. (1,043) 2,871 1,872 6,765 12,674
Other income........................... 77 344 214 608 608
Interest expense....................... (2) (2,394) (1,550) (9,298) (13,798)
Benefit (provision) for deferred income
taxes............................... -- (312) (204) 731 203
Minority interest in subsidiary
earnings............................ -- -- -- (40) (40)
------- -------- -------- --------- --------
Net income (loss) before
extraordinary loss........... (968) 509 332 (1,234) (353)
Extraordinary loss from early
extinguishment of debt................. -- -- -- (1,384) --
------- -------- -------- --------- --------
Net income (loss)........................ (968) 509 332 (2,618) (353)
Dividends applicable to preferred
shares................................. (617) (406) (382) (657) (657)
------- -------- -------- --------- --------
Income (loss) applicable to common
shares................................. $(1,585) $ 103 $ (50) $ (3,275) $ (1,010)
======= ======== ======== ========= ========
Income (loss) per common share before
extraordinary loss..................... $ (0.28) $ 0.01 $ 0.00 $ (0.14) $ (0.07)
Extraordinary loss per common share...... -- -- -- (0.10) --
------- -------- -------- --------- --------
Income (loss) per common share........... $ (0.28) $ 0.01 $ (0.00) $ (0.24) $ (0.07)
======= ======== ======== ========= ========
Common shares used in per share
calculation............................ 5,607 12,486 12,084 13,659 13,659
OTHER FINANCIAL DATA:
EBITDA(1)................................ $ (545) $ 6,166 $ 3,974 $ 15,980 $ 25,518
Capital expenditures(2).................. 1,244 41,471 38,787 148,429 148,429
CASH FLOWS:
Net cash (used by) provided by operating
activities............................. $ (849) $ 3,028 $ 1,864 $ 5,897 --
Net cash used by investing activities.... (2,007) (41,738) (38,599) (147,959) --
Net cash provided by financing
activities............................. 2,755 38,853 36,870 143,456 --
</TABLE>

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<TABLE>
<CAPTION>
SEPTEMBER 30, 1997
--------------------------
ACTUAL AS ADJUSTED(3)
-------- --------------
<S> <C> <C>
BALANCE SHEET DATA:
Working capital............................................. $ 1,927 $ 1,927
Property, plant and equipment, net.......................... 213,000 213,000
Total assets................................................ 240,158 240,158
Total debt(4)............................................... 190,748 149,714
Stockholders' equity........................................ 31,904 72,938
</TABLE>

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

(1) EBITDA is defined as net income (loss) before income taxes and minority
interest, plus the sum of depletion and depreciation and interest expense.
EBITDA is not a measure of cash flow as determined by generally accepted
accounting principles. The Company has included information concerning
EBITDA because EBITDA is a measure used by certain investors in determining
the Company's historical ability to service its indebtedness. EBITDA should
not be considered as an alternative to, or more meaningful than, net income
or cash flows as determined in accordance with generally accepted accounting
principles or as an indicator of the Company's operating performance or
liquidity.

(2) Capital expenditures include cash expended for acquisitions plus normal
additions to oil and gas properties and other fixed assets.

(3) Adjusted to reflect (i) the sale by the Company of 6,500,000 shares in the
Offering and the application of the net proceeds therefrom and (ii) the
issuance of 846,256 shares of Common Stock to holders of Warrants (which
were called for redemption on November 14, 1997). See "Use of Proceeds" and
"Capitalization."

(4) Consists of long-term debt, including $140.0 million of Notes and $48.0
million of bank debt, and $2.7 million of other notes payable, and excludes
production payment liabilities of $790,000.
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SUMMARY HISTORICAL AND PRO FORMA OPERATING, RESERVE AND WELL DATA

The following table sets forth certain summary information with respect to
the Company's operations for the periods indicated and summary information with
respect to the Company's estimated proved oil and gas reserves. The pro forma
operating data for the nine months ended September 30, 1997 give effect to the
Transactions as if they had occurred on January 1, 1997, and the pro forma
reserve and well data at December 31, 1996 give effect to the Transactions as if
they had occurred on December 31, 1996. The information contained in this table
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations," the Consolidated Financial
Statements and the notes thereto, the Unaudited Pro Forma Combined Financial
Data and the notes thereto and "Business and Properties" included elsewhere in
this Prospectus.

<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED ENDED SEPTEMBER 30,
DECEMBER 31, -----------------------------
---------------- PRO FORMA
1995 1996 1996 1997 1997
------ ------ ------ ------ ---------
<S> <C> <C> <C> <C> <C>
OPERATING DATA:
Production:
Oil (MBbl)................................ 30 191 140 490 763
Gas (MMcf)................................ 102 2,675 1,632 6,451 9,095
Natural Gas Equivalents (MMcfe)........... 282 3,821 2,472 9,391 13,672
Average sales price:
Oil (per Bbl)............................. $15.60 $20.46 $19.92 $17.79 $18.68
Gas (per Mcf)............................. 1.46 2.37 2.23 2.18 2.33
Natural Gas Equivalents (per Mcfe)........ 2.19 2.68 2.57 2.43 2.59
Average oil and gas production expense (per
Mcfe)(1).................................. $ 0.95 $ 1.15 $ 1.14 $ 0.91 $ 0.85
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------------------
PRO FORMA 1996
------------------------------
DEC. 31, 1996 MAR. 31, 1997
1995 1996 PRICES PRICES(2)
------- -------- ------------- -------------
<S> <C> <C> <C> <C>
RESERVE AND WELL DATA(3):
Proved Reserves:
Oil (MBbl)................................. 3,768 5,338 20,629 19,851
Gas (MMcf)................................. 14,072 90,566 190,442 181,363
Natural Gas Equivalents (MMcfe)............ 36,678 122,596 314,218 300,470
Percent Proved
Developed Reserves......................... 51% 68% 68% 67%
Percent gas reserves......................... 38% 74% 61% 60%
Reserve Life (years)......................... 16.2 16.6 14.6 14.0
Estimated future net cash flows before tax
(thousands)................................ $45,940 $353,542 $822,385 $447,932
SEC PV-10 (thousands)........................ $37,209 $164,766 $408,049 $224,831
Producing wells:
Gross...................................... 462 729 2,581 2,581
Net........................................ 130 569 1,436 1,436
Average Working Interest................... 28% 78% 56% 56%
Operated wells (4)........................... 130 609 1,833 1,833
</TABLE>

- ---------------
(1) Includes lease operating expenses and production and ad valorem taxes, if
applicable. For the year ended December 31, 1996 and the nine months ended
September 30, 1997, includes internal transfer price expenses for gas
gathering and overhead costs of $0.23 per Mcfe and $0.16 per Mcfe,
respectively.
(2) Proved Reserves, future net cash flows before tax and SEC PV-10 have been
estimated as of December 31, 1996 using March 31, 1997 market prices of
$20.41 per Bbl of oil and $2.30 per Mcf of gas (with appropriate adjustments
for Btu content) and have not been adjusted for production for the three-
month period ended March 31, 1997.
(3) For limitations on the accuracy and reliability of reserves and future net
cash flow estimates, see "Risk Factors -- Uncertainty of Estimates of
Reserves and Future Net Cash Flows." For reserve pricing information, see
"Business and Properties -- Oil and Gas Reserves."
(4) Includes wells operated for third parties.
10
<PAGE> 11

RISK FACTORS

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS. Information contained or
incorporated by reference in this Prospectus may contain "forward-looking
statements" within the meaning of the Private Securities Litigation Reform Act
of 1995, which can be identified by the use of forward-looking terminology such
as "may," "expect," "intend," "anticipate," "estimate" or "continue" or the
negative thereof or other variations thereon or comparable terminology. The
following matters and certain other factors noted throughout this Prospectus
constitute cautionary statements identifying important factors with respect to
any such forward-looking statements, including certain risks and uncertainties,
that could cause actual results to differ materially from those in such
forward-looking statements.

Prior to making an investment decision, prospective investors should
carefully consider, together with the other information contained in this
Prospectus, the following risk factors:

SUBSTANTIAL LEVERAGE; ABILITY TO SERVICE DEBT

The Company is highly leveraged, with outstanding long-term indebtedness of
approximately $188.0 million and stockholders' equity of $31.9 million as of
September 30, 1997. The Company's level of indebtedness has several important
effects on its future operations, including (i) a substantial portion of the
Company's cash flow from operations is dedicated to the payment of interest on
its indebtedness and is not available for other purposes; (ii) the covenants
contained in the Credit Facility require the Company to meet certain financial
tests and limit the Company's ability to borrow additional funds or to acquire
or dispose of assets; and (iii) the Company's ability to obtain additional
financing in the future may be impaired. Additionally, the senior (as opposed to
subordinated) status of the Notes, the Company's high debt to equity ratio, and
the pledge of substantially all of the Company's assets as collateral for the
Credit Facility will for the foreseeable future make it difficult for the
Company to obtain financing on an unsecured basis or to obtain secured financing
other than certain "purchase money" indebtedness collateralized by the acquired
assets.

Although the Company reported an operating profit for fiscal 1996, at
December 31, 1996 the Company had an accumulated deficit of $5.1 million due to
operating losses incurred in prior years. The Company's ability to meet its
financial covenants and to make scheduled payments of principal and interest to
repay its indebtedness is dependent upon its operating results and its ability
to obtain financing. However, there can be no assurance that the Company's
business will generate sufficient cash flow from operations or that future bank
credit will be available in an amount sufficient to enable the Company to
service its indebtedness or make necessary capital expenditures. In such event,
the Company would be required to obtain such financing from the sale of equity
securities or other debt financing. There can be no assurance that any such
financing will be available on terms acceptable to the Company. Should
sufficient capital not be available, the Company may not be able to continue to
implement its business strategy.

The Credit Facility limits the Company's borrowings to amounts determined
by the lenders, in their sole discretion, based upon a variety of factors
including the amount of indebtedness which can be adequately supported by the
value of oil and gas reserves and assets, contracts and throughput attributable
to the gas gathering systems and processing plant, and assets owned by the
Company (the "Borrowing Base"). The Credit Facility was amended effective
September 30, 1997 to increase the maximum commitment from $75.0 million to
$125.0 million, increase the Borrowing Base by $5.0 million to $65.0 million and
modify the Consolidated EBITDA to Interest Expense ratio (as defined in the
Credit Facility). With these adjustments, as of November 17, 1997, the Company
had approximately $19.0 million of borrowing availability under the Borrowing
Base. After application of the net proceeds from the Offering, the Company will
have approximately $55.4 million available for reborrowing under the Credit
Facility. If oil or gas prices decline below their current levels, the
availability of funds under the Credit Facility could be materially adversely
affected.

The Credit Facility also requires the Company to satisfy certain financial
ratios in the future. One covenant requires the Company to maintain a ratio of
the Company's funded indebtedness divided by the sum of funded indebtedness plus
equity (the "Debt to Capitalization Ratio") of not more than 0.86 until March
31, 1998, not more than 0.75 from April 1, 1998 until September 30, 1998, and
not more than 0.70 thereafter. At September 30, 1997, the Company had a Debt to
Capitalization Ratio of 0.86. At Septem-

11
<PAGE> 12

ber 30, 1997, as adjusted for this Offering and the exercise of Warrants for
846,256 shares of Common Stock in connection with their call for redemption on
November 14, 1997, the Company would have a Debt to Capitalization Ratio of
0.67. Another covenant requires the Company to maintain a ratio of Consolidated
EBITDA to Interest Expense of not less than 1.80 to 1 through March 31, 1998,
not less than 2.00 to 1 from April 1, 1998 through June 30, 1998, not less than
2.25 to 1 from July 1, 1998 through September 30, 1998, and not less than 2.50
to 1 thereafter. The Company had a ratio of Consolidated EBITDA to Interest
Expense of 1.80 to 1 as of September 30, 1997. The failure to satisfy these
covenants or any of the other covenants in the Credit Facility would constitute
an event of default thereunder and, subject to certain grace periods, may permit
the lenders to accelerate the indebtedness then outstanding under the Credit
Facility and demand immediate repayment thereof. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations." and "Description
of Indebtedness -- Description of Credit Facility."

VOLATILITY OF OIL AND GAS PRICES

The Company's revenues, profitability and the carrying value of its oil and
gas properties are substantially dependent upon prevailing prices of, and demand
for, oil and gas and the costs of acquiring, finding, developing and producing
reserves. The Company's ability to maintain or increase its borrowing capacity,
to repay current or future indebtedness, and to obtain additional capital on
attractive terms is also substantially dependent upon oil and gas prices.
Historically, the markets for oil and gas have been volatile and are likely to
continue to be volatile in the future. Prices for oil and gas are subject to
wide fluctuations in response to: (i) relatively minor changes in the supply of,
and demand for, oil and gas; (ii) market uncertainty; and (iii) a variety of
additional factors, all of which are beyond the Company's control. These factors
include domestic and foreign political conditions, the price and availability of
domestic and imported oil and gas, the level of consumer and industrial demand,
weather, domestic and foreign government relations, the price and availability
of alternative fuels and overall economic conditions. The Company's production
is predominantly weighted toward gas, making earnings and cash flow more
sensitive to gas price fluctuations. For 1996, the Company has estimated that a
$0.10 per Mcf change in gas prices would have resulted in a $250,000 difference
in EBITDA, and a $1.00 per Bbl change in oil prices would have resulted in a
$182,000 difference in EBITDA. On a pro forma basis for the Permian Basin
Acquisition for 1996, the Company has estimated that a $0.10 per Mcf change in
gas prices would have resulted in a $1.3 million difference in EBITDA, and a
$1.00 per Bbl change in oil prices would have resulted in a $1.1 million
difference in EBITDA. Furthermore, the marketability of the Company's production
depends in part upon the availability, proximity and capacity of gathering
systems, pipelines and processing facilities. Volatility in oil and gas prices
could affect the Company's ability to market its production through such
systems, pipelines or facilities. Substantially all of the Company's gas
production is currently sold to gas marketing firms or end users either on the
spot market on a month-to-month basis at prevailing spot market prices or under
long-term contracts based on current spot market prices. The Company normally
sells its oil under month-to-month contracts with a variety of purchasers.
Accordingly, the Company's oil and gas sales expose it to the commodities risks
associated with changes in market prices. See "Business and
Properties -- Marketing of Production."

Under full cost accounting, the Company would be required to take a
non-cash charge against earnings to the extent capitalized costs of acquisition,
exploration and development (net of depletion and depreciation), less deferred
income taxes, exceed the SEC PV-10 of its Proved Reserves and the lower of cost
or fair value of unproved properties after income tax effects. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Background."

UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET CASH FLOWS

This Prospectus contains estimates of the Company's oil and gas reserves
and the future net cash flows from those reserves, which have been prepared or
audited by certain independent petroleum consultants. There are numerous
uncertainties inherent in estimating quantities of Proved Reserves of oil and
gas and in projecting future rates of production and the timing of development
expenditures, including many factors beyond the Company's control. The estimates
in this Prospectus are based on various assumptions, including,

12
<PAGE> 13

for example, constant oil and gas prices, operating expenses, capital
expenditures and the availability of funds, and, therefore, are inherently
imprecise indications of future net cash flows. Actual future production, cash
flows, taxes, operating expenses, development expenditures and quantities of
recoverable oil and gas reserves may vary substantially from those assumed in
the estimates. Any significant variance in these assumptions could materially
affect the estimated quantity and value of reserves set forth in this
Prospectus. Additionally, the Company's reserves may be subject to downward or
upward revision based upon actual production performance, results of future
development and exploration, prevailing oil and gas prices and other factors,
many of which are beyond the Company's control. See "Business and
Properties -- Oil and Gas Reserves."

The SEC PV-10 of Proved Reserves referred to in this Prospectus should not
be construed as the current market value of the estimated Proved Reserves of oil
and gas attributable to the Company's properties. In accordance with applicable
requirements of the Securities and Exchange Commission (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 (i) the timing of both production and related expenses;
(ii) changes in consumption levels; and (iii) governmental regulations or
taxation. In addition, the calculation of the present value of the future net
cash flows using a 10% discount as required by the Commission is not necessarily
the most appropriate discount factor based on interest rates in effect from time
to time and risks associated with the Company's reserves or the oil and gas
industry in general. Furthermore, the Company's reserves may be subject to
downward or upward revision based upon actual production, results of future
development, supply and demand for oil and gas, prevailing oil and gas prices
and other factors. See "Business and Properties -- Oil and Gas Reserves."

FINDING AND ACQUIRING ADDITIONAL RESERVES; DEPLETION

The Company's future success depends upon its ability to find or acquire
additional oil and gas reserves that are economically recoverable. Except to the
extent the Company conducts successful exploration or development activities or
acquires properties containing Proved Reserves, the Proved Reserves of the
Company will generally decline as they are produced. The decline rate varies
depending upon reservoir characteristics and other factors. The Company's future
oil and gas reserves and production, and, therefore, cash flow and income, are
highly dependent upon the Company's level of success in exploiting its current
reserves and acquiring or finding additional reserves. There can be no assurance
that the Company's planned development projects and acquisition activities will
result in significant additional reserves or that the Company will have success
drilling productive wells at economic returns to replace its current and future
production.

ACQUISITION RISKS

The Company has grown primarily through acquisitions and intends to
continue acquiring oil and gas properties. Although the Company performs a
review of the properties proposed to be acquired, such reviews are subject to
uncertainties. It generally is not feasible to review in detail every individual
property involved in an acquisition. Ordinarily, review efforts are focused on
the higher-valued properties. However, even a detailed review of all properties
and records may not reveal existing or potential problems; nor will it permit
the Company to become sufficiently familiar with the properties to assess fully
their deficiencies and capabilities. Inspections are not always performed on
every well, and potential problems, such as mechanical integrity of equipment
and environmental conditions that may require significant remedial expenditures,
are not necessarily observable even when an inspection is undertaken.

The Company has recently begun to focus its acquisition efforts on larger
packages of oil and gas properties, such as the properties involved in the
Panoma and Permian Basin Acquisitions. The acquisition of larger oil and gas
properties may involve substantially higher costs and may pose additional issues
regarding operations and management. There can be no assurance that oil and gas
properties acquired by the Company will be successfully integrated into the
Company's operations or will achieve desired profitability objectives. See
"Business and Properties -- Recent Acquisitions."

13
<PAGE> 14

EXPLORATION AND DEVELOPMENT RISKS; WATERFLOOD PROJECTS

The Company intends to increase its development and exploration activities.
Exploration drilling and, to a lesser extent, development drilling of oil and
gas reserves involve a high degree of risk that no commercial production will be
obtained and/or that production will be insufficient to recover drilling and
completion costs. The cost of drilling, completing and operating wells is often
uncertain. The Company's drilling operations may be curtailed, delayed or
canceled as a result of numerous factors, including title problems, weather
conditions, compliance with governmental requirements and shortages or delays in
the delivery of equipment. Furthermore, completion of a well does not assure a
profit on the investment or a recovery of drilling, completion and operating
costs. See "Business and Properties -- Development and Exploration Activities."

There are certain risks associated with secondary recovery operations,
especially the use of waterflooding techniques, and drilling activities in
general. Part of the Company's inventory of development prospects consists of
waterflood projects. With respect to the Permian Basin Properties, the Company
has identified significant potential expenditures related to further developing
an existing waterflood. Waterflooding involves significant capital expenditures
and uncertainty as to the total amount of secondary reserves that can be
recovered. In waterflood operations, there is generally a delay between the
initiation of water injection into a formation containing hydrocarbons and any
increase in production that may result. The operating cost per unit of
production of waterflood projects is generally higher during the initial phases
of such projects due to the purchase of injection water and related costs, as
well as during the later stages of the life of the project as production
declines. The degree of success, if any, of any secondary recovery program
depends on a large number of factors, including the porosity of the formation,
the technique used and the location of injector wells. See "Business and
Properties -- Development and Exploration Activities."

OPERATING HAZARDS AND UNINSURED RISKS; PRODUCTION CURTAILMENTS

The Company's oil and gas business involves a variety of operating risks,
including, but not limited to, unexpected formations or pressures,
uncontrollable flows of oil, gas, brine or well fluids into the environment
(including groundwater contamination), blowouts, fires, explosions, pollution
and other risks, any of which could result in personal injuries, loss of life,
damage to properties and substantial losses. Although the Company carries
insurance at levels which it believes are reasonable, it is not fully insured
against all risks. The Company does not carry business interruption insurance.
Losses and liabilities arising from uninsured or under-insured events could have
a material adverse effect on the financial condition and operations of the
Company.

From time to time, due primarily to contract terms, pipeline interruptions
or weather conditions, the producing wells in which the Company owns an interest
have been subject to production curtailments. The curtailments range from
production being partially restricted to wells being completely shut-in. The
duration of curtailments varies from a few days to several months. In most cases
the Company is provided only limited notice as to when production will be
curtailed and the duration of such curtailments. The Company is not currently
experiencing any material curtailment on its production.

HEDGING RISKS

As of September 30, 1997 the Company had hedged approximately (i) 43% of
its gas production through March 1998 and (ii) 33% of its oil production through
December 1998. These hedges have in the past involved fixed price arrangements
and other price arrangements at a variety of prices, floors and caps. The
Company has in the past and may in the future enter into oil and gas futures
contracts, options and swaps. The Company's hedging activities, while intended
to reduce the Company's sensitivity to changes in market prices of oil and gas,
are subject to a number of risks including instances in which the Company or the
counterparties to its futures contracts could fail to purchase the contracted
quantities of oil or gas. Additionally, the fixed price sales and hedging
contracts limit the benefits the Company will realize if actual prices rise
above the contract prices. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources -- Hedging Activity" and Note 14 to the Company's Consolidated
Financial Statements.

14
<PAGE> 15

LAWS AND REGULATIONS

The Company's operations are affected by extensive regulation pursuant to
various federal, state and local laws and regulations relating to the
exploration for and development, production, gathering and marketing of oil and
gas. Matters subject to regulation include discharge permits for drilling
operations, drilling and abandonment bonds or other financial responsibility
requirements, reports concerning operations, the spacing of wells, unitization
and pooling of properties, 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.

Operations of the Company are also subject to numerous environmental laws,
including but not limited to, those governing management of waste, protection of
water, air quality, the discharge of materials into the environment, and
preservation of natural resources. Non-compliance with environmental laws and
the discharge of oil, gas, or other materials into the air, soil or water may
give rise to liabilities to the government and third parties, including civil
and criminal penalties, and may require the Company to incur costs to remedy the
discharge. Laws and regulations protecting the environment have become more
stringent in recent years, and may in certain circumstances impose retroactive,
strict, and joint and several liability rendering entities liable for
environmental damage without regard to negligence or fault. From time to time
the Company has agreed to indemnify sellers of producing properties from whom
the Company has acquired reserves against certain liabilities for environmental
claims associated with such properties. There can be no assurance that new laws
or regulations, or modifications of or new interpretations of existing laws and
regulations, will not increase substantially the cost of compliance or otherwise
adversely affect the Company's oil and gas operations and financial condition or
that material indemnity claims will not arise against the Company with respect
to properties acquired by or from the Company. While the Company does not
anticipate incurring material costs in connection with environmental compliance
and remediation, it cannot guarantee that material costs will not be incurred.
See "Business and Properties -- Regulation."

COMPETITION

The Company encounters substantial competition in acquiring properties,
marketing oil and gas, securing trained personnel and operating its properties.
Many competitors have financial and other resources that substantially exceed
those of the Company. The Company's competitors in acquisitions, development,
exploration and production include major oil companies, numerous independents,
individual proprietors and others. Therefore, competitors may be able to pay
more for desirable leases and to evaluate, bid for and purchase a greater number
of properties or prospects than the financial or personnel resources of the
Company will permit. See "Business and Properties -- Competition."

DEPENDENCE UPON KEY PERSONNEL

The Company is substantially dependent upon three key individuals within
its management, Gary C. Evans, Matthew C. Lutz and Richard R. Frazier, all of
whom were executives of Hunter prior to the Magnum Hunter Combination. The loss
of the services of any one of these individuals could have a material adverse
impact upon the Company. See "Management."

SHARES ELIGIBLE FOR FUTURE SALE; ABSENCE OF DIVIDENDS

The Company is authorized to issue up to 50,000,000 shares of Common Stock.
As of September 30, 1997, 13,733,342 shares were issued and outstanding, and
4,113,392 shares were reserved for issuance upon the conversion of shares of the
TCW Preferred Stock and upon the exercise of all outstanding warrants and
options. See "Description of Capital Stock." The issuance of additional shares
of Common Stock pursuant to such conversion rights and outstanding warrants and
options would reduce the proportionate ownership and voting rights of the Common
Stock then outstanding. The Company's existing management and their affiliates
own 2,265,675 shares of Common Stock that may in the future be sold in
compliance with Rule 144 adopted under the Securities Act. In addition, the
Credit Facility contains a Debt to Capitalization Ratio covenant requiring the
Company to reduce such ratio from approximately 0.86 to 0.75 by June 30, 1998
and 0.70 by

15
<PAGE> 16

December 31, 1998. The possibility that substantial amounts of Common Stock may
be sold in the public market may adversely affect prevailing and future market
prices for the Common Stock and could impair the Company's ability to raise
capital through the sale of its equity securities in the future.

The Company called for redemption on November 14, 1997 its publicly held
warrants (the "Warrants"), each of which was exercisable for three shares of
Common Stock at an exercise price of $5.50 per share and redeemable at $0.02 per
Warrant. As a result, Warrants were exercised for an aggregate of 846,256 shares
of Common Stock and the remaining Warrants covering 7,920 shares of Common Stock
were redeemed. See "Description of Capital Stock--Warrants."

The Company and its executive officers and directors, holding approximately
2,315,675 shares of Common Stock after the Offering, have agreed that they will
not, without the prior written consent of Rauscher Pierce Refsnes, Inc., for a
period of 90 days after the date of this Offering, directly or indirectly, offer
to sell, sell, pledge, contract to sell, grant any option for the sale of or
otherwise dispose of any shares of Common Stock or any securities convertible
into or exchangeable or exercisable for any shares of Common Stock, or any right
or option to acquire any such shares or securities, except, in the case of the
Company, for transactions related to the Company's existing option plans and
other employee benefit plans or related to outstanding stock options and
warrants disclosed in this Prospectus. See "Underwriting."

The Company has not previously paid any cash dividends on the Common Stock
and does not anticipate paying dividends on the Common Stock in the foreseeable
future. It is the present intention of management to utilize all available funds
for the development of the Company's business. In addition, the Company is not
permitted to pay any dividends on the Common Stock unless and until all dividend
rights on outstanding Preferred Stock have been satisfied. The Credit Facility
and the Indenture governing the Notes also restrict the payment of cash
dividends. See "Price Range of Common Stock and Dividend Policy" and
"Description of Indebtedness."

PREFERRED STOCK; ANTI-TAKEOVER PROVISIONS

The Common Stock is subordinate to all outstanding classes of Preferred
Stock of the Company in the payment of dividends and other distributions made
with respect to the stock, including distributions upon liquidation or
dissolution of the Company. The Board of Directors of the Company is authorized
to issue up to 10,000,000 shares of Preferred Stock without first obtaining
shareholder approval except in limited circumstances. The Company has previously
issued several series of Preferred Stock, although only the Series A Preferred
Stock and the TCW Preferred Stock are currently outstanding. The holders of the
TCW Preferred Stock currently have the right to appoint one additional member to
the Board of Directors and upon certain circumstances, up to 75% of the Board.
See "Description of Capital Stock--Preferred Stock." The designation and
issuance of other series of Preferred Stock will create additional securities
that will have dividend and liquidation preferences over the Common Stock or, in
the case of convertible preferred stock, may have the effect of diluting the
current shareholders' interest in the Company upon conversion.

The Company's Articles of Incorporation and Bylaws include certain
provisions that may have the effect of encouraging persons considering
unsolicited tender offers or other unilateral takeover proposals to negotiate
with the Board of Directors rather than pursue non-negotiated takeover attempts.
These provisions include authorized "blank check" Preferred Stock and the
availability of authorized but unissued Common Stock. The issuance of Preferred
Stock may have the effect of delaying or preventing a change in control of the
Company without further shareholder action and may adversely affect the rights
and powers, including voting rights, of the holders of Common Stock. In certain
circumstances the issuance of Preferred Stock could depress the market price of
the Common Stock. In addition, a change of control would entitle the holders of
the Notes to put the Notes to the Company under the Indenture and the lenders to
accelerate payment of outstanding indebtedness under the Credit Facility, both
of which events could have the effect of discouraging a takeover of the Company
by making such an attempt potentially more expensive. See "Description of
Capital Stock" and "Description of Indebtedness."

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<PAGE> 17

USE OF PROCEEDS

The net proceeds to the Company from the Offering will be approximately
$36.4 million ($42.0 million assuming exercise of the Underwriters'
over-allotment option) after deducting underwriting discounts and estimated
expenses of the Offering payable by the Company. Such net proceeds will be
utilized to repay outstanding indebtedness under the Credit Facility. The
Company intends to reborrow amounts under the Credit Facility to fund some or
all of the following: (i) the exploitation and development, potential
acquisition and exploration of oil and gas properties; (ii) the potential
expansion of the Company's gas gathering, processing and marketing activities,
including acquisitions; and (iii) other general corporate purposes.

The Company's current capital expenditures budget of approximately $36.0
million for 1998 includes $30.0 million for exploitation and development
activities and $6.0 million for exploration activities, including geological and
geophysical expenses. Actual expenditures by the Company are discretionary and
will depend upon future events that cannot be predicted, including the actual
results and costs of future exploration and development drilling and other
activities, the availability and cost of oil and gas properties meeting the
Company's acquisition criteria and other matters beyond the control of the
Company. The Company is continually evaluating and pursuing potential property
acquisitions. The Company has no commitments, contracts, understandings or
arrangements at the present time with respect to any material acquisition other
than a non-binding letter of intent regarding a potential acquisition of a
minority interest in a gas marketing company. See "Business and
Properties -- Marketing of Production."

The indebtedness of the Company, a portion of which is to be repaid with
the net proceeds of the Offering, was incurred, along with indebtedness under
the Company's previously existing term loan facility, to fund the Permian Basin
Acquisition, to repay the outstanding indebtedness under the Company's previous
credit facility (which included amounts borrowed to fund the McLean Plant
Acquisition) and to pay the costs associated with the Permian Basin Acquisition
and the related financings. At November 17, 1997, $46.0 million was outstanding
under the Credit Facility at a weighted average interest rate of 7.46% per annum
under LIBOR and prime rate interest options. Amounts outstanding under the
Credit Facility mature on April 30, 2002 with no required principal payments
until maturity, provided the then outstanding principal balance does not exceed
the future borrowing base determinations established from time to time by the
banks. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Liquidity and Capital Resources" and "Description of
Indebtedness."

The Company will not receive any proceeds from the sale of shares of Common
Stock by the Selling Shareholder. See "Principal and Selling Shareholders."

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<PAGE> 18

PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY

The Common Stock has been listed on the American Stock Exchange since March
8, 1996. The trading symbol for the Company's Common Stock was changed from
"MPM" to "MHR" on March 18, 1997 to reflect the Company's name change from
Magnum Petroleum, Inc. to Magnum Hunter Resources, Inc. Prior to March 8, 1996,
the Common Stock was listed on the American Stock Exchange Emerging Company
Marketplace. At November 18, 1997, 14,638,919 shares were held by 3,648
shareholders of record. The following table sets forth the range of high and low
quarterly closing sales prices of the Common Stock for the periods indicated.

<TABLE>
<CAPTION>
AVERAGE DAILY
TRADING VOLUME
HIGH LOW (SHARES)
----- ----- --------------
<S> <C> <C> <C>
1994
First Quarter............................................. $3.38 $2.44 878
Second Quarter............................................ 4.38 2.19 2,694
Third Quarter............................................. 3.63 2.88 4,277
Fourth Quarter............................................ 4.81 3.25 15,754

1995
First Quarter............................................. $5.00 $4.00 29,283
Second Quarter............................................ 4.69 3.44 10,406
Third Quarter............................................. 4.69 3.38 19,195
Fourth Quarter............................................ 4.13 2.88 15,768

1996
First Quarter............................................. $3.63 $2.75 19,737
Second Quarter............................................ 4.75 3.06 47,360
Third Quarter............................................. 4.75 3.56 23,781
Fourth Quarter............................................ 5.06 4.25 45,658

1997
First Quarter............................................. $6.63 $4.19 96,554
Second Quarter............................................ 6.31 5.00 41,845
Third Quarter............................................. 6.44 5.00 55,194
Fourth Quarter (through November 20, 1997)................ 7.94 6.25 171,392
</TABLE>

On November 20, 1997, the closing sale price of the Common Stock on the
American Stock Exchange was $6.25 per share.

The Company has not previously paid any cash dividends on Common Stock and
does not anticipate paying dividends on Common Stock in the foreseeable future.
Other than dividends required to be paid on the Company's Preferred Stock, it is
the present intention of management to utilize all available funds for the
development of the Company's business. The Company may not pay any dividends on
Common Stock unless and until all dividend rights on outstanding Preferred Stock
have been satisfied. In addition, both the Indenture governing the Notes and the
Credit Facility restrict the payment of cash dividends. See "Description of
Capital Stock," "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and "Description of Indebtedness."

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<PAGE> 19

CAPITALIZATION

The following table sets forth the capitalization of the Company at
September 30, 1997 (i) on an actual basis and (ii) as adjusted to give effect to
(a) the sale of the 6,500,000 shares of Common Stock offered by the Company in
the Offering and the application of the estimated net proceeds therefrom and (b)
the issuance of 846,256 shares of Common Stock to holders of Warrants (which
were called for redemption on November 14, 1997). See "Use of Proceeds" and
"Description of Capital Stock." This table should be read in conjunction with
the Consolidated Financial Statements and notes thereto included elsewhere in
this Prospectus.

<TABLE>
<CAPTION>
SEPTEMBER 30, 1997
----------------------
ACTUAL AS ADJUSTED
-------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Long term debt, including current maturities:
Credit Facility(1)........................................ $ 48,000 $ 6,966
10% Senior Notes due 2007(1).............................. 140,000 140,000
Other..................................................... 49 49
-------- --------
Total long-term debt.............................. 188,049 147,015
-------- --------
Production payment liability................................ 790 790
Stockholders' equity:
Preferred Stock, $.001 par value, 10,000,000 shares
authorized: 80,000 shares issued and outstanding of
Series A Preferred Stock (no liquidation preference)
and 1,000,000 shares issued and outstanding of TCW
Preferred Stock ($10 liquidation preference per
share)(2).............................................. 1 1
Common Stock, $.002 par value, 50,000,000 shares
authorized: 14,271,975 shares issued and 21,618,231
shares issued (as adjusted)............................ 29 43
Additional paid-in capital................................ 40,291 81,311
Accumulated deficit....................................... (8,416) (8,416)
Unrealized gain on investments............................ -- --
Less treasury stock (538,633 shares of Common Stock)...... (1) (1)
-------- --------
Total stockholders' equity............................. 31,904 72,938
-------- --------
Total capitalization................................... $220,743 $220,743
======== ========
</TABLE>

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

(1) For a discussion of the Credit Facility and the Notes, see "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" and "Description of
Indebtedness."

(2) TCW Preferred Stock refers to the 1996 Series A Convertible Preferred Stock
issued to TCW. See "Description of Capital Stock -- Preferred Stock -- TCW
Preferred Stock."

19
<PAGE> 20

SELECTED CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

The following historical selected consolidated financial data of the
Company are derived from, and qualified by reference to, the Company's
Consolidated Financial Statements and the notes thereto. The income statement
data for the nine months ended September 30, 1997 are not necessarily indicative
of results for a full year. The historical selected financial data for the two
years ended December 31, 1996 were derived from the Company's audited
consolidated financial statements. The selected financial data for the nine
months ended September 30, 1996 and 1997 have been derived from the Company's
unaudited interim consolidated financial statements and include, in the opinion
of the Company's management, all adjustments (consisting of only normal
recurring adjustments) necessary to present fairly the data for such periods.
The information contained 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 of the Company and the
notes thereto included elsewhere in this Prospectus.

<TABLE>
<CAPTION>
YEAR ENDED NINE MONTHS ENDED
DECEMBER 31, SEPTEMBER 30,
------------------ ---------------------
1995 1996 1996 1997
------- ------- -------- ---------
<S> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating revenues:
Oil and gas.................................... $ 617 $10,248 $ 6,357 $ 22,793
Gas gathering, marketing and processing........ -- 5,768 3,143 7,721
Oil field services and international sales..... 32 396 385 3,792
------- ------- -------- ---------
Total operating revenues............... 649 16,412 9,885 34,306
------- ------- -------- ---------
Operating costs and expenses:
Oil and gas production......................... 268 4,390 2,305 8,521
Gas gathering, marketing and processing........ -- 4,708 2,629 5,803
Oil field services and international sales..... 26 267 521 3,482
Depreciation and depletion..................... 421 2,951 1,888 8,607
General and administrative..................... 977 1,225 670 1,128
------- ------- -------- ---------
Total operating costs and expenses..... 1,692 13,541 8,013 27,541
------- ------- -------- ---------
Operating profit (loss).......................... (1,043) 2,871 1,872 6,765
Other income................................... 77 344 214 608
Interest expense............................... (2) (2,394) (1,550) (9,298)
------- ------- -------- ---------
Income (loss) before income tax and minority
interest....................................... (968) 821 536 (1,925)
Benefit (provision) for deferred income
taxes....................................... -- (312) (204) 731
------- ------- -------- ---------
Income (loss) before minority interest........... (968) 509 332 (1,194)
Minority interest in subsidiary earnings......... -- -- -- (40)
------- ------- -------- ---------
Income (loss) before extraordinary loss.......... (968) 509 332 (1,234)
Extraordinary loss from early extinguishment of
debt........................................... -- -- -- (1,384)
------- ------- -------- ---------
Net income (loss)...................... (968) 509 332 (2,618)
Dividends applicable to preferred
shares............................... (617) (406) (382) (657)
------- ------- -------- ---------
Income (loss) applicable to common shares........ $(1,585) $ 103 $ (50) $ (3,275)
======= ======= ======== =========
Income (loss) per common share before
extraordinary loss............................. $ (0.28) $ 0.01 $ 0.00 $ (0.14)
Extraordinary loss per common share.............. -- -- -- (0.10)
------- ------- -------- ---------
Income (loss) per common share................... $ (0.28) $ 0.01 $ (0.00) $ (0.24)
======= ======= ======== =========
Common shares used in per share calculation...... 5,607 12,486 12,084 13,659
</TABLE>

20
<PAGE> 21
<TABLE>
<CAPTION>
YEAR ENDED NINE MONTHS ENDED
DECEMBER 31, SEPTEMBER 30,
------------------ ---------------------
1995 1996 1996 1997
------- ------- -------- ---------
<S> <C> <C> <C> <C>
OTHER FINANCIAL DATA:
EBITDA(1)........................................ $ (545) $ 6,166 $ 3,974 $ 15,980
Capital expenditures(2).......................... 1,244 41,471 38,787 148,429
CASH FLOWS:
Net cash (used by) provided by operating
activities..................................... $ (849) $ 3,028 $ 1,864 $ 5,897
Net cash used by investing activities............ (2,007) (41,738) (38,599) (147,959)
Net cash provided by financing activities........ 2,755 38,853 36,870 143,456
</TABLE>

<TABLE>
<CAPTION>
DECEMBER 31,
------------------- SEPTEMBER 30,
1995 1996 1997
-------- ------- -------------
<S> <C> <C> <C>
BALANCE SHEET DATA:
Working capital........................................... $ (916) $ 2,279 $ 1,927
Property, plant and equipment, net........................ 36,405 73,648 213,000
Total assets.............................................. 40,065 83,072 240,158
Total debt(3)............................................. 9,612 38,766 190,748
Stockholders' equity...................................... 24,496 35,154 31,904
</TABLE>

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

(2) Capital expenditures include cash expended for acquisitions plus normal
additions to oil and gas properties and other fixed assets.

(3) Consists of long-term debt, including $140.0 million of Notes and $48.0
million of bank debt, and $2.7 million of other notes payable at September
30, 1997, and excludes production payment liabilities of $288,000, $937,000
and $790,000 as of December 31, 1995 and 1996 and September 30, 1997,
respectively.

21
<PAGE> 22

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with the Company's
Consolidated Financial Statements and "Selected Consolidated Financial Data" and
respective notes thereto, included elsewhere herein. The information below
should not be construed to imply that the results discussed herein will
necessarily continue into the future or that any conclusion reached herein will
necessarily be indicative of actual operating results in the future. Such
discussion represents only the best present assessment of management of the
Company. Because of the size and scope of the Company's recent acquisitions and
the relatively small scale of the Company's operations prior to 1996, the
results of operations from period to period are not necessarily comparative.

BACKGROUND

In December 1995 the Company entered into the Magnum Hunter Combination
pursuant to which the Company issued to Hunter 5,085,077 shares of Common Stock
and 111,825 shares of the Company's Series C Preferred Stock (which were
subsequently converted into 335,475 shares of Common Stock) and assumed certain
liabilities in exchange for all the capital stock of Hunter's subsidiaries (the
"Hunter Subsidiaries"). The acquired assets included developed and undeveloped
oil and gas properties, a gas gathering system, and an established oil and gas
consulting and operating company, and were valued at $12.5 million at the time
of acquisition based upon the then current stock price. In connection with the
Magnum Hunter Combination, the management of Hunter assumed operating control of
the Company.

The new management implemented a business strategy that emphasized
acquisition of long-lived, Proved Reserves with significant exploitation and
development opportunities that management considered to have a lower risk
profile than the Company's historic projects. Prior to the Magnum Hunter
Combination, the Company was primarily focused on developing and selling higher
risk, non-operated exploratory and development projects and did not focus on
acquisitions. In order to improve the economics of acquisitions, the Company
emphasizes strict cost control in all aspects of its business and seeks to
operate its properties wherever possible. The Company also participates, to a
lesser extent, in selected exploration projects on a controlled risk basis.

As a part of the Company's new strategy, in June 1996 the Company acquired
the Panoma Properties, which include interests in 520 gas wells in the Texas
Panhandle and western Oklahoma and an associated 427 mile gas gathering system,
from Burlington for a net purchase price of $34.7 million. The Company assumed
operations of approximately 90% of the wells and of the gathering system and
began planning for increased density development drilling on the Panoma
Properties.

In January 1997 the Company purchased for $2.5 million a 50% interest in a
gas processing plant, the McLean Gas Plant, which currently processes 100% of
the gas produced from the Panoma Properties. The Company receives 100% of the
net profits of the plant until it recoups its investment, after which time the
Company will receive 50% of the net profits. As of September 30, 1997 the
Company had recouped approximately 35% of its $2.5 million investment.
Management believes that the acquisition of the McLean Gas Plant allows the
Company to capture a significant portion of the profits generated from
processing the gas produced at the Panoma Properties that would otherwise go to
third party processors.

In April 1997 the Company purchased the Permian Basin Properties from
Burlington for a net purchase price of $133.0 million after purchase price
adjustments of $10.5 million. These properties consist of approximately 1,852
producing oil and gas wells and associated acreage in west Texas and southeast
New Mexico. This acquisition substantially increased the Company's cash flow and
inventory of exploitation, development and exploration opportunities.

On April 29, 1997 the Company received and accepted two new loan
commitments from Bankers Trust Company, as Agent, and other banks for senior
credit facilities for the Company and several of its subsidiaries. The two new
senior credit facilities were structured as the $130.0 million Credit Facility
with a term of five years and a $60.0 million one year senior subordinated
bridge facility (the "Term Loan Facility") convertible

22
<PAGE> 23

into a five year term loan. The new credit facilities were conditioned, among
other things, upon the closing of the Permian Basin Acquisition, which took
place on April 30, 1997. The Credit Facility gives the Company the flexibility
of choosing a range of either "LIBOR" or "Prime" based interest rate options.
This Credit Facility replaced the Company's previously existing $100.0 million
revolving credit facility.

On May 29, 1997 the Company placed, through a Rule 144A private placement
offering, $140.0 million aggregate principal amount of Notes. Net proceeds from
the sale of the Notes were used to completely repay the Term Loan Facility in
the principal amount of $60.0 million and to repay a substantial portion of the
indebtedness outstanding under the Credit Facility. The Notes bear interest at
10% per annum, with interest payable on June 1 and December 1 commencing on
December 1, 1997.

The Company uses the full cost method of accounting for its investment in
oil and gas properties. Under the full cost method of accounting, all costs of
acquisition, exploration and development of oil and gas reserves are capitalized
into a "full cost pool" as incurred, and properties in the pool are depleted and
charged to operations using the unit-of-production method based on the ratio of
current production to total proved oil and gas reserves. To the extent that such
capitalized costs (net of accumulated depreciation, depletion and amortization)
less deferred taxes exceed the SEC PV-10 of estimated future net cash flow from
Proved Reserves of oil and gas, and the lower of cost or fair value of unproved
properties after income tax effects, such excess costs are charged to
operations. Once incurred, a write-down of oil and gas properties is not
reversible at a later date even if oil or gas prices increase. While the Company
has never been required to write-down its asset base, significant downward
revisions of quantity estimates or declines in oil and gas prices from those in
effect on December 31, 1996 which are not offset by other factors could result
in a write-down for impairment of oil and gas properties.

COMPARISON OF NINE MONTHS ENDED SEPTEMBER 30, 1997 TO NINE MONTHS ENDED
SEPTEMBER 30, 1996

As discussed above, the Company acquired the Panoma Properties in June
1996, the McLean Gas Plant in January 1997, and the Permian Basin Properties in
April 1997. As such, the results of operations for the nine month period ended
September 30, 1997 included nine months of operations for the Panoma Properties
and the McLean Gas Plant and five months for the Permian Basin Properties, while
the corresponding period in 1996 contained three months of operations for the
Panoma Properties and no results related to the McLean Gas Plant and the Permian
Basin Properties. Unless otherwise stated, the increases in the 1997 interim
period over the 1996 period were a result of these acquisitions.

Oil and gas sales were $22.8 million in 1997, a 259% increase over sales of
$6.4 million in 1996. In 1997, the Company sold 489,771 Bbl of oil, a 250%
increase, and 6,451 MMcf of gas, a 295% increase. The price received for oil was
$17.79 per Bbl and for gas was $2.18 per Mcf in 1997, representing an 11%
decrease in oil price from $19.92 per Bbl in 1996 and a 2% decrease in gas price
from $2.23 per Mcf in 1996. Oil and gas production costs increased 270% to $8.5
million in 1997 from $2.3 million in 1996. The gross operating margin from oil
and gas production was $14.3 million in 1997, a 252% increase over gross
operating margin of $4.1 million in 1996, principally due to the volume increase
of oil and gas sold. On an equivalent unit basis, the gross margin was $1.52 per
Mcfe in 1997 versus $1.64 in 1996, a 7% decrease, principally due to decline in
sales price received for both oil and gas between 1996 and 1997.

Gas gathering, marketing, and processing revenues were $7.7 million in the
1997 period, a 146% increase over revenues of $3.1 million in 1996, principally
as a result of the acquisition of the Panoma gas gathering system and the McLean
Gas Plant. Costs from these activities were $5.8 million in 1997, a 121%
increase over costs of $2.6 million in 1996. Gross operating margin was $1.9
million in 1997 versus $514,000 in 1996, a 273% increase. As a result of the
acquisition of the Panoma gas gathering system, total gathering system
throughput increased 100% to 20.2 MMcf per day in 1997 compared with 10.1 MMcf
per day in 1996. Due to the McLean Gas Plant acquisition, gas plant processing
throughput was 14.5 MMcf per day in 1997 versus none reported in 1996. Gross
operating margin from gathering operations was $0.24 per Mcf of throughput in
1997 versus $0.29 per Mcf in 1996. The gross operating margin from gas
processing was $0.23 per Mcf of throughput versus none reported in 1996.

23
<PAGE> 24

Revenues from oil field services and international sales were $3.8 million
in 1997, an 885% increase over revenues of $385,000 in 1996, principally due to
an increase in sales of Hunter Butcher International, L.L.C. ("Hunter Butcher")
in the amount of $3.4 million. Operating costs were $3.5 million in 1997 a $3.0
million increase over 1996, also principally due to Hunter Butcher. The gross
operating margin from these activities was $310,000 in 1997 versus a loss of
$136,000 in the 1996 period. The margin from Hunter Butcher operations was
$60,000 in 1997 versus $32,000 in the 1996 period. Oil field services produced
an operating margin of $250,000 in 1997 versus a loss of $168,000 in 1996.

Depreciation and depletion expense increased 356% to $8.6 million in 1997
from $1.9 million in 1996 due to the acquisitions. Depletion expense on oil and
gas production in 1997 was $8.0 million, or $0.85 per Mcfe, in 1997 versus $1.6
million, or $0.66 per Mcfe in 1996. General and administrative expense increased
68% to $1.1 million in 1997 from $670,000 in 1996, due to increased staffing and
other costs as a result of the acquisitions.

Operating profit increased to $6.8 million in 1997 from $1.9 million in
1996, a 261% increase. Other income increased 184% to $608,000 due to gain on
sale of marketable securities. Interest expense increased to $9.3 million in
1997 from $1.6 million in 1996, an increase of 500%, due to increased levels of
borrowing under the Company's revolving credit lines, the Notes, and bridge
financing used to fund the acquisitions previously mentioned. The Company
incurred a net loss before income tax and minority interest of $1.9 million in
1997, versus net income of $536,000 in 1996, principally due to interest expense
on the acquisitions exceeding operating income and due to the higher charge for
depreciation and depletion. The Company provided for a deferred income tax
benefit of $731,000 on this loss in 1997 versus deferred income tax expense of
$204,000 in 1996. After recording a $40,000 minority interest in Hunter Butcher,
the Company reported a net loss in 1997 before extraordinary items of $1.2
million, or $0.14 per common share, versus a $332,000 net profit, or no cents
per common share, in 1996.

The Company realized an extraordinary loss of $1.4 million ($0.10 per
common share) as required under Accounting Principles Board ("APB") Statement
No. 26 and Statement of Financial Standards ("SFAS") No. 4, from the early
extinguishment of bank debt. The early extinguishment was a result of the Notes
financing and new amended revolving credit agreements with banks arranged to
repay the Company's previous credit facility in conjunction with the purchase of
the Permian Basin Properties from Burlington. The net loss in 1997, after the
extraordinary charge, applicable to common shareholders was $3.3 million ($0.24
per common share) in 1997 compared to a loss of $50,000 (no cents per common
share) in 1996. The Company accrued $657,000 in dividends on its preferred stock
in 1997 versus $382,000 in 1996.

COMPARISON OF YEAR ENDED DECEMBER 31, 1996 TO YEAR ENDED DECEMBER 31, 1995

After deduction for preferred dividends, the Company reported net income
applicable to common shares for the year ended December 31, 1996 of $0.1
million, a $1.7 million increase as compared to the net loss of $1.6 million for
the year ended December 31, 1995. Prior to the preferred dividends in both
periods, the Company reported net income of $0.5 million in 1996, a $1.5 million
increase over 1995. Net income per common share was $0.01 for 1996, as compared
to a $0.28 per share loss in 1995. This increase was the result of higher
production volumes in 1996 from (i) acquisition activities, which included the
Magnum Hunter Combination in December 1995 and the Panoma Acquisition in June
1996, (ii) increased prices received for oil and gas products, (iii) the
acquisition of gas gathering systems in the Panoma Acquisition, and (iv) gas
marketing activities. During 1996, oil and gas production volumes increased
significantly to 3.8 Bcfe, an average of 10,470 Mcfe per day, as compared to 0.3
Bcfe, an average of 773 Mcfe per day, in 1995. The increased revenues recognized
from production volumes were aided by a 22% increase in the average price
received per Mcfe of production to $2.68 during 1996. The average oil price
increased 31% to $20.46 per Bbl in 1996, as compared to $15.60 per Bbl in 1995,
while average gas prices increased 62% to $2.37 per Mcf in 1996 as compared to
$1.46 per Mcf in 1995.

As a result of the acquisition activity and higher prices, total revenues
in 1996 were $16.4 million, a $15.8 million increase over 1995. This increase
consisted of an increase in oil and gas sales of $9.6 million from 1995 to 1996
and an increase in gas gathering, marketing and services revenue of $6.1 million
over the same period.

24
<PAGE> 25

After the Panoma Acquisition in June 1996, the percentage of the Company's
reserves attributable to gas was 74% as compared to 38% at the end of 1995. Due
to the Company's owning more properties and larger volume of production, oil and
gas production expenses increased $4.1 million to $4.4 million in 1996 versus
$0.3 million in 1995. The average cost of oil and gas produced per Mcfe was
$1.15 in 1996, an increase of $0.20 per Mcfe, due to costs of startup of
operations at the Panoma Properties.

Gross margin from oil and gas production increased $5.5 million to $5.9
million in 1996 from $0.4 million in 1995. Gross margins from gas gathering,
marketing, and services increased to $1.2 million in 1996, from $0.0 million in
1995.

Depreciation and depletion expense increased to $3.0 million in 1996, a
$2.5 million increase over 1995, as a result of the Panoma Acquisition and the
Magnum Hunter Combination. The Company-wide depreciation and depletion rate was
$0.77 per Mcfe in 1996 versus $1.49 per Mcfe in 1995. General and administrative
expense increased to $1.2 million in 1996, a $0.2 million increase over 1995,
due to higher operational staffing and associated costs as a result of expanded
operations, partially offset by a reduction in promotional and related expenses.
Other income increased to $0.3 million in 1996 due to a gain on sale of assets.
Interest expense increased to $2.4 million due to increased financing costs
incurred as a result of the Magnum Hunter Combination and the Panoma
Acquisition.

The Company made a provision for deferred income taxes of $0.3 million in
1996. No income taxes were due for 1996 as a result of utilization of net
operating loss carryforwards. At December 31, 1996 the Company had $6.9 million
available in such carryforwards to offset against future income. Dividends
applicable to preferred stock were $0.4 million for 1996, a $0.2 million
decrease from 1995, due to the redemption of the Series B and Series C Preferred
Stock during 1996, offset by the effect of the issuance of the TCW Preferred
Stock at the end of 1996.

LIQUIDITY AND CAPITAL RESOURCES

The Company has three principal operating sources of cash: (i) sales of oil
and gas, (ii) revenues from gas gathering, processing, and marketing, and (iii)
revenues from petroleum management and consulting services. The Company's cash
flow is highly dependent upon oil and gas prices. Decreases in the market price
of oil and gas could result in reductions of both cash flow and the Borrowing
Base under the Company's Credit Facility, which would result in decreased funds
available, including funds for capital expenditures.

In December 1996 the Company issued $10.0 million of TCW Preferred Stock to
facilitate its development drilling program.

On April 30, 1997 the Company closed the acquisition of the Permian Basin
Properties for a net purchase price of approximately $133.0 million. At the same
time, the Company's previously existing $100.0 million credit facility was
replaced by two new credit facilities, the $130.0 million Credit Facility and
the $60.0 million Term Loan Facility, for a total of $190.0 million. The initial
advances under these new facilities totaled $179.5 million, including funds to
complete the Permian Basin Acquisition, to pay principal and accrued interest
remaining on the Company's previous credit facility, and to provide cash for
working capital purposes.

On May 29, 1997 the Company sold, through a Rule 144A private placement
offering, $140.0 million aggregate principal amount of Notes. Net proceeds from
the sale of the Notes were used to completely repay the Company's Term Loan
Facility in the principal amount of $60.0 million and to repay a substantial
portion of the indebtedness outstanding under the Credit Facility. The Notes
bear interest at 10% per annum, with interest payable on June 1 and December 1
commencing on December 1, 1997. After paydown, the maximum commitment under the
Credit Facility was reduced from $130.0 million to $75.0 million, with a
Borrowing Base of $60.0 million. The Credit Facility was amended effective
September 30, 1997 to increase the maximum commitment from $75.0 million to
$125.0 million, increase the Borrowing Base by $5.0 million to $65.0 million and
modify the Consolidated EBITDA to Interest Expense ratio. With these
adjustments, total long-term debt under the Credit Facility at September 30,
1997 was $48.0 million, leaving $17.0 million available to draw at such time,
prior to the next borrowing base redetermination based upon financial results of
the Company. At November 17, 1997, total long-term debt under the Credit
Facility was $46.0 million,

25
<PAGE> 26

leaving $19.0 million available to draw at such time. At September 30, 1997, the
Company had $3.1 million in cash and cash equivalents and $1.9 million in net
working capital, in addition to the funds available under the Credit Facility.

The Company called for redemption on November 14, 1997 its publicly traded
Warrants, each of which was exercisable for three shares of Common Stock at an
exercise price of $5.50 per share and redeemable at $0.02 per Warrant. As a
result, Warrants were exercised for an aggregate of 846,256 shares of Common
Stock and the remaining Warrants covering 7,920 shares of Common Stock were
redeemed. The Company received cash proceeds of approximately $4.7 million.

For 1996 the Company had a net increase in cash of $143,000. The Company's
operating activities provided net cash of $3.0 million, principally from
operating income before depreciation, depletion and deferred taxes, reduced by a
net increase in accounts receivable over accounts payable. The Company used
$41.7 million in investing activities, principally for additions to property and
equipment of $41.5 million, as well as increases in deposits and other assets.
Financing activities provided $38.9 million of cash, principally from the
aggregate proceeds from the issuance of long-term debt of $56.5 million and
production payments of $750,000, less payments on such debt and production
payments of $27.5 million, as well as proceeds from the issuance of preferred
stock of $9.8 million. The Company also paid $295,000 to redeem a portion of the
outstanding Series C Preferred Stock and $438,000 to pay dividends on preferred
stock.

For 1995 the Company had a net decrease in cash of $101,000 as the proceeds
received from the sale of preferred stock were principally used for oil and gas
acquisition and development activity and for the payment of dividends and
payables. The Company's operating activities used net cash of $849,000,
principally as a result of the net loss from operations and the payoff of a
substantial amount of accounts payable. Investing activities used net cash of
$2.0 million, largely from acquisition and development of oil and gas
properties. Financing activities accounted for net cash provided of $2.8
million, principally from the proceeds received due to the issuance of preferred
stock mentioned above. Partially offsetting the proceeds from the stock
issuances were advances made to Magnum Hunter Production, Inc. for acquisition
costs and working capital of $1.0 million, prior to the Magnum Hunter
Combination and the ultimate consolidation, and the payment of preferred
dividends of $583,000.

CAPITAL REQUIREMENTS

For fiscal 1997 the Company has budgeted approximately $20.0 million for
development and exploration activities, including $5.0 million budgeted for
development projects on the Permian Basin Properties and $3.0 million budgeted
for exploration projects. In addition, with respect to the recently closed
Permian Basin Acquisition, the Company anticipates that it will spend
approximately $38.1 million over a four year period beginning in 1997 in a
development program to enhance an existing waterflood project in the Westbrook
Field located in Mitchell County, Texas. For fiscal 1998, the Company has
budgeted approximately $36.0 million on development and exploration activities,
of which $6.0 million is projected to be spent on exploration projects,
including geological and geophysical expenses. The Company is not contractually
obligated to proceed with any of its budgeted capital expenditures. The amount
and allocation of future capital expenditures will depend on a number of factors
that are not entirely within the Company's control or ability to forecast,
including drilling results and changes in oil and gas prices. As a result,
actual capital expenditures may vary significantly from current expectations.

On April 30, 1997, the Company acquired from Burlington, effective as of
January 1, 1997, the Permian Basin Properties. The net purchase price was $133.0
million after adjustments. The Company financed the acquisition of the Permian
Basin Properties with the $130.0 million Credit Facility and the $60.0 million
Term Loan Facility. The Credit Facility and the Term Loan Facility were used to
pay the $123.0 million balance (after deducting a $10.0 million earnest money
deposit) of the net purchase price, to repay the $53.7 million in outstanding
indebtedness under the Company's previous credit facility and to pay costs
associated with the Permian Basin Acquisition and the related financings. In
addition to providing the Company with significant new sources of earnings and
operating cash flow, management of the Company believes the Permian Basin

26
<PAGE> 27

Properties will provide significant opportunities for exploitation and
development of both oil and gas reserves through a combination of enhanced
recovery projects and new drilling projects.

Based upon the Company's anticipated level of operations, the Company
believes that cash flow from operations together with the availability under the
Credit Facility (approximately $17.0 million as of September 30, 1997) will be
adequate to meet its anticipated requirements for working capital, capital
expenditures and scheduled interest payments for the foreseeable future. As
adjusted for the Offering and exercise of the Warrants, the Company would have
had approximately $58.0 available for borrowing under the Credit Facility as of
September 30, 1997.

INFLATION AND CHANGES IN PRICES

During the past several years, the Company has experienced some inflation
in oil and gas prices with moderate increases in property acquisition and
development costs. During 1996, the Company received somewhat higher commodity
prices for the natural resources produced from its properties. The results of
operations and cash flow of the Company have been, and will continue to be,
affected to a certain extent by the volatility in oil and gas prices. Should the
Company experience a significant increase in oil and gas prices that is
sustained over a prolonged period, it would expect that there would also be a
corresponding increase in oil and gas finding costs, lease acquisition costs,
and operating expenses. Periodically the Company enters into futures, options,
and swap contracts to reduce the effects of fluctuations in crude oil and gas
prices. It is policy of the Company not to enter into any such arrangements
which exceed 50% of the Company's oil and gas production during the next 12
months.

The Company markets oil and gas for its own account, which exposes the
Company to the attendant commodities risk. Substantially all of the Company's
gas production is currently sold to gas marketing firms or end users either on
the spot market on a month-to-month basis at prevailing spot market prices or
under long-term contracts based on current spot market prices. The Company
normally sells its oil under month-to-month contracts with a variety of
purchasers.

HEDGING ACTIVITY

Periodically, the Company enters into futures, options, and swap contracts
to reduce the effects of fluctuations in crude oil and gas prices. As of
September 30, 1997 the Company had 33% of its oil production and 43% of its gas
production hedged although lesser or greater amounts may be hedged in the
future. At September 30, 1997 the Company had open contracts for oil price
collars of 30,000 Bbls of oil per month (with cap and floor prices of $22.25 and
$18.50, respectively) through December 1998. At September 30, 1997 the Company
had open contracts for gas price swaps of 100,000 MMBtu of gas per month at
$1.905 per MMBtu through January 1998, 100,000 MMBtu of gas per month at $1.77
per MMBtu through January 1998 and 300,000 MMBtu of gas per month at an average
price of $2.67 per MMBtu through March 1998. The average Btu content of gas
produced by the Company exceeds 1,100 Btu per Mcf of gas. Therefore, each of the
above gas prices should be increased by 10% to reflect the actual gas price per
Mcf received by the Company. All of these swaps are against the El Paso Permian
Basin Index. These contracts expire monthly. The gains or losses on the
Company's hedging transactions are determined as the difference between the
contract price and a reference price, generally closing prices on New York
Mercantile Exchange. The resulting transaction gains and losses are determined
monthly and are included in the period the hedged production or inventory is
sold. Net gains or losses relating to these derivatives for the years ended
December 31, 1995 and 1996 were $0.0 and $(0.3) million, respectively.

YEAR 2000 MODIFICATIONS

The Company is currently reviewing its computer systems in order to
evaluate necessary modifications for the year 2000. The Company does not
currently anticipate that it will incur material expenditures to complete any
such modifications.

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BUSINESS AND PROPERTIES

THE COMPANY

Magnum Hunter is an independent energy company engaged in the exploitation
and development, acquisition, exploration and operation of oil and gas
properties with a geographic focus in Texas, Oklahoma and New Mexico. In
December 1995 the Company consummated the Magnum Hunter Combination and the
management of Hunter assumed operating control of the Company. The new
management implemented a business strategy that emphasized acquisitions of
long-lived Proved Reserves with significant exploitation and development
opportunities where the Company generally could control the operations of the
properties. As part of this strategy, in June 1996 the Company acquired the
Panoma Properties from Burlington for a net purchase price of $34.7 million.
Additionally, in April 1997 the Company acquired the Permian Basin Properties
from Burlington for a net purchase price of $133.0 million. The Company
presently intends to focus its efforts on its substantial inventory of
exploitation and development opportunities, further acquisitions and, to a
lesser extent, selected exploratory drilling prospects. The Company has
identified over 600 development drilling locations (including both production
and injection wells) on its properties, substantially all of which are low-risk
in-fill drilling opportunities.

On a pro forma basis at December 31, 1996, the Company had an interest in
2,581 wells and had estimated Proved Reserves of 314.2 Bcfe with an SEC PV-10 of
$408.0 million. As adjusted to use market prices in effect on March 31, 1997,
the Proved Reserves were 300.5 Bcfe with an SEC PV-10 of $224.8 million on a pro
forma basis at December 31, 1996. Approximately 68% of these reserves were
Proved Developed Producing Reserves and 86% were attributable to the Panoma
Properties and the Permian Basin Properties. On a pro forma basis at December
31, 1996, the Company's Proved Reserves had an estimated Reserve Life of 14.6
years and were 61% gas. The Company serves as operator for approximately 71% of
its properties (based on the number of producing wells in which the Company owns
an interest). Additionally, the Company owns over 485 miles of gas gathering
systems and a 50% interest in a gas processing plant that is connected to the
Company's largest gas gathering system, which was purchased with the Panoma
Properties.

Beginning with the Magnum Hunter Combination in December 1995, the Company
has made nine acquisitions for an aggregate net purchase price of $185.4
million. This strategy has added approximately 305.6 Bcfe of reserves
(determined as of the respective times of their acquisition) at an average cost
of $0.61 per Mcfe, as well as a 427 mile gas gathering system and a 50% interest
in the McLean Gas Plant. As a result of its acquisitions, the Company has
achieved substantial growth as described below:

- Proved Reserves increased to 314.2 Bcfe on a pro forma basis at year end
1996 (300.5 Bcfe on a pro forma basis at year end 1996 as adjusted for
March 31, 1997 market prices) from 36.7 Bcfe at year end 1995;

- Average daily production increased to 50.8 MMcfe in third quarter 1997
from 0.8 MMcfe in fiscal 1995; and

- EBITDA increased to $16.0 million for the nine months ended September 30,
1997 from $(0.5) million in fiscal 1995.

BUSINESS STRATEGY

The following are key elements of the Company's strategy:

- Exploitation and Development of Existing Properties. The Company has a
substantial inventory of exploitation projects including development
drilling, workovers and recompletions. The Company seeks

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<PAGE> 29

to maximize the value of its properties through development activities
including in-fill drilling, waterflooding and other enhanced recovery
techniques.

RECENT ACQUISITIONS

The most significant of the Company's completed acquisitions are the
Permian Basin Acquisition, the Panoma Acquisition, the McLean Plant Acquisition
and the Magnum Hunter Combination.

Permian Basin Acquisition

On April 30, 1997 the Company acquired from Burlington, effective as of
January 1, 1997, the Permian Basin Properties, consisting of 25 field areas in
west Texas and 22 field areas in southeast New Mexico, for a net purchase price
of $133.0 million after adjustments aggregating $10.5 million. The primary
producing formations include the Yates, Seven Rivers and Queen in Lea and Eddy
Counties, New Mexico; the Atoka in the Brunson Ranch Field in Loving County,
Texas; the Clearfork in the Westbrook Field in Mitchell County, Texas; the San
Andres in the Levelland/Slaughter Field in Cochran County, Texas; and the Canyon
Sand in Sutton County, Texas. The Permian Basin Properties include 1,852
producing oil and gas wells on approximately 113,810 gross acres (82,175 net
acres). One of the Company's subsidiaries, Gruy Petroleum Management Co.
("Gruy"), serves as operator on approximately 66% of the wells on the Permian
Basin Properties. Management of the Company believes the Permian Basin
Properties provide significant opportunities for exploitation and development of
both oil and gas through enhanced recovery projects and drilling.

During 1996 daily net production from the Permian Basin Properties was 25.8
MMcf per day of gas and over 2,500 Bbl per day of oil. According to Ryder Scott
Co. ("Ryder Scott"), independent petroleum engineers engaged by the Company to
evaluate the Permian Basin Properties, as of December 31, 1996, the Permian
Basin Properties had Proved Reserves of 15.3 MMBbl of oil and 99.9 Bcf of gas,
or on a Natural Gas Equivalent Basis, 191.6 Bcfe. Ryder Scott further estimated
the future net cash flows and the SEC PV-10 for the Permian Basin Properties to
be $468.8 million and $243.3 million, respectively, as of December 31, 1996
based on prices of $23.61 per Bbl of oil and $4.12 per Mcf of gas at December
31, 1996. Based on market prices of $20.41 per Bbl of oil and $2.30 per Mcf of
gas at March 31, 1997, future net cash flows and the SEC PV-10 for the Permian
Basin Properties would be $267.3 million and $139.6 million, respectively, as of
December 31, 1996. Approximately 68% of the Proved Reserves were classified as
Proved Developed Producing Reserves as of December 31, 1996. See "-- Oil and Gas
Reserves." Based on the $133.0 million adjusted purchase price and Proved
Reserves of 186.9 Bcfe as of April 30, 1997, the Company paid approximately
$0.71 per Mcfe for the Permian Basin Properties.

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<PAGE> 30

The major fields in the Permian Basin Properties are the Westbrook,
Levelland/Slaughter, Lea County Shallow Properties and the Brunson Ranch.

Westbrook. The Westbrook Field covers 45 square miles of the Permian
Basin in Mitchell County, Texas and produces from the Clearfork formation
at a depth of approximately 3,200 feet. The following table sets forth
information regarding three properties in the Westbrook Field at the time
they were purchased in the Permian Basin Acquisition on April 30, 1997. The
interests acquired in the Permian Basin Acquisition include the following
three properties in the Westbrook Field:

<TABLE>
<CAPTION>
GROSS OIL
WELL WORKING NET REVENUE PRODUCTION
PROPERTY OPERATOR COUNT INTEREST INTEREST (BBL/D)
-------- ----------- ----- -------- ----------- ----------
<S> <C> <C> <C> <C> <C>
Southwest Westbrook Unit... Company 135 89.9% 77.5% 560
Morrison "G" Lease(1)...... Company 2 83.3% 72.9% 10
North Westbrook Unit....... Third Party 294 2.0% 2.8%(2) 1,560
</TABLE>

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

(1) Subsequent to the Permian Basin Acquisition, the Company acquired the
remaining 16.7% of the working interest in the Morrison "G" Lease,
increasing its Net Revenue Interest to 87.5%.

(2) Includes an overriding Royalty Interest.

Most of the leases and units in the field had waterflood projects
initiated in the 1960's and those projects are still active. The Company
plans to initiate waterflood enhancement operations on the Southwest
Westbrook Unit and the Morrison "G" Lease.

Ryder Scott attributed approximately 10.0%, or $24.3 million, of the
SEC PV-10 at December 31, 1996 (9.9%, or $13.8 million, at such date using
March 31, 1997 market prices) to a four year enhancement program,
commencing in 1997, on an existing waterflood project on the Westbrook
Field in Mitchell County, Texas. The Company has identified approximately
250 drilling locations, including production and injection wells, to
further develop the fields at a cost of approximately $38.1 million. When
completed, the properties will be developed on a ten acre, line drive
waterflood pattern, as opposed to the current 28 acre, five-spot pattern.
The Company has budgeted approximately $11.0 million for 1998 for
development of the Westbrook Field.

Levelland/Slaughter. The Levelland and Slaughter Fields consist of 155
wells located in Cochran County, Texas that produce from the San Andres
formation at a depth of 5,000 feet. The interests acquired in the Permian
Basin Acquisition include the following three properties in the Levelland
and Slaughter Fields:

<TABLE>
<CAPTION>
GROSS OIL
WELL WORKING NET REVENUE PRODUCTION
PROPERTY OPERATOR COUNT INTEREST INTEREST (BBL/D)
-------- -------- ----- -------- ----------- ----------
<S> <C> <C> <C> <C> <C>
TLB Unit.......................... Company 20 100.0% 87.3% 90
Veal Lease........................ Company 52 100.0% 87.1% 250
NW Slaughter Unit................. Company 83 74.8% 62.8% 310
</TABLE>

Discovered in the 1930's, all three properties have been actively
waterflooded since the 1970's. While the projects are mature, additional
drilling and waterflood enhancement are likely. No Proved Undeveloped
Reserves were assigned by Ryder Scott to either the Veal Lease or the TLB
Unit. Proved Undeveloped Reserves were assigned by Ryder Scott to the NW
Slaughter Unit in contemplation of a carbon dioxide injection project which
is anticipated for that property. The operator of an adjacent property has
been successfully injecting carbon dioxide for several years to enhance
production.

Lea County Shallow Properties. The Lea County Shallow Properties
consist of approximately 300 wells in Lea County, New Mexico which are in
the Rhodes, Jalmat, Monument, Langlie Mattix, Eumont and Eunice Fields. The
fields produce from the Yates, Seven Rivers, Queen and other formations at
depths generally shallower than 3,000 feet. Production is generally high
Btu gas, which produces into low pressure gathering systems. No Proved
Undeveloped Reserves have been assigned by

30
<PAGE> 31

Ryder Scott to the properties, but the Company anticipates that numerous
recompletion, stimulation, workover or development drilling opportunities
will result from detailed geological and engineering studies which are
planned.

Brunson Ranch. The Brunson Ranch Field consists of four wells located
in Loving County, Texas in the deep Delaware Basin geological province of
the Permian Basin. Three of these wells are currently producing a total of
approximately 2.4 MMcf of gas per day from the Atoka formation at a depth
of approximately 16,000 feet. The Company recompleted an additional well in
June 1997 that is producing 2.1 MMcf of gas per day. Undeveloped potential
exists on the properties through redrilling the Atoka formation and
completing such wells using technology designed for high bottom hole
pressure conditions.

Burlington has agreed to indemnify the Company for breaches by Burlington
of the purchase agreement as well as any claims attributable to or arising out
of acts or omissions of Burlington (including, but not limited to, environmental
claims) occurring before January 1, 1997. There are certain limitations on the
amount of, and time period for bringing, a claim for indemnity made by the
Company. Burlington is a defendant in two actions claiming that Burlington
underpaid royalty owners on properties in New Mexico and Texas, including
properties that are a part of the Permian Basin Properties. The plaintiffs in
the New Mexico action are seeking class certification while the Texas action has
been certified as a class action. Burlington's indemnity would hold the Company
harmless from any of these claims arising prior to January 1, 1997. The Company
has also agreed, subject to certain limitations, to indemnify Burlington for
matters arising subsequent to January 1, 1997 as well as for certain liabilities
and obligations assumed by the Company as part of the purchase transaction.

Panoma Acquisition

On June 28, 1996, the Company purchased from Burlington interests in 520
gas wells in the Texas Panhandle and western Oklahoma (470 of which are operated
by the Company) and the associated 427 mile gas gathering system. The net
purchase price, after certain purchase price adjustments, was $34.7 million,
funded by borrowings under the Company's previous credit facility. Gruy is the
operator of the gas gathering system and the wells that were previously operated
by Burlington. According to Gaffney, Cline & Associates, independent petroleum
engineers engaged by the Company to evaluate the Panoma Properties ("Gaffney,
Cline"), the Proved Reserves attributable to the Panoma Properties as of
December 31, 1996 aggregated 77.3 Bcfe with an SEC PV-10 of $111.0 million. As
adjusted to use market prices in effect on March 31, 1997, the Proved Reserves
attributable to the Panoma Properties as of December 31, 1996 aggregated 74.2
Bcfe with an SEC PV-10 of $53.3 million.

The Panoma Properties consist of approximately 520 gas wells in the West
Panhandle, East Panhandle, and South Erick Fields along a corridor 65 miles long
and 20 miles wide stretching from Beckham County, Oklahoma to Gray County,
Texas. All wells are less than 2,800 feet deep and produce dry gas from the
Granite Wash and/or Brown Dolomite formations.

McLean Plant Acquisition

On January 1, 1997, the Company complemented its Panoma Acquisition by
purchasing for $2.5 million a 50% ownership interest in the McLean Gas Plant,
which is connected to the Panoma gas gathering system, and a related products
pipeline. The Company receives 100% of the net profits from the McLean Gas Plant
until it recoups the $2.5 million purchase price, after which time it will
receive 50% of the net profits. See "-- Gathering and Processing of Gas."

Magnum Hunter Combination

The recent growth experienced by the Company commenced with the Magnum
Hunter Combination in December 1995. In that transaction, the Company assumed
certain liabilities and issued an aggregate value of $12.5 million of stock
consisting of 5,085,077 shares of Common Stock and 111,825 shares of the
Company's Series C Preferred Stock, which were subsequently converted into
335,475 shares of Common Stock. In connection with the Magnum Hunter
Combination, management of the Company was replaced by Hunter's

31
<PAGE> 32

management team. The acquisition of the Hunter Subsidiaries significantly
increased the size and expanded the nature of the Company's business. The Hunter
Subsidiaries were engaged in: (i) the acquisition, production and sale of crude
oil; (ii) the gathering, transmission and marketing of gas; (iii) the management
and operation of producing oil and gas properties for interest owners; and (iv)
the provision of consulting and U.S. export services to facilitate Latin
American trade in energy products. The acquisition of Gruy, a Hunter Subsidiary
that specializes in the management of producing properties, has enabled the
Company to gain a higher level of expertise in operating oil and gas properties.
Estimated Proved Reserves for the properties acquired in the Magnum Hunter
Combination were 3.1 MMBbl of oil and 11.0 Bcf of gas as of December 31, 1995.

DEVELOPMENT AND EXPLORATION ACTIVITIES

Overview

The Company presently intends to focus its efforts on its substantial
inventory of exploitation and development activities, further acquisitions and,
to a lesser extent, selected exploratory drilling prospects.

The Company seeks to minimize its overhead and capital expenditures by
subcontracting the drilling, redrilling and workover of wells to independent
drilling contractors and by outsourcing other services. The Company typically
compensates its drilling subcontractors on a turnkey (fixed price), footage or
day rate basis depending on the Company's assessment of risk and cost
considerations.

Development Drilling

The Company's development strategy focuses on maximizing the value and
productivity of its oil and gas asset base through development drilling and
enhanced recovery projects. The Company has budgeted approximately $30.0 million
for exploitation and development activities for 1998. The Company has identified
over 600 development drilling locations (including both production and injection
wells) on its properties. In exploiting its producing properties, the Company
relies upon its in-house technical staff of petroleum engineering and geological
professionals and utilizes the services of outside consultants on a selective
basis.

Permian Basin Properties. In evaluating the Permian Basin Properties,
the Company believes there are many development opportunities. The Company
has identified approximately 400 drilling locations, including production
and injection wells, on the Permian Basin Properties. Engineering and
geological studies are being initiated to more precisely identify specific
development locations. In addition, in evaluating the Permian Basin
Properties, Ryder Scott attributed approximately 10.0%, or $24.3 million,
of their SEC PV-10 at December 31, 1996 (9.9%, or $13.8 million, at such
date using March 31, 1997 prices) to a four-year enhancement program,
commencing in 1997, on an existing waterflood in the Westbrook Field in
Mitchell County, Texas. The proposed waterflood project is estimated to
cost an aggregate of $38.1 million. The Company has budgeted approximately
$11.0 million for development of the Westbrook Field in 1998.

Panoma Properties. The Company believes that developmental drilling
can enhance the value of its recently acquired Panoma Properties, which
produce from the Brown Dolomite and Granite Wash formations in the Texas
Panhandle and western Oklahoma. The easternmost fields are developed on 160
acre spacing because the original spacing of 640 acres proved inadequate to
drain reserves efficiently. In-fill development is underway in the
westernmost field with 31 wells of a 70 well program having been completed
during the first nine months of 1997. Upon completion of the 70 well
program, the westernmost field will be developed with 320 acre spacing. The
Company has budgeted approximately $4.0 million for development of the
Panoma Properties through 1998.

Waterfloods. The Company believes it can enhance the value of selected
west Texas fields through in-fill drilling and enhanced recovery projects,
including several waterflood projects. While waterfloods typically take
considerable time to respond to fluid injection, the west Texas properties
have in-fill drilling potential that management believes could result in a
somewhat faster increase in production and cash flow. The Company has
budgeted approximately $7.3 million in 1998 for five west Texas waterflood
projects.

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<PAGE> 33

Exploratory Drilling

The Company attempts to lessen the risks inherent in exploratory drilling
by (i) concentrating in specific areas in the United States where the Company's
technical staff has considerable experience and which are in known producing
trends where the potential for significant reserves exists; (ii) diversifying
through investment in multiple prospects; (iii) utilizing 3-D seismic and other
advanced technologies; and (iv) promoting out interests to industry partners.

The Company plans to spend approximately $3.0 million of its $20.0 million
1997 capital budget on exploratory drilling. The Company has a $6.0 million
exploration budget for 1998, including geological and geophysical expenses. Two
exploratory wells have been drilled in 1997 to date. One of these is located on
a 7,500 acre lease block in Roger Mills County, Oklahoma and was completed as a
gas well flowing approximately 500 Mcfe per day. Drilling of a confirmation well
is scheduled to commence in November 1997 at a location approximately two miles
west of the initial discovery. A second exploratory well located on a 3,000 acre
block in Fayette County, Texas has encountered oil shows and is awaiting a
completion rig to test one of the objective horizons. The Company owns 25% and
20% working interests, respectively, in these two prospects. The Company expects
to commence additional exploratory wells before year-end 1997 on prospects in
Oklahoma and Texas. An exploratory well will commence before year-end 1997 on
the Mossy Grove prospect in Walker County, Texas. The Company owns a 25% working
interest in the proposed test well which is located on a 30,000 acre lease
block. The primary objective is the Glen Rose formation at approximately 11,800
feet. Magnum Hunter also owns a 50% working interest in 2,500 acres on four new
prospects in Ellis County, Oklahoma. The Company expects to commence the first
exploratory well in late 1997, with the Atoka formation as the primary
objective. In Victoria County, Texas the Company has purchased 1,000 acres
overlaying a shallow Frio structure. Magnum Hunter owns a 100% interest in this
prospect and plans to commence an exploratory test well in late 1997 or early
1998. The Company is actively generating and evaluating prospects for the
application of future 3-D seismic and advanced drilling technologies.

GATHERING AND PROCESSING OF GAS

Hunter Gas Gathering, Inc., a wholly owned subsidiary of the Company, owns
three gas gathering systems located in Oklahoma, Texas and Louisiana, none of
which are subject to regulation by the Federal Energy Regulatory Commission
("FERC"), and a 50% ownership interest in the McLean Gas Plant in the Texas
Panhandle. Two of the gas gathering systems, Panoma and North Appleby, account
for more than 90% of the throughput from the Company's three systems. Gruy
operates all three gas gathering systems.

Generally, the gathering systems transport the gas from wells to a common
point where it is dehydrated prior to redelivery to downstream pipelines. In
managing its gas gathering systems, the Company has emphasized operating
efficiency and overhead management and introduced a program which ties
throughput costs to volume transported rather than to compression capacity. The
Company believes that its focus on volume-based pricing reduces the potential
financial impact of a decline in actual throughput.

The Panoma system, the largest of the Company's three gas gathering
systems, consists of approximately 427 miles of pipeline. The main trunklines
run east to west for approximately 66 miles with the east end starting in
Beckham County, Oklahoma and the west end starting in Gray County, Texas. Gas
throughput for the Panoma gas gathering system is approximately 16.3 MMcf per
day. The Panoma gas gathering system currently delivers gas to El Paso Natural
Gas Company for transport to markets in western Oklahoma and the West Coast,
although the Company is actively seeking additional markets for such gas. The
Company, which operates approximately 489 of the approximately 540 wells
connected to the Panoma system, is also actively seeking to add new wells to
such system through acquisition, development or arrangements with third party
producers.

The Company's North Appleby gas gathering system is located primarily in
Nacogdoches County in east Texas. Approximately 39 wells are connected to the
system, which delivers approximately 3.2 MMcf per day for third parties to
Natural Gas Pipeline Co. for transportation to other markets.

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<PAGE> 34

Effective January 1, 1997, the Company purchased for $2.5 million a 50%
ownership interest in the McLean Gas Plant, the gas processing facility
connected to the Company's Panoma gas gathering system. The purchase also
included a 23-mile products pipeline between the McLean Gas Plant and the Koch
Pipeline at Lefors, Texas and all gas and product purchase and sales agreements
related to the plant. The McLean Gas Plant is a modern cryogenic gas processing
plant with a capacity of 23.0 MMcf per day with a current throughput of 16.5
MMcf per day. The Company acquired its 50% ownership interest in the plant from
Carrera Gas Company, L.L.C. ("Carrera") of Tulsa, Oklahoma, which owns the
remaining 50% of the plant and operates the facility. Under terms of the
Company's operating agreement with Carrera, the Company receives 100% of the net
profits from the McLean Gas Plant until it recoups the $2.5 million purchase
price, at which point net profits will be divided equally between the Company
and Carrera. As of September 30, 1997 the Company had recouped approximately 35%
of its $2.5 million investment.

MARKETING OF PRODUCTION

The Company markets all of its gas production as well as gas it purchases
from third parties to gas marketing firms or end users either on the spot market
on a month-to-month basis at prevailing spot market prices or at negotiated
prices under long-term contracts. Marketing gas for its own account exposes the
Company to the attendant commodities risk. In 1996 the Company sold
approximately 91% of its gas to Crosstex, a gas marketing firm in Dallas, Texas
formed in January 1997 when Comstock Resources, Inc. sold its gas gathering,
processing and marketing operations. The Company does not anticipate that
Crosstex will purchase more than 10% of the Company's total oil and gas
production during 1997. The Company typically obtains letters of credit
guaranteeing the payment of the purchase price for its gas.

The Company normally sells its own oil under month-to-month contracts with
a variety of purchasers. Oil is usually sold for the Company's own account
through Enmark Services, a marketing agent in Dallas, Texas. While the Company
has historically been able to sell oil above posted prices, it is also exposed
to the commodities risk inherent in short-term contracts. For a discussion of
the Company's hedging activities, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources -- Hedging Activity" and Note 14 to the Company's Consolidated
Financial Statements.

The market for oil and gas produced by the Company depends on factors
beyond its control, including the extent of domestic production and imports of
oil and gas, the proximity and capacity of gas pipelines and other
transportation facilities, weather, demand for oil and gas, the marketing of
competitive fuels and the effects of state and federal regulation. The oil and
gas industry also competes with other industries in supplying the energy and
fuel requirements of industrial, commercial and individual consumers.

In October 1997 Hunter Gas Gathering, Inc. entered into a nonbinding letter
of intent to acquire a 30% interest in a privately held gas marketing firm,
Natural Gas Transmission Services, Inc., for an estimated consideration of
approximately $4.0 to $5.0 million payable in the Company's Common Stock. This
gas marketing firm had net income of $2.3 million on total revenues of $154.9
million and $2.2 million on total revenues of $131.4 million in 1996 and the
first nine months of 1997, respectively. As part of the proposed acquisition,
the Company plans to dedicate 100% of its gas production to such firm for
marketing. The proposed transaction (including the purchase price) is subject to
due diligence and negotiation of a definitive agreement (both of which have only
recently commenced) and other contingencies, and there is no assurance this
transaction will be consummated.

PETROLEUM MANAGEMENT AND CONSULTING SERVICES; OTHER ACTIVITIES

Gruy

The Company acquired Gruy in the Magnum Hunter Combination in December
1995. Gruy, which conducts operations for both the Company and third parties,
has a 40-year history of managing properties for third parties, which include
banks, financial institutions, bankruptcy trustees, estates, individual
investors, trusts and independent oil and gas companies. Gruy provides drilling,
completion and other well-site services; advice regarding environmental and
other regulatory compliance; receipt and disbursement functions and other
managerial services; petroleum engineering services; and consultation as an
expert witness. Gruy

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<PAGE> 35

manages, operates and provides consulting services on oil and gas properties
located in Texas, Oklahoma, Mississippi, Louisiana, New Mexico and Kansas. Gruy
is an important component of the Company's acquisition program. As the operator
of wells for third parties and as a provider of consulting services for the
energy industry, Gruy is often able to identify attractive acquisition
opportunities.

Hunter Butcher

The Company provides consulting services to Latin American energy companies
through Hunter Butcher. Hunter Butcher has primarily focused on assisting
energy-related Mexican companies in obtaining financing for their purchases in
the United States of products for import into Mexico. This is accomplished
through a commercial bank credit facility established to facilitate short and
medium term credit for Hunter Butcher to purchase these products and resell them
to its clients at a slight premium. The credit risk to Hunter Butcher on such
resales is lessened by partial guarantees of approximately 85% to 90% of such
borrowings by the Export Import Bank of the United States (the "ExIm Bank"), by
credit insurance and through deposits by Hunter Butcher's clients to secure the
unguaranteed portion of the indebtedness and certain interest. Hunter Butcher
could, however, incur a loss under such arrangement in repaying indebtedness
under the credit facility since the applicable ExIm Bank guaranty and deposit
would not be adequate to pay interest under the credit facility at the default
rate or cover other possible losses. In addition, the Company itself may from
time to time guarantee the indebtedness incurred under the credit facility by
Hunter Butcher for its clients, but the Credit Facility limits the Company to
guaranteeing not more than $3.0 million of such indebtedness at any time.

OIL AND GAS RESERVES

General

All information set forth in this Prospectus regarding estimated proved
reserves, related estimated future net cash flows and SEC PV-10 of the Company's
oil and gas interests is taken from reports prepared (i) by Gaffney, Cline and
Glenn Harrison Petroleum Consultants, Inc. ("Glenn Harrison"), both independent
petroleum engineers in Dallas, Texas with respect to the Company's interests at
December 31, 1996 (using oil and gas prices at both December 31, 1996 and March
31, 1997), (ii) by the engineers named in the footnotes to the tables below with
respect to the Company's interests at December 31, 1995 and (iii) by Ryder Scott
with respect to the Permian Basin Properties at December 31, 1996 (using oil and
gas prices at both December 31, 1996 and March 31, 1997) and with respect to all
the Company's properties at September 30, 1997. The estimates of these
independent petroleum engineers were based upon their review of production
histories and other geological, economic, ownership and engineering data
provided by the Company and, in the case of Ryder Scott's report at December 31,
1996, by Burlington and the Company.

In accordance with Commission guidelines (and except for the alternative
estimates of future net cash flows and SEC PV-10 as of December 31, 1996 using
March 31, 1997 prices), the estimates of future net cash flows from Proved
Reserves and their SEC PV-10 are made using oil and gas sales prices in effect
as of the dates of such estimates and are held constant throughout the life of
the properties. The Company's estimates of Proved Reserves, future net cash
flows and SEC PV-10 were estimated using the following weighted average prices
(other than prices at March 31, 1997, which are market prices as adjusted for
Btu content), before deduction of production taxes:

<TABLE>
<CAPTION>
PRICES USED IN RESERVE REPORTS AT DECEMBER 31,
----------------------------------------------------
PRO FORMA 1996(1)
----------------------------------
DECEMBER 31, 1996 MARCH 31, 1997
1995 1996 PRICES(2) PRICES(3)
------ ------ ----------------- --------------
<S> <C> <C> <C> <C>
Gas (per Mcf)........................ $ 1.46 $ 4.03 $ 4.05 $ 2.30
Oil (per Bbl)........................ $15.60 $24.37 $24.18 $20.41
</TABLE>

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

(1) Gives effect to the Permian Basin Acquisition as if it had occurred on
December 31, 1996.

(2) Proved Reserves attributable to the Permian Basin Properties at December 31,
1996 were estimated based upon weighted average prices (before deduction of
production taxes) of $4.12 per Mcf of gas and $23.61 per Bbl of oil.

35
<PAGE> 36

(3) Proved Reserves attributable to the Permian Basin Properties at December 31,
1996 using prices at March 31, 1997 were based upon market prices (before
deduction of production taxes) of $2.30 per Mcf of gas and $20.41 per Bbl of
oil.

All reserves are evaluated at contract temperature and pressure which can
affect the measurement of gas reserves. Operating costs, development costs and
certain production-related and ad valorem taxes were deducted in arriving at the
estimated future net cash flows. No provision was made for income taxes. The
following estimates set forth reserves considered to be economically recoverable
under normal operating methods and existing conditions at the prices and
operating costs prevailing at the dates indicated above. The estimates of the
SEC PV-10 from future net cash flows differ from the standardized measure of
discounted future net cash flows set forth in the notes to the Consolidated
Financial Statements of the Company, which is calculated after provision for
future income taxes. There can be no assurance that these estimates are accurate
predictions of future net cash flows from oil and gas reserves or their present
value.

Proved Reserves are estimates of oil and gas to be recovered in the future.
Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserve estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered. See "Risk
Factors -- Uncertainty of Estimates of Reserves and Future Net Cash Flows."

Except for the effect of changes in oil and gas prices, no major discovery
or other favorable or adverse event is believed to have caused a significant
change in these estimates of the Company's proved reserves since December 31,
1996.

No estimates of Proved Reserves of oil and gas have been filed by the
Company with, or included in any report to, any United States authority or
agency (other than the Commission) since January 1, 1996.

36
<PAGE> 37

Company Reserves

The following tables set forth the estimated Proved Reserves of oil and gas
of the Company and the SEC PV-10 thereof on (i) an actual basis at December 31,
1995 and 1996 and (ii) a pro forma basis giving effect to the Permian Basin
Acquisition as if it had occurred on December 31, 1996 (using oil and gas prices
at both December 31, 1996 and March 31, 1997).

ESTIMATED PROVED OIL AND GAS RESERVES(1)

<TABLE>
<CAPTION>
AT DECEMBER 31,
--------------------------------------------------------
PRO FORMA 1996(4)
-----------------------------
DECEMBER 31, MARCH 31,
1995(2) 1996(3) 1996 PRICES 1997 PRICES(5)
---------- ----------- ------------ --------------
<S> <C> <C> <C> <C>
NET GAS RESERVES (MCF):
Proved Developed Producing Reserves...... 8,796,748 71,166,555 148,486,702 139,410,810
Proved Developed Non-Producing
Reserves............................... -- 108,586 161,546 160,960
Proved Undeveloped Reserves.............. 5,275,168 19,290,856 41,793,954 41,791,208
---------- ----------- ----------- -----------
Total Proved Gas Reserves...... 14,071,916 90,565,997 190,442,202 181,362,984
========== =========== =========== ===========
NET OIL RESERVES (BBL):
Proved Developed Producing Reserves...... 1,681,841 1,849,846 10,804,735 10,050,370
Proved Developed Non-Producing
Reserves............................... -- 112,338 125,979 119,641
Proved Undeveloped Reserves.............. 2,085,898 3,376,071 9,698,562 9,681,158
---------- ----------- ----------- -----------
Total Proved Oil Reserves...... 3,767,739 5,338,255 20,629,276 19,851,169
========== =========== =========== ===========
Total Proved Reserves (Mcfe)... 36,678,350 122,595,527 314,217,858 300,469,998
========== =========== =========== ===========
</TABLE>

ESTIMATED SEC PV-10 OF PROVED RESERVES(1)

<TABLE>
<CAPTION>
AT DECEMBER 31,
-------------------------------------------------------------
PRO FORMA 1996(4)
------------------------------
DECEMBER 31, MARCH 31,
1995(2) 1996(3) 1996 PRICES 1997 PRICES(5)
----------- ------------ ------------ --------------
<S> <C> <C> <C> <C>
ESTIMATED SEC PV-10(6):
Proved Developed Producing
Reserves......................... $19,036,205 $115,858,134 $295,509,505 $161,683,897
Proved Developed Non-Producing
Reserves......................... -- 664,308 987,032 682,003
Proved Undeveloped
Reserves......................... 18,173,125 48,244,017 111,552,418 62,465,119
----------- ------------ ------------ ------------
Total SEC PV-10 of Proved
Reserves......................... $37,209,330 $164,766,459 $408,048,955 $224,831,019
=========== ============ ============ ============
</TABLE>

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

(1) Based upon (i) reserve report at December 31, 1995 prepared by James J.
Weisman, Jr.; (ii) reserve reports at December 31, 1996 prepared by Gaffney,
Cline and Glenn Harrison; and (iii) reserve report relating to the Permian
Basin Properties at December 31, 1996 prepared by Ryder Scott.

(2) Includes reserves acquired in the Magnum Hunter Combination. See "-- Recent
Acquisitions."

(3) Includes reserves acquired in the Panoma Acquisition. See "-- Recent
Acquisitions."

(4) Gives effect to the Permian Basin Acquisition as if it had occurred on
December 31, 1996.

(5) Proved Reserves and SEC PV-10 have been estimated as of December 31, 1996
using March 31, 1997 market prices of $20.41 per Bbl of oil and $2.30 per
Mcf of gas. Such Proved Reserves and SEC PV-10 have not been adjusted for
production for the three-month period ended March 31, 1997.

(6) SEC PV-10 differs from the standardized measure of discounted future net
cash flows set forth in the notes to the Consolidated Financial Statements
of the Company, which is calculated after provision for future income taxes.

37
<PAGE> 38

Significant Properties

On December 31, 1996, after giving pro forma effect to the Permian Basin
Acquisition, 86% of the Company's Proved Reserves on a Bcfe basis were located
in the Permian Basin Properties and the Panoma Properties. On such date the
Company's properties included, on a pro forma basis, working interests in 2,581
gross (1,436 net) productive oil and gas wells. The Company also held interests
in 10,992 gross (5,003 net) undeveloped acres on a pro forma basis at December
31, 1996.

The following table sets forth summary information with respect to the
Company's estimated Proved Reserves of oil and gas on a pro forma basis at
December 31, 1996.

<TABLE>
<CAPTION>
SEC PV-10(1)
---------------------- NATURAL GAS
AMOUNT % OF OIL GAS EQUIVALENT
(IN THOUSANDS) TOTAL (BBL) (MCF) (MCFE)
-------------- ----- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Permian Basin Properties(2)(3).... $243,282 59.6% 15,291,021 99,876,205 191,622,331
Panoma Properties(4).............. 111,030 27.2% 28,531 77,114,929 77,286,115
Other(5).......................... 53,736 13.2% 5,309,724 13,451,068 45,309,412
-------- ----- ---------- ----------- -----------
Total(2)................ $408,048 100.0% 20,629,276 190,442,202 314,217,858
======== ===== ========== =========== ===========
</TABLE>

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

(1) SEC PV-10 differs from the standardized measure of discounted future net
cash flows set forth in the notes to the Consolidated Financial Statements
of the Company, which is calculated after provision for future income taxes.

(2) Gives effect to the Permian Basin Acquisition as if it had occurred on
December 31, 1996.

(3) Based on a reserve report at December 31, 1996 prepared by Ryder Scott.

(4) Based on a reserve report at December 31, 1996 prepared by Gaffney, Cline.

(5) Based on reserve reports at December 31, 1996 prepared by Gaffney, Cline and
Glenn Harrison.

Permian Basin Reserves

The following tables set forth as of December 31, 1996 the estimated Proved
Reserves and the SEC PV-10 thereof for the Permian Basin Properties.

ESTIMATED PROVED OIL AND GAS RESERVES OF THE PERMIAN BASIN PROPERTIES(1)

<TABLE>
<CAPTION>
AT DECEMBER 31, 1996
-----------------------------------
DECEMBER 31, 1996 MARCH 31, 1997
PRICES PRICES(2)
----------------- --------------
<S> <C> <C>
NET GAS RESERVES (MCF):
Proved Developed Producing Reserves....................... 77,320,147 71,319,816
Proved Developed Non-Producing Reserves................... 52,960 52,960
Proved Undeveloped Reserves............................... 22,503,098 22,503,098
----------- -----------
Total Proved Reserves of gas...................... 99,876,205 93,875,874
----------- -----------
NET OIL RESERVES (BBL):
Proved Developed Producing Reserves....................... 8,954,889 8,296,370
Proved Developed Non-Producing Reserves................... 13,641 13,641
Proved Undeveloped Reserves............................... 6,322,491 6,304,139
----------- -----------
Total Proved Reserves of oil...................... 15,291,021 14,614,150
----------- -----------
Total Proved Reserves (Mcfe)...................... 191,622,331 181,560,774
=========== ===========
</TABLE>

38
<PAGE> 39

ESTIMATED SEC PV-10 OF PROVED RESERVES OF THE PERMIAN BASIN PROPERTIES(1)

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

(1) Based upon reserve reports at December 31, 1996 prepared by Ryder Scott.

(2) Proved Reserves and SEC PV-10 have been estimated as of December 31, 1996
using March 31, 1997 market prices of $20.41 per Bbl of oil and $2.30 per
Mcf of gas at the Permian Basin Properties. Such Proved Reserves and SEC
PV-10 have not been adjusted for production for the three-month period ended
March 31, 1997.

(3) SEC PV-10 differs from the standardized measure of discounted future net
cash flows set forth in the notes to the Consolidated Financial Statements
of the Company, which is calculated after provision for future income taxes.

OIL AND GAS PRODUCTION, PRICES AND COSTS

The following table shows the approximate net production attributable to
the Company's oil and gas interests, the average sales price and the average
production expense attributable to the Company's oil and gas production for the
periods indicated. Except for pro forma data, production and sales information
relating to properties acquired or disposed of is reflected in this table only
since or up to the closing date of their respective acquisition or sale and may
affect the comparability of the data between the periods presented.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS
---------------------------------- ENDED
PRO SEPTEMBER 30,
FORMA ---------------
1994 1995 1996 1996(1) 1996 1997
------ ------ ------ ------- ------ ------
<S> <C> <C> <C> <C> <C> <C>
Oil and gas production:
Oil (MBbl)................................ 42 30 191 1,105 140 490
Gas (MMcf)................................ 88 102 2,675 13,811 1,632 6,451
Natural Gas Equivalents (MMcfe)........... 340 282 3,821 20,441 2,472 9,391
Average sales price(2):
Oil (per Bbl)............................. $14.20 $15.60 $20.46 $20.15 $19.92 $17.79
Gas (per Mcf)............................. 1.53 1.46 2.37 2.22 2.23 2.18
Natural Gas Equivalents (per Mcfe)........ 2.15 2.19 2.68 2.59 2.57 2.43
Oil and gas production expense (per
Mcfe)(3).................................. $ 0.94 $ 0.95 $ 1.15 $ 0.84 $ 1.14 $ 0.91
</TABLE>

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

(1) Gives effect to the Permian Basin Acquisition as if it had occurred on
January 1, 1996.

(2) Before deduction of production taxes and net of hedging results for the two
years ended December 31, 1996.

(3) Includes lease operating expenses and production and ad valorem taxes, if
applicable. For the years ended December 31, 1996 on a historical basis and
December 31, 1996 on a pro forma basis and the nine months ended September
30, 1997, includes internal transfer price expenses for gas gathering and
overhead costs of $0.23 per Mcfe, $0.04 per Mcfe and $0.16 per Mcfe,
respectively. Internal transfer price expenses are not available for the
nine months ended September 30, 1996.

39
<PAGE> 40

DRILLING ACTIVITY

The following table sets forth the results of the Company's drilling
activities during the three fiscal years ended December 31, 1996 and the period
from January 1, 1997 through September 30, 1997. From September 30, 1997 through
October 28, 1997, the Company has drilled one dry hole and has completed 13
producing wells. At October 28, 1997 the Company was in the process of drilling
seven development wells (4.7 net wells).

<TABLE>
<CAPTION>
GROSS WELLS(1) NET WELLS(2)
----------------------------- -----------------------------
YEAR TYPE OF WELL PRODUCING(3) DRY(4) TOTAL PRODUCING(3) DRY(4) TOTAL
- ------- ------------ ------------ ------ ----- ------------ ------ -----
<S> <C> <C> <C> <C> <C> <C> <C>
1994 Exploratory................. -- -- -- -- -- --
Development................. 2 1 3 0.50 0.25 0.75
1995 Exploratory................. 2 -- 2 0.55 -- 0.55
Development................. -- -- -- -- -- --
1996 Exploratory................. 4 4 8 2.63 2.60 5.23
Development................. 3 -- 3 0.66 -- 0.66
1997(5) Exploratory................. 2 -- 2 0.45 -- 0.45
Development................. 46 -- 46 40.63 -- 40.63
</TABLE>

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

(1) The number of gross wells is the total number of wells in which a working
interest is owned. Fluid injection wells for waterflood and other enhanced
recovery projects are not included as gross wells.

(2) The number of net wells is the sum of fractional working interests owned in
gross wells expressed as whole numbers and fractions thereof.

(3) A producing well is an exploratory or development well found to be capable
of producing either oil or gas in sufficient quantities to justify
completion as an oil or gas well.

(4) A dry well is an exploratory or development well that is not a producing
well.

(5) Based on wells completed through September 30, 1997.

OIL AND GAS WELLS

The following table sets forth the number of productive oil and gas wells
in which the Company had a working interest at December 31, 1996.

<TABLE>
<CAPTION>
PRODUCTIVE WELLS
-------------------------------------------
GROSS(1) NET(2)
----------------- -----------------------
LOCATION OIL GAS TOTAL OIL GAS TOTAL
-------- --- --- ----- ----- ------ ------
<S> <C> <C> <C> <C> <C> <C>
Texas............................................. 113 447 560 53.35 381.72 435.07
Oklahoma.......................................... 26 117 143 21.85 103.09 124.94
Mississippi....................................... 4 -- 4 2.98 -- 2.98
New Mexico........................................ 3 3 6 2.48 0.64 3.12
California........................................ 14 -- 14 1.05 -- 1.05
Kansas............................................ 2 -- 2 1.90 -- 1.90
--- --- --- ----- ------ ------
Total................................... 162 567 729 83.61 485.45 569.06
=== === === ===== ====== ======
</TABLE>

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

(1) The number of gross wells is the total number of wells in which a working
interest is owned. Well counts include wells with multiple completions, but
do not include injector wells.

(2) The number of net wells is the sum of fractional working interests owned in
gross wells expressed as whole numbers and fractions thereof.

On a pro forma basis at December 31, 1996, the Company had a working
interest in 2,581 gross (1,436 net) productive oil and gas wells.

40
<PAGE> 41

OIL AND GAS ACREAGE

The following table summarizes the Company's developed and undeveloped
leasehold acreage at December 31, 1996.

<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED
------------------ -----------------
LOCATION GROSS(1) NET(2) GROSS(1) NET(2)
-------- -------- ------- -------- ------
<S> <C> <C> <C> <C>
Texas.................................................... 167,216 151,293 10,432 4,711
Oklahoma................................................. 45,610 42,982 -- --
Mississippi.............................................. 528 452 -- --
New Mexico............................................... 840 702 -- --
California............................................... 509 38 -- --
Kansas................................................... 80 69 -- --
------- ------- ------ -----
Total.......................................... 214,783 195,536 10,432 4,711
======= ======= ====== =====
</TABLE>

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

(1) The number of gross acres is the total number of acres in which a working
interest is owned.

(2) The number of net acres is the sum of fractional working interests owned in
gross acres expressed as whole numbers and fractions thereof.

On a pro forma basis at December 31, 1996, the Company held interests in
328,033 gross (277,419 net) developed acres and 10,992 gross (5,003 net)
undeveloped acres.

Substantially all of the Company's interests are leasehold working
interests or overriding royalty interests (as opposed to mineral or fee
interests) under standard onshore oil and gas leases. As is customary in the
industry, the Company generally acquires oil and gas acreage without any
warranty of title except as to claims made by, through or under the transferor.
Although the Company has title examined by a landman or title attorney prior to
acquisition of developed acreage in those cases in which the economic
significance of the acreage justifies the cost, there can be no assurance that
losses will not result from title defects or from defects in the assignment of
leasehold rights. In many instances, title opinions may not be obtained if in
the Company's judgment it would be uneconomical or impractical to do so.

COMPETITION

The oil and gas industry is highly competitive. Competitors of the Company
include major oil companies, other independent oil and gas concerns, and
individual producers and operators, many of which have substantially greater
financial resources and larger staffs and facilities than those of the Company.
In addition, the Company frequently encounters competition in the acquisition of
oil and gas properties and gas gathering systems, and in its management and
consulting business. The principal means of such competition are the amount and
terms of the consideration offered. The principal means of such competition with
respect to the sale of oil and gas production are product availability and
price. The price at which the Company's gas may be sold will continue to be
affected by a number of factors, including the price of alternate fuels such as
oil and coal and competition among various gas producers and marketers. See
"Risk Factors -- Competition."

REGULATION

General Federal and State Regulation

The Company's oil and gas exploration, production and related operations
are subject to extensive rules and regulations promulgated by federal and state
agencies. Failure to comply with such rules and regulations can result in
substantial penalties. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business and affects its profitability.
Because such rules and regulations are frequently amended or reinterpreted, the
Company is unable to predict the future cost or impact of complying with such
laws.

The State of Texas and many other states require permits for drilling
operations, drilling bonds and reports concerning operations and impose other
requirements relating to the exploration and production of oil and gas. Such
states also have statutes or regulations addressing conservation matters,
including provisions for

41
<PAGE> 42

the unitization or pooling of oil and gas properties, the establishment of
maximum rates of production from wells, and the regulation of spacing, plugging
and abandonment of such wells. Many states restrict production to the market
demand for oil and gas. Some states have enacted statutes prescribing ceiling
prices for gas sold within their states.

FERC regulates interstate gas transportation rates and service conditions,
which affect the marketing of gas produced by the Company, as well as the
revenues received by the Company for sales of such production. Since the
mid-1980s, FERC has issued a series of orders, culminating in Order Nos. 636,
636-A and 636-B ("Order 636"), that have significantly altered the marketing and
transportation of gas. Order 636 mandates a fundamental restructuring of
interstate pipeline sales and transportation service, including the unbundling
by interstate pipelines of the sale, transportation, storage and other
components of the city-gate sales services such pipelines previously performed.
One of FERC's purposes in issuing the orders is to increase competition within
all phases of the gas industry. Order 636 and subsequent FERC orders on
rehearing have been appealed and are pending judicial review. Because these
orders may be modified as a result of the appeals, it is difficult to predict
the ultimate impact of the orders on the Company and its gas marketing efforts.
Generally, Order 636 has eliminated or substantially reduced the interstate
pipelines' traditional role as wholesalers of gas, and has substantially
increased competition and volatility in gas markets.

The price the Company receives from the sale of oil and natural gas liquids
is affected by the cost of transporting products to market. Effective January 1,
1995, FERC implemented regulations establishing an indexing system for
transportation rates for oil pipelines, which, generally, would index such rates
to inflation, subject to certain conditions and limitations. The Company is not
able to predict with certainty the effects, if any, of these regulations on its
operations. However, the regulations may increase transportation costs or reduce
wellhead prices for oil and natural gas liquids. Finally, 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 natural production
capacity in order to conserve supplies of oil and gas. See "Risk Factors -- Laws
and Regulations."

Environmental Regulation

The Company's exploration, development, and production of oil and gas,
including its operation of saltwater injection and disposal wells, are subject
to various federal, state and local environmental laws and regulations. Such
laws and regulations can increase the costs of planning, designing, installing
and operating oil and gas wells. The Company's domestic activities are subject
to a variety of environmental laws and regulations, including but not limited
to, the Oil Pollution Act of 1990 ("OPA"), the Clean Water Act ("CWA"), the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
the Resource Conservation and Recovery Act ("RCRA"), the Clean Air Act ("CAA"),
and the Safe Drinking Water Act ("SDWA"), as well as state regulations
promulgated under comparable state statutes. The Company also is subject to
regulations governing the handling, transportation, storage, and disposal of
naturally occurring radioactive materials that are found in its oil and gas
operations. Civil and criminal fines and penalties may be imposed for
non-compliance with these environmental laws and regulations. Additionally,
these laws and regulations require the acquisition of permits or other
governmental authorizations before undertaking certain activities, limit or
prohibit other activities because of protected areas or species, and impose
substantial liabilities for cleanup of pollution.

Under the OPA, a release of oil into water or other areas designated by the
statute could result in the Company being held responsible for the costs of
remediating such a release, certain OPA specified damages, and natural resource
damages. The extent of that liability could be extensive, as set forth in the
statute, depending on the nature of the release. A release of oil in harmful
quantities or other materials into water or other specified areas could also
result in the Company being held responsible under the CWA for the costs of
remediation, and civil and criminal fines and penalties.

CERCLA and comparable state statutes, also known as "Superfund" laws, can
impose joint and several and retroactive liability, without regard to fault or
the legality of the original conduct, on certain classes of persons for the
release of a "hazardous substance" into the environment. In practice, cleanup
costs are usually allocated among various responsible parties. Potentially
liable parties include site owners or operators, past

42
<PAGE> 43

owners or operators under certain conditions, and entities that arrange for the
disposal or treatment of, or transport hazardous substances found at the site.
Although CERCLA, as amended, currently exempts petroleum, including but not
limited to, crude oil, gas and natural gas liquids from the definition of
hazardous substance, the Company's operations may involve the use or handling of
other materials that may be classified as hazardous substances under CERCLA.
Furthermore, there can be no assurance that the exemption will be preserved in
future amendments of the act, if any.

RCRA and comparable state and local requirements impose standards for the
management, including treatment, storage, and disposal of both hazardous and
nonhazardous solid wastes. The Company generates hazardous and nonhazardous
solid waste in connection with its routine operations. From time to time,
proposals have been made that would reclassify certain oil and gas wastes,
including wastes generated during pipeline, drilling, and production operations,
as "hazardous wastes" under RCRA which would make such solid wastes subject to
much more stringent handling, transportation, storage, disposal, and clean-up
requirements. This development could have a significant impact on the Company's
operating costs. While state laws vary on this issue, state initiatives to
further regulate oil and gas wastes could have a similar impact.

Because oil and gas exploration and production, and possibly other
activities, have been conducted at some of the Company's properties by previous
owners and operators, materials from these operations remain on some of the
properties and in some instances require remediation. In addition, the Company
has agreed to indemnify sellers of producing properties from whom the Company
has acquired reserves against certain liabilities for environmental claims
associated with such properties. While the Company does not believe that costs
to be incurred by the Company for compliance and remediating previously or
currently owned or operated properties will be material, there can be no
guarantee that such costs will not result in material expenditures.

Additionally, in the course of the Company's routine oil and gas
operations, surface spills and leaks, including casing leaks, of oil or other
materials occur, and the Company incurs costs for waste handling and
environmental compliance. Moreover, the Company is able to control directly the
operations of only those wells for which it acts as the operator.
Notwithstanding the Company's lack of control over wells owned by the Company
but operated by others, the failure of the operator to comply with applicable
environmental regulations may, in certain circumstances, be attributable to the
Company. The Company currently expects to spend approximately $725,000 over the
next five years in connection with remediation and environmental compliance,
including $75,000 for the remainder of 1997, $200,000 in 1998 and $150,000 in
1999.

It is not anticipated that the Company will be required in the near future
to expend amounts that are material in relation to its total capital
expenditures program by reason of environmental laws and regulations, but
inasmuch as such laws and regulations are frequently changed, the Company is
unable to predict the ultimate cost of compliance. There can be no assurance
that more stringent laws and regulations protecting the environment will not be
adopted or that the Company will not otherwise incur material expenses in
connection with environmental laws and regulations in the future. See "Risk
Factors -- Laws and Regulations."

EMPLOYEES

At September 30, 1997, the Company had 57 full-time employees of which nine
were management, 21 were administrative and 27 were field employees. None of the
Company's employees are represented by a union. Management considers its
relations with employees to be good.

FACILITIES

The Company occupies approximately 11,590 square feet of office space at
600 East Las Colinas Boulevard, Suite 1200, Irving, Texas, under a lease that
expires in November 2001. The Company owns a field office and production yard in
Shamrock, Texas. The Company also has field production offices in Midland, Texas
and Hobbs, New Mexico.

LEGAL PROCEEDINGS

No legal proceedings are pending other than ordinary routine litigation
incidental to the Company's business, the outcome of which management believes
will not have a material adverse effect on the Company.

43
<PAGE> 44

MANAGEMENT

The following table sets forth the directors, executive officers and other
significant employees of the Company, their ages, and all offices and positions
with the Company. Each director is elected for a period of one year and
thereafter serves until his successor is duly elected by the stockholders of the
Company and qualifies.

<TABLE>
<CAPTION>
NAME AGE TITLE
---- --- -----
<S> <C> <C>
Gary C. Evans........ 40 Director, President and Chief Executive Officer of the
Company
Matthew C. Lutz...... 63 Chairman and Executive Vice President of Exploration and
Business Development of the Company
Chris Tong........... 41 Senior Vice President and Chief Financial Officer of the
Company
David S. Krueger..... 48 Vice President and Chief Accounting Officer of the Company
Morgan F. Johnston... 37 Vice President, General Counsel and Secretary of the Company
Richard R. Frazier... 50 President and Chief Operating Officer of Magnum Hunter
Production, Inc. and Chief Operating Officer of Gruy
R. Renn Rothrock, 55
Jr. ............... President of both Hunter Gas Gathering, Inc. and Gruy and
Executive Vice President of Magnum Hunter Production, Inc.
Michael McInerney.... 56 Vice President, Corporate Development & Investor Relations
Gerald W. Bolfing.... 69 Director of the Company
Oscar C. Lindemann... 75 Director of the Company
John H. Trescot, 72
Jr. ............... Director of the Company
James E. Upfield..... 77 Director of the Company
</TABLE>

Gary C. Evans has served as President, Chief Executive Officer and a
director of the Company since December 31, 1995 and Chairman and Chief Executive
Officer of all of the Hunter Subsidiaries since their formation or acquisition.
He served as Chief Financial Officer from January 1997 to August 1997. He acted
as Chairman, President and Chief Executive Officer of Hunter from September 1992
until October 1996. Previously, he was President and Chief Operating Officer of
Hunter from December 1990 to September 1992. From 1985 to 1990, Mr. Evans was
Chairman, President and Chief Executive Officer of Sunbelt Energy, Inc. and its
subsidiaries, which were merged with Hunter. From 1981 to 1985, Mr. Evans was
associated with the Mercantile Bank of Canada where he held various positions
including Vice President and Manager of the Energy Division of the Southwestern
United States. From 1978 to 1981, he served in various capacities with National
Bank of Commerce (now BancTexas, N.A.) including Credit Manager and Credit
Officer. Mr. Evans serves on the Board of Directors of Karts International
Incorporated, a Nasdaq-listed company, and Digital Communications Technology
Corporation, an American Stock Exchange listed company.

Matthew C. Lutz became Chairman as of March 31, 1997 after having served as
Vice Chairman of the Company since December 31, 1995. Mr. Lutz has also served
as Executive Vice President of Exploration and Business Development since
December 31, 1995. Mr. Lutz held similar positions with Hunter from September
1993 until October 1996. From 1984 through 1992, Mr. Lutz was Senior Vice
President of Exploration and on the Board of Directors of Enserch Exploration,
Inc. with responsibility for such company's worldwide oil and gas exploration
and development program. Prior to joining Enserch, Mr. Lutz spent 28 years with
Getty Oil Company. He advanced through several technical, supervisory and
managerial positions which gave him various responsibilities including
exploration, production, lease acquisition, administration and financial
planning.

Chris Tong became Senior Vice President and Chief Financial Officer as of
August 18, 1997. Previously, Mr. Tong was Senior Vice President of Finance of
Tejas Acadian Holding Company and its subsidiaries including Tejas Gas Corp.,
Acadian Gas Corporation and Transok, Inc., all of which are wholly-owned
subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions since
August 1996, and served in other treasury positions with Tejas beginning August
1989. He was also responsible for managing Tejas' property and liability
insurance. From 1980 to 1989, Mr. Tong served in various energy lending
capacities with Canadian Imperial Bank of Commerce, Post Oak Bank, and Bankers
Trust Company in Houston, Texas. Prior to his banking career, Mr. Tong also
served over a year with Superior Oil Company as a Reservoir Engineering

44
<PAGE> 45

Assistant. Mr. Tong is a Summa Cum Laude graduate of the University of
Southwestern Louisiana with a Bachelor of Arts degree in Economics and a minor
in Mathematics.

David S. Krueger has served as Chief Accounting Officer of the Company
since January 1997. Mr. Krueger acted as Vice President-Finance of Cimarron Gas
Holding Co., a gas processing and natural gas liquids marketing company in
Tulsa, Oklahoma, from April 1992 until January 1997. He served as Vice
President/Controller of American Central Gas Companies, Inc., a gas gathering,
processing and marketing company from May 1988 until April 1992. From 1974 to
1986, Mr. Krueger served in various managerial capacities for Southland Energy
Corporation. From 1971 to 1973, Mr. Krueger was a staff accountant with Arthur
Andersen LLP. Mr. Krueger, a certified public accountant, graduated from the
University of Arkansas with a B.S./B.A. degree in Business Administration and
earned his M.B.A. from the University of Tulsa.

Morgan F. Johnston has served as Vice President and General Counsel since
April 1, 1997 and has served as the Company's Secretary since May 1, 1996. Mr.
Johnston was in private practice as a sole practitioner from May 1, 1996 to
April 1, 1997, specializing in corporate and securities law. From February 1994
to May 1996, Mr. Johnston served as general counsel for Millennia, Inc.
(formerly known as SOI Industries, Inc.) and Digital Communications Technology
Corporation, two American Stock Exchange listed companies. He also served as
general counsel to Halter Capital Corporation, a private consulting firm from
August 1991 to May 1996. For the two years prior to August 1, 1991 he was
securities counsel for Motel 6 L.P., a New York Stock Exchange listed company.
Mr. Johnston graduated cum laude from Texas Tech Law School in May 1986 and is
licensed to practice law in the State of Texas.

Richard R. Frazier has been President of Magnum Hunter Production, Inc. and
Chief Operating Officer of Magnum Hunter Production, Inc. and Gruy since January
1994. From 1977 to 1993, Mr. Frazier was employed by Edisto Resources
Corporation in Dallas, serving as Executive Vice President Exploration and
Production from 1983 to 1993, where he had overall responsibility for its
property acquisition, exploration, drilling, production, gas marketing and
engineering functions. From 1972 to 1976, Mr. Frazier served as District
Production Superintendent and Petroleum Engineer with HNG Oil Company (now Enron
Oil & Gas Company) in Midland, Texas. Mr. Frazier's initial employment, from
1968 to 1971, was with Amerada Hess Corporation as a petroleum engineer involved
in numerous projects in Oklahoma and Texas. Mr. Frazier graduated in 1970 from
the University of Tulsa with a Bachelor of Science Degree in Petroleum
Engineering. He is a registered Professional Engineer in Texas and a member of
the Society of Petroleum Engineers and many other professional organizations.

R. Renn Rothrock, Jr. has been President of both Hunter Gas Gathering, Inc.
and Gruy and Executive Vice President of Magnum Hunter Production, Inc. since
January 1994. He served as Executive Vice President and Chief Operating Officer
of Gruy from May 1988 until January 1994. Mr. Rothrock was Executive Vice
President and General Manager of Gruy Engineering Corporation from 1986 until
May 1988. Over his 32-year career, Mr. Rothrock has also served as a reservoir
engineer and operations research engineer at Skelly Oil Company and as an area
engineer at Amerada Petroleum Corporation; the Engineering Editor of Petroleum
Engineer International Magazine; Vice President and Energy Manager of the First
National Bank of Mobile, Alabama; Executive Vice President of Energy Assets
International Corporation, a public company that financed oil and gas ventures;
and the producer and operator of his own gas gathering and transportation
system. Mr. Rothrock earned a B.S. degree in Petroleum Engineering and an M.S.
degree in Engineering from the University of Oklahoma. He is a member of the
Society of Professional Engineers, the National Society of Professional
Engineers, the National Academy of Forensic Engineers and the Texas Society of
Professional Engineers. Mr. Rothrock is a registered Professional Engineer in
Texas and Oklahoma.

Michael McInerney has been Vice President, Corporate Development & Investor
Relations of the Company since October 1997. Prior to joining the Company, Mr.
McInerney owned Energy Advisors, Inc., an energy consulting firm, from June 1993
until October 1997. Mr. McInerney was employed from 1981 until June 1993 by
Triton Energy Corporation, an independent energy company, where his
responsibilities included investor relations, acquisitions and corporate
planning. Before joining Triton Energy Corporation, Mr. McInerney served nine
years in various financial management positions with American Natural Resources
Company, a gas transmission and distribution corporation. Mr. McInerney
graduated from the University of Michigan with a B.B.A.

45
<PAGE> 46

Gerald W. Bolfing has been a director of the Company since December 31,
1995. Mr. Bolfing was appointed a director of Hunter in August 1993. He is an
investor in the oil and gas business and a past officer of one of Hunter's
former subsidiaries. From 1962 to 1980, Mr. Bolfing was a partner in Bolfing
Food Stores in Waco, Texas. During this time, he also joined American Service
Company in Atlanta, Georgia from 1964 to 1965, and was active with Cable
Advertising Systems, Inc. of Kerrville, Texas from 1978 to 1981. He joined a
Hunter subsidiary in the well servicing business in 1981 where he remained
active until its divestiture in 1992. Mr. Bolfing is on the board of directors
of Capital Marketing Corporation of Hurst, Texas.

Oscar C. Lindemann has served as a director of the Company since December
31, 1995. Mr. Lindemann was previously a director of Hunter, having been
appointed in November 1995. Mr. Lindemann has over 40 years experience in the
financial industry. Mr. Lindemann began his banking career with the Texas Bank
and Trust in Dallas, Texas in 1951. He served the bank until 1977 in many
capacities, including Chief Executive Officer and Chairman of the Board. Since
leaving Texas Bank and Trust, he has served as Vice Chairman of both the United
National Bank and the National Bank of Commerce, also in Dallas. Mr. Lindemann
has also served as a consultant to the banking industry. He retired from
commercial banking in 1987. Mr. Lindemann is a former President of the Texas
Bankers Association, and a former state representative to the American Bankers
Association. He was a Founding Director and Board Member of VISA, and a member
of the Reserve City Bankers Association. He has served as an instructor at both
the Southwestern Graduate School of Banking at Southern Methodist University and
the School of Banking of the South at Louisiana State University. He has also
served as a faculty member for four years in the College of Business
Administration at the University of Texas in Austin teaching various banking
subjects.

John H. Trescot, Jr. has served as a director of the Company since June 5,
1997. For the last five years, Mr. Trescot has been a principal of AWA
Management Corporation, a professional consulting firm specializing in oil,
timber, pulp and paper, and financial management. Early in his career, Mr.
Trescot held various positions in woodlands, and pulp and paper, advancing to
the position of Senior Vice President, Southern Operations at Hudson Pulp &
Paper Corp. (now part of Georgia Pacific Corp.) Later Mr. Trescot became Vice
President of The Charter Company, a corporation with operations in oil,
communications and insurance. In 1979, Mr. Trescot became the Chief Executive
Officer of "Jari" Florestal e Agropecuaria, Ltda., a pulp, timber, rice and
kaolin operation in the Amazon Basin of Brazil owned by D.K. Ludwig. In 1981,
Mr. Trescot became the Chief Executive Officer of TOT Drilling Corp., a contract
drilling company drilling in west Texas and New Mexico.

James E. Upfield has served as a director of the Company since December 31,
1995. Mr. Upfield was appointed a director of Hunter in August 1992. Mr. Upfield
is Chairman of Temtex Industries, Inc. based in Dallas, Texas, a public company
that produces consumer hard goods and building materials. In 1969, Mr. Upfield
served on a select Presidential Committee serving postal operations of the
United States of America. He later accepted the responsibility for the Dallas
region, which encompassed Texas and Louisiana. From 1959 to 1967, Mr. Upfield
was President of Baifield Industries, Inc. ("Baifield") and its predecessor, a
company he founded in 1949 which merged with Baifield in 1963. Baifield was
engaged in prime government contracts for military systems and sub-systems in
the production of high-strength, light-weight metal products. In 1967, Baifield
was acquired by Automatic Sprinkler Corporation of America, where Mr. Upfield
remained until resigning in 1968 to pursue other business opportunities.

SIGNIFICANT OFFICERS OF SUBSIDIARIES

R. Douglas Cronk, age 50, has been Vice President of Operations for Magnum
Hunter Production, Inc. since May 1996, at which time the Company acquired from
Mr. Cronk Rampart Petroleum, Inc., based in Abilene, Texas. Rampart had been an
active operating and exploration company in the north central and west Texas
region since 1983. Prior to the formation of Rampart, Mr. Cronk was an
independent oil and gas consultant in Houston, Texas for approximately two
years. From 1974 to 1981, Mr. Cronk held various positions with subsidiaries of
Deutsch Corporation of Tulsa, Oklahoma, including Southland Drilling and
Production where he became Vice President of Drilling and Production. Mr. Cronk
is a Chemical Engineer graduate from the University of Tulsa.

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<PAGE> 47

Russell A. Talley, age 64, has been Executive Vice President and Drilling
Manager of Gruy Company since January 1991. From 1959 to 1970, Mr. Talley worked
for Diamond Shamrock Oil & Gas Company in Amarillo, Texas, where he had
substantial responsibilities in drilling, production and workover programs. From
1970 to 1985, Mr. Talley worked for Samedan Oil Corporation in Houston, Texas,
where he became the Manager of Offshore Drilling and Production. He managed all
domestic and Canadian drilling operations and supervised international
operations in Ecuador, the North Sea and Canada. From 1985 to 1987, Mr. Talley
was Vice President of Operations for Seagull Energy E & P, Inc. in Houston,
where he was responsible for all onshore and offshore drilling operations. In
1988 he established Texstar Energy Operators, Inc., which was acquired by Gruy
in 1991.

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<PAGE> 48

PRINCIPAL AND SELLING SHAREHOLDERS

SECURITY OWNERSHIP

The following table sets forth certain information as of September 30, 1997
and after giving effect to the Offering made hereby, regarding the share
ownership of the Company by (i) each person known to the Company to be the
beneficial owner of more than 5% of the outstanding shares of Common Stock of
the Company, (ii) each director, (iii) the Company's Chief Executive Officer and
the two other most highly compensated executive officers of the Company
(including the Selling Shareholder), and (iv) all directors and executive
officers of the Company, as a group. Additionally, this table reflects the
number of shares of Common Stock to be sold by the Selling Shareholder in this
Offering. None of the directors or executive officers named below owned, as of
September 30, 1997, any shares of the Company's Series A Preferred Stock or its
TCW Preferred Stock. The business address of each officer and director listed
below is: c/o Magnum Hunter Resources, Inc., 600 East Las Colinas Blvd., Suite
1200, Irving, Texas 75039.

<TABLE>
<CAPTION>
SHARES BENEFICIALLY SHARES BENEFICIALLY OWNED
OWNED PRIOR TO THE OFFERING AFTER THE OFFERING
---------------------------- SHARES --------------------------
NUMBER PERCENT OF BEING NUMBER PERCENT
NAME OF SHARES(1) CLASS(1) OFFERED OF SHARES(1) OF CLASS(1)
---- ------------- ------------ ------- ------------ -----------
<S> <C> <C> <C> <C> <C>
Directors and Executive Officers
Gary C. Evans(2)................... 1,618,046 11.7% 100,000 1,518,046 6.9%
Matthew C. Lutz.................... 271,338 2.0 -- 271,338 1.3%
Gerald W. Bolfing.................. 324,022 2.4 -- 324,022 1.5%
Oscar C. Lindemann................. 1,624 * -- 1,624 *
John H. Trescot, Jr. .............. 22,154 * -- 22,154 *
James E. Upfield................... 29,268 * -- 29,268 *
Richard R. Frazier................. 148,623 1.1 -- 148,623 *

All directors and executive
officers as a group (8
persons)........................ 2,415,675 15.8% 100,000 2,315,675 10.9%
Beneficial owners of 5% or more
(excluding persons named above)
TCW Group, Inc.
865 South Figueroa Street
Los Angeles, CA 90017.............. 1,702,127(3) 11.0% -- 1,702,127 8.1%
</TABLE>

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

* Less than 1%.

(1) The number of shares outstanding was calculated in accordance with Rule
13d-3(d) promulgated under the Exchange Act. For purposes of calculating the
beneficial ownership of each shareholder, it was assumed (in accordance with
the Commission's definition of "beneficial ownership") that such shareholder
had exercised all options, conversion rights or warrants by which such
shareholder had the right, within 60 days following September 30, 1997, to
acquire shares of Common Stock.

(2) Includes 17,024 shares held in the name of Jacquelyn Evelyn Enterprises
Inc., a corporation whose sole shareholder is Mr. Evans' wife. Mr. Evans
disclaims any ownership in such securities other than those in which he has
an economic interest. For certain additional information regarding Mr.
Evans's relationship with the Company, see "Management."

(3) Consists of shares attributable to shares of Common Stock issuable upon
conversion of 1,000,000 shares of the Company's TCW Preferred Stock.

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<PAGE> 49

DESCRIPTION OF CAPITAL STOCK

COMMON STOCK

The Company is presently authorized to issue 50,000,000 shares of Common
Stock, par value $.002, of which 13,733,342 shares were issued and outstanding
at September 30, 1997. The holders of Common Stock are entitled to equal
dividends and distributions, per share, with respect to the Common Stock when,
as and if declared by the Board of Directors from funds legally available
therefor. No holder of any shares of Common Stock has a preemptive right to
subscribe for any securities of the Company nor are any shares of Common Stock
subject to redemption or convertible into other securities of the Company. Upon
liquidation, dissolution or winding up of the Company, and after payment of
creditors and preferred shareholders, if any, the assets will be divided
pro-rata on a share-for-share basis among the holders of the shares of Common
Stock. All shares of Common Stock now outstanding are fully paid, validly issued
and non-assessable. Holders of the Common Stock do not have cumulative voting
rights, so that holders of more than 50% of the combined shares voting for the
election of directors may elect all of the directors, if they choose to do so
and, in that event, the holders of the remaining shares will not be able to
elect any members to the Board of Directors. At September 30, 1997, there were
reserved for issuance (i) 1,097,676 shares of Common Stock issuable upon
exercise of various outstanding warrants (including the public Warrants); (ii)
1,313,589 shares of Common Stock issuable upon exercise of options held by
management and other employees; and (iii) 1,702,127 shares of Common Stock
issuable upon conversion of the TCW Preferred Stock.

PREFERRED STOCK

Under the Company's Articles of Incorporation, as amended, the Board of
Directors has the power, generally without further action by the holders of the
Common Stock, to designate the relative rights and preferences of the Preferred
Stock, par value $.001 (the "Preferred Stock"), and issue the Preferred Stock in
one or more series as designated by the Board of Directors. The designation of
rights and preferences could include preferences as to liquidation, redemption
and conversion rights, voting rights, dividends or other preferences, any of
which may be dilutive of the interest of the holders of the Common Stock or
other series of Preferred Stock. The issuance of Preferred Stock may have the
effect of delaying or preventing a change in control of the Company without
further shareholder action and may adversely affect the rights and powers,
including voting rights, of the holders of Common Stock. In certain
circumstances, the issuance of Preferred Stock could depress the market price of
the Common Stock. The Board of Directors effects a designation of each series of
Preferred Stock by filing with the Nevada Secretary of State a Certificate of
Designation defining the rights and preferences of each such series. Documents
so filed are matters of public record and may be examined in accordance with
procedures of the Nevada Secretary of State, or copies thereof may be obtained
from the Company.

The Board of Directors designated a Series A Preferred Stock in May 1993
and subsequently issued 216,000 shares of such series, of which 80,000 shares
are presently outstanding. The Board of Directors also previously designated a
Series B Preferred Stock and issued 248,500 shares of such series, and a Series
C Preferred Stock and issued 625,000 shares of such series. No shares of either
the Series B or Series C Preferred Stock are currently outstanding. The Board of
Directors designated a 1996 Series A Convertible Preferred Stock (the "TCW
Preferred Stock") and issued 1,000,000 shares of such series in December 1996.
See " -- TCW Preferred Stock."

Series A Preferred Stock

There are presently 80,000 shares of Series A Preferred Stock outstanding,
which are entitled to an aggregate dividend in the total amount of $7.50 per
share, payable only from the allocation of 50% of the net operating revenue
received by the working interest owners in the West Dilley Prospect and between
50% and 60% of the net operating revenue in excess of $500,000 received by the
working interest owners in the Hope Prospect. The Company owns 90% of the
working interest in such prospects. The dividend is cumulative to the extent
accrued but not paid. To date no dividends have accrued or been paid on the
Series A Preferred Stock because the revenues generated from such prospect,
which are allocable to the working interests, have not

49
<PAGE> 50

exceeded the associated costs, so no net operating revenue has yet been
generated that could be allocated to the payment of such dividends. The shares
of Series A Preferred Stock have a liquidation preference on the liquidation
proceeds from the Company's interest in the West Dilley Prospect and the Hope
Prospect. The Company has not yet paid and does not anticipate paying any
dividends on the Series A Preferred Stock because the wells located in the West
Dilley Prospect and the Hope Prospect from which the dividends are required to
be paid are plugged and abandoned. The Company has agreed with TCW to use its
best efforts to negotiate with the holders of the Series A Preferred Stock for
the repurchase of their shares.

TCW Preferred Stock

In December 1996, the Company issued 1,000,000 shares of its TCW Preferred
Stock in a private placement with Trust Company of the West, as trustee,
custodian or agent for certain institutional investors, TCW Asset Management
Company, as agent for certain institutional investors, TCW Debt and Royalty Fund
IVB and TCW Debt and Royalty Fund IVC (collectively, "TCW"). Holders of such
shares are entitled to receive when, as and if declared by the Board of
Directors out of funds legally available for the purpose, cumulative dividends
at a quarterly rate of $.21875 per share, commencing December 31, 1996.
Dividends on the TCW Preferred Stock cumulate from the date of original issue of
the TCW Preferred Stock, and accumulations of dividends bear interest at 8.75%
per annum. Such dividends are normally to be paid in cash, but the holders of
the TCW Preferred Stock can require the Company to pay accumulated dividends in
tradeable shares of Common Stock if dividends are not declared or paid within
certain time limitations. If the holders make such a demand, the Company is
obligated to file a "shelf" registration statement with respect to such shares.
The use of proceeds from the sale of the TCW Preferred Stock is limited to
development of proved undeveloped properties, working capital and/or a reduction
of any indebtedness outstanding under its credit facilities.

The shares are convertible into shares of Common Stock at a conversion
price of $5.875 per share (subject to various adjustments). Beginning in
December 1998, the Company has an option, if certain conditions are satisfied,
to exchange shares of the TCW Preferred Stock into convertible subordinated
debentures of equivalent value or into shares of Common Stock. The holders also
have the right to require the Company to redeem all or any part of the TCW
Preferred Stock upon certain sales of all or substantially all of the Company's
assets or upon changes in control.

The holders of the TCW Preferred Stock are entitled, on all matters
submitted for a vote of the holders of shares of Common Stock, whether pursuant
to law or otherwise, to a number of votes per share of the TCW Preferred Stock
equal to the number of shares of Common Stock issuable upon conversion of one
share of the TCW Preferred Stock on the date of such vote, and on all such
matters such holders vote together as one class with the holders of Common Stock
and the holders of all other shares of stock entitled to vote with the holders
of Common Stock on such matters. The holders of the TCW Preferred Stock have the
right, as a class, to elect at least one member of the Board of Directors of the
Company. Upon certain special events, the holders of the TCW Preferred Stock
will have the right, voting separately from all other classes and series, to
elect a total of 75% of the directors of the Company either through call of a
special meeting of the shareholders of the Company or at the annual meeting to
elect directors. Such special events ("Voting Events") include but are not
limited to (i) failure by the Company to redeem the TCW Preferred Stock when
such redemption is required; (ii) certain events causing any debt or security of
the Company or any of its subsidiaries to become due prior to its stated
maturity or prior to its regularly scheduled payment (if, except for the
Company's senior bank or other credit facility, such debt exceeds $3.0 million,
and if the Company is given notice of the acceleration); (iii) bankruptcy of the
Company; (iv) dissolution of the Company; and (v) breach by the Company of any
terms regarding the TCW Preferred Stock in the TCW Stock Purchase Agreement or
Certificate of Designation. If the average closing price of the Company's Common
Stock is below certain levels after January 1, 1999, the occurrence of a Voting
Event will give the holders of the TCW Preferred Stock the right, voting
separately from all other classes and series, to elect one additional director
of the Company every 60 days (or every 45 days, if the Board of Directors
increases above seven persons, excluding persons appointed by such holders)
until the Voting Event no longer remains outstanding.

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<PAGE> 51

So long as any TCW Preferred Stock is outstanding, the Company cannot,
without the affirmative vote of all of the holders of the outstanding shares of
TCW Preferred Stock, voting separately as a class, amend or repeal any provision
of the Articles of Incorporation which affect the dividend rate, liquidation
amount, liquidation preference, conversion price, dividend and liquidation
priority, voting rights, or mandatory redemption rights and terms of the TCW
Preferred Stock. Unless the vote or consent of the holders of a greater number
of shares is then required by law or as provided in the immediately preceding
sentence, and so long as any shares of the TCW Preferred Stock are outstanding,
the Company cannot, without the affirmative vote or consent of the holders of at
least 70% of the outstanding shares of TCW Preferred Stock, voting as a separate
class: (i) amend or repeal any provision of, or add any provision to, the
Company's Articles of Incorporation which affect the other rights, powers,
preferences or terms of the TCW Preferred Stock; (ii) consolidate or merge with
or into any other corporation where (1) the Company is not the surviving
corporation or (2) the Company issues to any person as consideration in respect
of such consolidation or merger any capital stock of the Company representing
50% or more of the Company's outstanding capital stock prior to such
consolidation or merger; (iii) sell, transfer or convey all or substantially all
of the assets of the Company, or dissolve or liquidate the Company; (iv)
reclassify any Common Stock into shares having any preference or priority as to
the payment of dividends or the distribution of assets superior to or on a
parity with any such preference or priority of the 1996 Series A Preferred
Stock; (v) declare or pay any dividend, or make any distribution, or purchase,
redeem or otherwise acquire for value any capital stock or other interest in the
Company outstanding on or after first issuance of the 1996 Series A Preferred
Stock, or make any other distribution of its assets, to the holders of any stock
junior to the 1996 Series A Preferred Stock, unless (i) no Voting Events have
occurred and are continuing immediately prior to and after such distributions,
and (ii) all accumulated dividends with respect to the 1996 Series A Preferred
Stock have been paid in full immediately prior to such distribution; or (vi)
amend or otherwise modify in any material respect the Company's Development Plan
furnished pursuant to the Stock Purchase Agreement relating to the TCW Preferred
Stock.

Upon the request of at least 51% of the outstanding TCW Preferred Stock and
the Common Stock issuable upon conversion or redemption of the TCW Preferred
Stock and in payment of dividends on the TCW Preferred Stock (collectively, the
"Conversion Shares"), the Company has the obligation to register the Conversion
Shares under the Securities Act (subject to certain limitations). The holders of
the TCW Preferred Stock are entitled to require two effective registration
statements pursuant to their demand registration rights. If the Company proposes
to register any of its securities under the Securities Act, the Company has the
obligation (subject to certain limitations and exceptions) to give written
notice to the holders of outstanding TCW Preferred Stock and Conversion Shares
of its intention to do so. Upon the written request of a holder or holders of
any such TCW Preferred Stock and Conversion Shares given within 30 days after
receipt of any such notice, the Company has an obligation to use its best
efforts to cause all Conversion Shares, the holders of which have requested
registration thereof, to be registered under the Securities Act. The Company has
promised to indemnify (i) the holders of Common Stock registered pursuant to the
foregoing registration rights provisions and (ii) the underwriters of such
registered offerings for any losses arising from any misstatement or omission in
any offering materials related to such registered offerings.

Pursuant to the provisions of the TCW Preferred Stock, the Company has
agreed (i) not to effect any public or private sale or distribution of its
equity securities during the period in which TCW has exercised its demand
registration rights, subject to certain exceptions and (ii) to cause each holder
of its privately-placed equity securities purchased from the Company at any time
after the date of the TCW Stock Purchase Agreement to agree not to effect any
public sale or distribution of any such securities, including a sale pursuant to
Rule 144 under the Securities Act (except as part of a permitted underwritten
registration).

WARRANTS

Public Warrants

In November 1993 the Company issued warrants in a public offering (the
"Warrants"). Each Warrant represented the right to purchase three shares of
Common Stock at an exercise price of $5.50 per share and was redeemable at $0.02
per Warrant. The Company called the Warrants for redemption on November 14,

51
<PAGE> 52

1997. As a result, Warrants were exercised for an aggregate of 846,256 shares of
Common Stock and the remaining Warrants covering 7,920 shares of Common Stock
were redeemed.

Miscellaneous Outstanding Warrants

Between December 1995 and January 1997, the Company issued warrants
exercisable for an aggregate of 343,500 shares of Common Stock at exercise
prices ranging from $3.00 to $4.50 per share. These warrants, which expire
between June 1997 and January 2000, were issued in exchange for certain services
rendered. As of September 30, 1997, 100,000 of such warrants had been exercised.

In October 1996, the Company granted American Founders Life Insurance
Company warrants to purchase 75,000 shares of Common Stock for prices ranging
from $5.18 to $6.13 per share (25,000 at $5.18, 25,000 at $5.65 and 25,000 at
$6.13) as part of a production payment financing. These warrants expire between
October 31, 1999 and October 31, 2001, depending upon the balance of a certain
investment. The warrants are subject to adjustment upon certain
reclassifications of the shares of Common Stock underlying the warrants.

REGISTRATION RIGHTS

Certain holders of the Company's securities have been granted registration
rights for their Common Stock. These include (i) certain piggyback and demand
registration rights held by the holders of the TCW Preferred Stock, (ii)
piggyback registration rights on shares received upon exercising a warrant
issued to Research Works, Inc. on January 16, 1996, and (iii) piggyback
registration rights on shares received upon exercising warrants issued to
American Founders Life Insurance Company.

TRANSFER AGENT

Securities Transfer Corporation of Dallas, Texas is the transfer agent and
registrar for the Common Stock.

INDEMNIFICATION

The General Corporation Law of Nevada permits provisions in the articles,
by-laws or resolutions approved by shareholders which limit liability of
directors for breach of fiduciary duty of certain specified circumstances. The
Articles of Incorporation, with certain exceptions, eliminate any personal
liability of a director to the Company or its shareholders for monetary damages
for the breach of a director's fiduciary duty, and therefore a director cannot
be held liable for damages to the Company or its shareholders for gross
negligence or lack of due care in carrying out his fiduciary duties as a
director. Nevada law permits indemnification if a director or officer acts in
good faith in a manner reasonably believed to be in, or not opposed to, the best
interests of the corporation. A director or officer must be indemnified as to
any matter in which he successfully defends himself. Indemnification is
prohibited as to any matter in which the director or officer is adjudged liable
to the corporation. Insofar as indemnification for liabilities arising under the
Securities Act may be permitted to directors, officers, and controlling persons
of the Company pursuant to the foregoing provisions or otherwise, the Company
has been advised that in the opinion of the Commission, such indemnification is
against public policy as expressed in the Securities Act and is, therefore,
unenforceable.

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<PAGE> 53

DESCRIPTION OF INDEBTEDNESS

DESCRIPTION OF CREDIT FACILITY

On April 30, 1997, the Company entered into a $130.0 million revolving
credit facility (the "Credit Facility") with Bankers Trust Company, as
Administrative Agent, and certain other lenders (collectively, the "Lenders").
The purpose of the Credit Facility was to (i) repay the remaining $53.7 million
of indebtedness under the Company's previous credit facility, (ii) partially
finance the Permian Basin Acquisition, and (iii) provide funds for working
capital support and general corporate purposes. A $20.0 million letter of credit
sub-facility is available as support for purposes approved by the Lenders. The
Credit Facility is subject to a Borrowing Base determination established on
October 1 and April 1 of each year by the Lenders.

Following the offering of the Notes, the Credit Facility was decreased to
$75.0 million and the Borrowing Base was reduced to $60.0 million. The Credit
Facility was amended effective September 30, 1997 to increase the maximum
commitment of the Credit Facility to $125.0 million, increase the Borrowing Base
to $65.0 million and modify the Consolidated EBITDA to Interest Expense ratio
test. At November 17, 1997, $46.0 million was outstanding under the Credit
Facility.

Under the terms of the Credit Facility, the Company must maintain a Debt to
Capitalization Ratio of not more than 0.86 until March 31, 1998, not more than
0.75 from April 1, 1998 until September 30, 1998 and not more than 0.70
thereafter. Another covenant requires the Company to maintain a ratio of
Consolidated EBITDA to Interest Expense of not less than 1.80 to 1 through March
31, 1998, not less than 2.00 to 1 from April 1, 1998 until June 30, 1998, not
less than 2.25 to 1 from July 1, 1998 through September 30, 1998 and not less
than 2.50 to 1 thereafter. The Credit Facility also contains certain financial
and other covenants, which include a minimum tangible net worth test, a minimum
current ratio and other customary covenants in addition to the Debt to
Capitalization Ratio and the ratio of Consolidated EBITDA to Interest Expense.

The Company may select an interest rate equal to the Base Rate (defined in
the Credit Facility as the higher of (i) the prime rate of Bankers Trust Company
or (ii) the sum of the overnight rate on federal funds transactions plus 0.50%)
or a LIBOR-based rate, which varies depending upon the Company's usage of its
Borrowing Base. The LIBOR-based interest rate will range from LIBOR plus 1.00%
if less than 25% of the Borrowing Base is used to LIBOR plus 1.75% if 75% or
more of the Borrowing Base is used. At November 17, 1997 the Credit Facility
bore interest at a weighted average rate of 7.46% per annum under LIBOR and
prime rate interest options.

The Credit Facility has a maturity of five years with no required principal
payments until maturity, provided that the outstanding principal balance does
not exceed the Borrowing Base determinations established from time to time by
the Lenders. Outstanding indebtedness is secured by a first priority security
interest taken by the Lenders in substantially all assets owned now or in the
future by the Company (including its subsidiaries). All of the capital stock of
all wholly owned material subsidiaries of the Company is pledged pursuant to the
Credit Facility. Each of the Company's wholly owned subsidiaries has guaranteed
the Credit Facility.

The Credit Facility contains representations and warranties, conditions to
extensions of credit, events of default and indemnifications on terms customary
for credit facilities of this type.

DESCRIPTION OF THE NOTES

The Notes were issued under an indenture (the "Indenture") dated as of May
29, 1997 by and among the Company, each of the Company's subsidiaries, except
Hunter Butcher, as guarantors (the "Subsidiary Guarantors"), and First Union
National Bank of North Carolina, as Trustee (the "Trustee"). Upon the issuance
of the Exchange Notes (defined below), the Indenture will be subject to and
governed by the provisions of the Trust Indenture Act of 1939, as amended (the
"TIA"). The following summary of certain provisions of the Indenture does not
purport to be complete and is subject to, and is qualified in its entirety by
reference to, the TIA and all of the provisions of the Indenture, including the
definitions of certain terms therein and those terms made a part of the
Indenture by reference to the TIA as in effect on the date of the

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<PAGE> 54

Indenture. Capitalized terms used in this summary and not otherwise defined
below have the meaning assigned to them in the Indenture. For purposes of this
"-- Description of the Notes" section, references to the "Company" include only
Magnum Hunter Resources, Inc. and not its Subsidiaries.

The Company is currently conducting an exchange offer (the "Exchange
Offer"), pursuant to which the Company is offering to exchange up to $140.0
million aggregate principal amount of its 10% Senior Notes due 2007 (the
"Exchange Notes") that have been registered under the Securities Act of 1933, as
amended, for a like aggregate principal amount of its outstanding Notes (the
"Outstanding Notes"). The Exchange Offer expires at 5:00 p.m., New York City
time, on December 2, 1997, unless extended. The Exchange Notes will be issued
under the same Indenture as the Outstanding Notes, and the Exchange Notes, the
Private Exchange Notes (if any) and the Outstanding Notes will constitute a
single series of debt securities under the Indenture. The Exchange Notes, the
Private Exchange Notes and the Outstanding Notes are sometimes collectively
referred to herein as the "Notes."

The Notes are general unsecured obligations of the Company ranking pari
passu in right of payment to all unsubordinated indebtedness of the Company and
ranking senior in right of payment to all subordinated indebtedness of the
Company. The Guarantees are general unsecured obligations of the Subsidiary
Guarantors and rank pari passu in right of payment to all unsubordinated
indebtedness of the Subsidiary Guarantors and rank senior in right of payment to
all subordinated indebtedness of the Subsidiary Guarantors. However, the Notes
are effectively subordinated to secured indebtedness of the Company and the
Subsidiary Guarantors to the extent of the value of the assets securing such
indebtedness.

The Notes mature on June 1, 2007. Interest on the Notes generally will
accrue at the rate of 10% per annum and will be payable semi-annually in cash on
each June 1 and December 1, commencing on December 1, 1997. The Notes are not
entitled to the benefit of any mandatory sinking fund.

The Notes will be redeemable, at the Company's option, in whole at any time
or in part from time to time, on and after June 1, 2002 at a premium declining
ratably to par on or after June 1, 2005, plus accrued interest, if any, thereon
to the date of redemption. At any time, or from time to time, on or prior to
June 1, 2000, the Company may, at its option, use all or a portion of the net
cash proceeds of one or more Equity Offerings to redeem up to 35% of the
aggregate principal amount of the Notes originally issued at a redemption price
equal to 110% of the aggregate principal amount of the Notes to be redeemed,
plus accrued interest, if any, thereon to the date of redemption; provided,
however, that at least 65% of the aggregate principal amount of Notes originally
issued remains outstanding immediately after giving effect to any such
redemption.

Each Subsidiary Guarantor has unconditionally guaranteed, on a senior
basis, jointly and severally, to each holder and the Trustee, the full and
prompt performance of the Company's obligations under the Indenture and the
Notes, including the payment of principal of and interest on the Notes. The
obligations of each Subsidiary Guarantor will be limited to the maximum amount
which, after giving effect to all other contingent and fixed liabilities of such
Subsidiary Guarantor and after giving effect to any collections from or payments
made by or on behalf of any other Subsidiary Guarantor in respect of the
obligations of such other Subsidiary Guarantor under its Guarantee or pursuant
to its contribution obligations under the Indenture, will result in the
obligations of such Subsidiary Guarantor under its Guarantee not constituting a
fraudulent conveyance or fraudulent transfer under federal or state law. Each
Subsidiary Guarantor that makes a payment or distribution under its Guarantee
shall be entitled to a contribution from each other Subsidiary Guarantor in an
amount pro rata, based on the net assets of each Subsidiary Guarantor,
determined in accordance with GAAP.

The Indenture provides that upon the occurrence of a Change of Control,
each Holder will have the right to require that the Company purchase all or a
portion of such Holder's Notes at a purchase price equal to 101% of the
principal amount thereof, plus accrued interest, if any, thereon to the date of
purchase.

The Indenture contains covenants providing for, among other things, (i)
limitation on incurrence of additional indebtedness, (ii) limitation on
restricted payments, (iii) limitation on asset sales, (iv) limitation on
dividend and other payment restrictions affecting Restricted Subsidiaries, (v)
limitation on preferred stock

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<PAGE> 55

of Restricted Subsidiaries, (vi) limitation on liens, (vii) limitations on
merger, consolidation and sale of assets, (viii) limitations on transactions
with affiliates, (ix) limitation on Restricted and Unrestricted Subsidiaries,
(x) additional Subsidiary Guarantees, (xi) limitation on conduct of business,
and (xii) reports to holders.

Upon an Event of Default, the Trustee or the holders of at least 25% in
principal amount of outstanding Notes may declare the principal, premium, if
any, and accrued and unpaid interest on all the Notes to be immediately due and
payable. The holders of a majority in principal amount of the Notes may rescind
such declaration of acceleration in certain circumstances.

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<PAGE> 56

UNDERWRITING

The Underwriters named below, represented by Rauscher Pierce Refsnes, Inc.,
CIBC Oppenheimer Corp., Johnson Rice & Company L.L.C. and Van Kasper & Company
(collectively, the "Representatives"), have severally agreed, subject to the
terms and conditions of the Underwriting Agreement, to purchase from the Company
and the Selling Shareholder the number of shares of Common Stock set forth
opposite their respective names below. The nature of the obligations of the
Underwriters is such that if any of such shares are purchased, all must be
purchased.

<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITERS SHARES
------------ ---------
<S> <C>
Rauscher Pierce Refsnes, Inc................................ 1,685,000
CIBC Oppenheimer Corp. ..................................... 1,685,000
Johnson Rice & Company L.L.C. .............................. 1,685,000
Van Kasper & Company........................................ 545,000
ABN AMRO Chicago Corporation................................ 80,000
Dain Bosworth Incorporated.................................. 80,000
Jefferies & Company, Inc. .................................. 80,000
Ladenburg Thalmann & Co. Inc. .............................. 80,000
McDonald & Company Securities, Inc. ........................ 80,000
Morgan Keegan & Company, Inc. .............................. 80,000
Petrie Parkman & Co. ....................................... 80,000
Principal Financial Securities, Inc. ....................... 80,000
Raymond James & Associates, Inc. ........................... 80,000
Sutro & Co. Incorporated.................................... 80,000
Hoak Breedlove Wesneski & Co. .............................. 40,000
Pennsylvania Merchant Group Ltd............................. 40,000
Rodman & Renshaw, Inc. ..................................... 40,000
Southeast Research Partners, Inc. .......................... 40,000
Starr Securities, Inc. ..................................... 40,000
---------
Total............................................. 6,600,000
=========
</TABLE>

The Underwriters propose to offer the shares of Common Stock offered hereby
to the public at the price to public set forth on the cover page of this
Prospectus. The Underwriters may allow a concession to selected dealers who are
members of the National Association of Securities Dealers, Inc. ("NASD") not in
excess of $0.18 per share, and the Underwriters may allow, and such dealers may
reallow, to members of the NASD a concession not in excess of $0.10 per share.
After the public offering, the price to public, the concession and the
reallowance may be changed by the Representatives.

The Company has granted an option to the Underwriters, exercisable within
30 days after the date of this Prospectus, to purchase up to an aggregate of
990,000 additional shares of Common Stock at the initial price to public, less
the underwriting discount, set forth on the cover page of this Prospectus. The
Underwriters may exercise the option only for the purpose of covering
over-allotments. To the extent that the Underwriters exercise such option, each
Underwriter will be committed, subject to certain conditions, to purchase from
the Company that number of additional shares of Common Stock which is
proportionate to such Underwriter's initial commitment as indicated in the table
above.

The Company and its executive officers and directors have agreed that for a
period of 90 days after the date of this Prospectus they will not, directly or
indirectly, offer to sell, sell, pledge, contract to sell, grant any option to
sell, or otherwise dispose of any shares of Common Stock (or securities
convertible into or exercisable or exchangeable for, or any rights or options to
purchase or acquire, Common Stock or such securities) without the prior written
consent of Rauscher Pierce Refsnes, Inc., except, in the case of the Company,
for transactions related to the Company's existing option plans and other
employee benefit plans or related to outstanding stock options and warrants
disclosed in this Prospectus.

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<PAGE> 57

The Company and the Selling Shareholder have agreed to indemnify the
Underwriters against certain liabilities that may be incurred in connection with
the Offering, including liabilities under 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
Common Stock in the open market. The transactions may include over-allotment and
stabilization transactions 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 Selling Shareholder and the Company in
the Offering. The Representatives 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 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 may be discontinued at any time. These transactions
may be effected on the American Stock Exchange, in the over-the-counter market
or otherwise.

Neither the Company nor any of the Underwriters makes any representation or
prediction as to the direction or magnitude of any effect that the transactions
described above may have on the price of the Common Stock. In addition, neither
the Company nor any of the Underwriters makes any representation that the
Representatives will engage in such transactions or that such transactions, once
commenced, will not be discontinued without notice.

As a result of a recently completed merger, CIBC Oppenheimer Corp. ("CIBC
Oppenheimer") is affiliated with CIBC, Inc.("CIBC"). CIBC is a Lender under the
Credit Facility, which will be paid down with the proceeds of the Offering.
Accordingly, more than 10% of the net proceeds of the Offering, not including
underwriter compensation, may be paid to CIBC Oppenheimer and its affiliates.
Thus, pursuant to subparagraph (c)(8) of Rule 2710 of the Conduct Rules
promulgated by the National Association of Securities Dealers, Inc., the
Underwriters are required to comply with Rule 2720(c)(3) of the Conduct Rules
regarding certain potential conflicts of interest, which requires in paragraph
(B) that the Offering is of a class of equity securities for which a bona fide
independent market exists as of the date of filing and is expected to exist on
the effective date. The market for the Common Stock meets the definition of bona
fide independent market as stated in Rule 2720(b)(3) of the Conduct Rules.

Except as described with regard to CIBC Oppenheimer and CIBC, with respect
to subparagraph (c)(8) of Rule 2710 of the Conduct Rules relating to "Conflicts
of Interest" arising from "Proceeds Directed to a Member," none of the proceeds
of the Offering are intended to be paid to NASD members participating in the
distribution of the Offering or associated or affiliated persons of NASD members
participating in the distribution of the Offering or members of the immediate
family of any such person.

In the ordinary course of their business, certain of the Underwriters have
engaged in transactions with and performed services for the Company. In
addition, CIBC and CIBC Oppenheimer may continue to participate on a regular
basis in various general financing and banking transactions for the Company and
its affiliates.

LEGAL MATTERS

Certain legal matters with respect to the Common Stock offered hereby will
be passed upon for the Company and the Selling Shareholder by Thompson & Knight,
P.C., Dallas, Texas. Certain legal matters in connection with the Offering will
be passed upon for the Underwriters by Haynes and Boone, LLP.

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<PAGE> 58

EXPERTS

The consolidated balance sheet of Magnum Hunter Resources, Inc. as of
December 31, 1996 and the related consolidated statements of operations,
stockholders' equity and cash flows for the year then ended, included elsewhere
and incorporated by reference in this Prospectus, have been audited by Deloitte
& Touche LLP, independent auditors, as stated in their report which is included
and incorporated by reference herein and have been so included in reliance upon
the report of such firm given upon their authority as experts in accounting and
auditing.

The financial statements of the Company as of December 31, 1995 and for the
year then ended have been audited by Hein + Associates LLP, independent
certified public accountants, as stated in their report which is included and
incorporated by reference herein and have been so included in reliance upon the
report of such firm given upon their authority as experts in accounting and
auditing. The change in accountants from Hein + Associates LLP to Deloitte &
Touche LLP was effective for fiscal 1996 and was not due to any disagreements
between the Company and Hein + Associates LLP.

The historical summaries of revenues and direct operating expenses of the
Permian Basin Properties for the years ended December 31, 1996 and 1995 have
been audited by Hein + Associates LLP, independent certified public accountants,
as stated in their report, which is included and incorporated by reference
herein and have been so included in reliance upon the report of such firm given
upon their authority as experts in accounting and auditing.

The reference to the report of Ryder Scott Co., independent petroleum
consultants, contained herein estimating the Proved Reserves, future net cash
flows from such Proved Reserves and the SEC PV-10 of such estimated future net
cash flows for the Permian Basin Properties as of December 31, 1996 is made in
reliance upon the authority of such firm as an expert with respect to such
matters.

The reference to the report of Gaffney, Cline & Associates Inc.,
independent petroleum consultants, contained herein estimating the Proved
Reserves, future net cash flows from such Proved Reserves and the SEC PV-10 of
such estimated future net cash flows for the Company's properties (other than
certain west Texas properties) as of December 31, 1996 is made in reliance upon
the authority of such firm as experts with respect to such matters.

The reference to the report of Glenn Harrison Petroleum Consultants, Inc.,
independent petroleum consultants, contained herein estimating the Company's
Proved Reserves, future net cash flows from such Proved Reserves and the SEC
PV-10 of such estimated future net cash flows for certain west Texas properties
as of December 31, 1996 is made in reliance upon the authority of such firm as
experts with respect to such matters.

The reference to the reports of James J. Weisman, Jr., an independent
petroleum engineer, contained herein auditing the Company's estimates of its
Proved Reserves, the estimated future net cash flows from such Proved Reserves,
and the SEC PV-10 of such estimated future net cash flows as of December 31,
1995 is made in reliance upon the authority of such individual as an expert with
respect to such matters.

AVAILABLE INFORMATION

The Company is subject to the informational requirements of the Exchange
Act and, in accordance therewith, files reports, proxy statements and other
information with the Commission. Such reports, proxy statements and other
information can be inspected and copied at the office of the Commission at Room
1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, as well
as the regional offices of the Commission at Citicorp Center, 500 West Madison
Street, Suite 1400, Chicago, Illinois 60661, and Seven World Trade Center, 13th
Floor, New York, New York 10048. Copies of such information can be obtained by
mail from the Public Reference Section of the Commission at Judiciary Plaza, 450
Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates. Additionally,
the Commission maintains a web site that contains reports, proxy statements and
other information regarding registrants that file electronically with the
Commission. The address of the Commission's web site is http://www.sec.gov. The
Company's Common

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<PAGE> 59

Stock is listed on the American Stock Exchange and copies of reports, proxy
statements and other information concerning the Company also can be inspected at
the offices of the American Stock Exchange, 86 Trinity Place, New York, New York
10006-1881.

This Prospectus constitutes a part of a registration statement on Form S-3
(the "Registration Statement") filed by the Company with the Commission under
the Securities Act. This Prospectus does not contain all the information set
forth in the Registration Statement, certain parts of which are omitted in
accordance with the rules and regulations of the Commission, and reference is
hereby made to the Registration Statement and to the exhibits relating thereto
for further information with respect to the Company and the Common Stock. Any
statements contained herein concerning the provisions of any document are not
necessarily complete, and, in each instance, reference is made to a copy of such
document filed as an exhibit to the Registration Statement or otherwise filed
with the Commission. Each such statement is qualified in its entirety by such
reference.

The Company, a corporation organized under the laws of Nevada, has its
principal executive offices located at 600 East Las Colinas Boulevard, Suite
1200, Irving, Texas 75039; its telephone number is (972) 401-0752.

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

The following documents and information heretofore filed with the
Commission by the Company are hereby incorporated by reference into this
Prospectus:

1. The Company's Annual Report on Form 10-KSB for the year ended
December 31, 1996, as amended by Form 10-KSB/A filed June 27, 1997;

2. An amendment to the Company's Quarterly Report on Form 10-QSB/A for
the quarter ended September 30, 1996, filed on March 18, 1997;

3. The Company's Quarterly Report on Form 10-QSB for the quarters
ended March 31, 1997, as amended by Form 10-QSB/A filed on May 21, 1997,
June 30, 1997 and September 30, 1997;

4. The Company's Current Reports on Form 8-K dated January 20, 1997
(as amended by Form 8-K/A filed on February 5, 1997), February 28, 1997,
April 30, 1997, May 20, 1997 and May 29, 1997; and

5. The description of Common Stock contained in the Registration
Statement on Form 8-A of the Company heretofore filed with the Commission,
including any amendments or reports filed for the purpose of updating such
description.

All documents subsequently filed by the Company pursuant to Sections 13(a),
13(c), 14 or 15(d) of the Exchange Act, prior to the termination of the Offering
shall be deemed to be incorporated by reference into this Prospectus and to be a
part hereof from the date of filing of such documents. Any statement contained
in a document incorporated or deemed to be 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 or in any other subsequently filed
document which also is or is deemed to be incorporated by reference 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 UNDERTAKES TO PROVIDE WITHOUT CHARGE TO EACH PERSON, INCLUDING
ANY BENEFICIAL OWNER, TO WHOM THIS PROSPECTUS IS DELIVERED, ON THE WRITTEN OR
ORAL REQUEST OF ANY SUCH PERSON, A COPY OF ANY AND ALL OF THE DOCUMENTS
INCORPORATED BY REFERENCE HEREIN (OTHER THAN EXHIBITS TO SUCH DOCUMENTS WHICH
ARE NOT SPECIFICALLY INCORPORATED BY REFERENCE IN SUCH DOCUMENTS). WRITTEN
REQUESTS FOR SUCH COPIES SHOULD BE DIRECTED TO THE COMPANY, 600 EAST LAS COLINAS
BLVD., SUITE 1200, IRVING, TEXAS 75039, ATTENTION: MORGAN F. JOHNSTON, VICE
PRESIDENT, GENERAL COUNSEL AND SECRETARY. TELEPHONE REQUESTS MAY BE DIRECTED TO
MR. JOHNSTON AT (972) 401-0752.

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<PAGE> 60

GLOSSARY

The terms defined in this glossary are used throughout this Prospectus.

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

BBL/D. One barrel of oil or other liquid hydrocarbons per day.

BCF. One billion cubic feet of gas.

BCF/D. One billion cubic feet of gas per day.

BCFE. One billion cubic feet of natural gas equivalents converting one Bbl
of oil to six Mcf of gas.

BTU. British Thermal Unit, the quantity of heat required to raise one pound
of water by one degree Fahrenheit.

DEVELOPED ACREAGE. The number of acres which are allocated or assignable to
producing wells or wells capable of production.

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.

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.

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 OR GROSS WELLS. The total acres or wells, as the case may be,
in which a working interest is owned.

IN-FILL WELL. A well drilled between known producing wells to better
exploit the reservoir.

MBBL. One thousand barrels of oil or other liquid hydrocarbons.

MCF. One thousand cubic feet of gas.

MCFE. One thousand cubic feet of natural gas equivalents converting one Bbl
of oil to six Mcf of gas.

MCFE/D. Mcfe per day.

MMBBL. One million barrels of oil or other liquid hydrocarbons.

MMBTU. One million Btu.

MMCF. One million cubic feet of gas.

MMCFE. One million cubic feet of natural gas equivalents converting one Bbl
of oil to six Mcf of gas.

MMCF/D. One million cubic feet of gas per day.

NATURAL GAS EQUIVALENT. The amount of gas having the same Btu content as a
given quantity of oil, with one Bbl of oil being converted to six Mcf of gas.

NET ACRES OR NET WELLS. The sum of the fractional working interests owned
in gross acres or gross wells.

NET REVENUE INTEREST. A share of the Working Interest that does not bear
any portion of the expense of drilling and completing a well and that represents
the holder's share of production after satisfaction of all royalty, overriding
royalty, oil payments and other nonoperating interests.

PRODUCTIVE WELL. A well that is producing oil or gas or that is capable of
production in paying quantities.

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<PAGE> 61

NON-PRODUCING RESERVES. Proved Developed Reserves that consist of (i)
proved reserves from wells which have been completed and tested but are not
producing due to lack of market or minor completion problems which are expected
to be corrected and (ii) proved reserves currently behind the pipe in existing
wells and which are expected to be productive due to both the well log
characteristics and analogous production in the immediate vicinity of the wells.

PRODUCING RESERVES. Proved Developed Reserves that can be expected to be
recovered from currently producing zones under the continuation of present
operating methods.

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

RECOMPLETION. The completion for production of an existing wellbore in a
different formation or producing horizon from that in which the well was
previously completed.

RESERVE LIFE. The estimated productive life of a proved reservoir based
upon the economic limit of such reservoir producing hydrocarbons in paying
quantities assuming certain price and cost parameters. For purposes of this
Prospectus, reserve life is calculated by dividing the Proved Reserves (on an
Mcfe basis) at the end of the period by projected production volumes for the
next 12 months.

ROYALTY INTEREST. An interest in an oil and gas property entitling the
owner to a share of oil and gas production free of cost of production.

SEC PV-10. The present value of proved reserves is an estimate of the
discounted future net cash flows from each of the properties at December 31,
1996, or as otherwise indicated. Net cash flow is defined as net revenues less,
after deducting production and ad valorem taxes, future capital costs and
operating expenses, but before deducting federal income taxes. As required by
rules of the Commission, the future net cash flows have been discounted at an
annual rate of 10% to determine their "present value." The present value is
shown to indicate the effect of time on the value of the revenue stream and
should not be construed as being the fair market value of the properties. In
accordance with Commission rules, estimates have been made using constant oil
and gas prices and operating costs, at December 31, 1996, or as otherwise
indicated.

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 that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.

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<PAGE> 63

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
UNAUDITED PRO FORMA COMBINED FINANCIAL DATA
Unaudited Pro Forma Combined Income Statement for the year
ended December 31, 1996................................... F-3
Unaudited Pro Forma Combined Income Statement for the nine
months ended
September 30, 1997........................................ F-4
Notes to Unaudited Pro Forma Combined Financial Data........ F-5
AUDITED FINANCIAL STATEMENTS
Independent Auditors' Report -- Hein + Associates LLP....... F-8
Independent Auditors' Report -- Deloitte & Touche LLP....... F-9
Consolidated Balance Sheets as of December 31, 1995 and
1996...................................................... F-10
Consolidated Statements of Operations for the years ended
December 31, 1995 and 1996................................ F-11
Consolidated Statements of Stockholders' Equity for the
years ended December 31, 1995
and 1996.................................................. F-12
Consolidated Statements of Cash Flows for the years ended
December 31, 1995 and 1996................................ F-13
Notes to Consolidated Financial Statements.................. F-14
Supplemental Information on Oil and Gas Producing Activities
(Unaudited)............................................... F-29
UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheet as of September 30, 1997
(Unaudited)............................................... F-32
Consolidated Statements of Operations for the three months
ended September 30, 1996 and 1997 and the nine months
ended September 30, 1996 and 1997 (Unaudited)............. F-33
Consolidated Statements of Cash Flows for the nine months
ended September 30, 1996 and 1997 (Unaudited)............. F-34
Notes to Unaudited Consolidated Financial Statements........ F-35
FINANCIAL STATEMENTS OF PERMIAN BASIN PROPERTIES
Independent Auditors' Report -- Hein + Associates LLP....... F-37
Historical Summaries of Revenues and Direct Operating
Expenses of the Permian Basin Properties for the years
ended December 31, 1995 and 1996 and for the four month
unaudited periods ended April 30, 1996 and 1997........... F-38
Notes to Historical Summaries of Revenues and Direct
Operating Expenses for the years ended December 31, 1995
and 1996 and for the four month unaudited periods ended
April 30, 1996 and 1997................................... F-39
</TABLE>

F-1
<PAGE> 64

UNAUDITED PRO FORMA COMBINED FINANCIAL DATA

The following unaudited pro forma combined financial data are derived from
the Consolidated Financial Statements of the Company herein and certain
historical financial data in respect of various assets acquired by the Company.
The historical revenues and oil and gas production and gas gathering and
marketing expenses of the McLean Gas Plant, the Panoma Properties and the
Permian Basin Properties represent amounts recorded with respect to such
properties for the period indicated. The Unaudited Pro Forma Income Statement
for the year ended December 31, 1996 has been prepared assuming the Panoma
Acquisition, the issuance of the TCW Preferred Stock, the McLean Plant
Acquisition, the conversion of the Series B and Series C Preferred Stock into
Common Stock, the Permian Basin Acquisition (including the incurrence of
indebtedness under the Credit Facility and the Company's previously existing
term loan facility and the use of proceeds therefrom) and the offering of the
Notes (the "Debt Offering") and the application of the net proceeds therefrom
had been consummated as of January 1, 1996. The Unaudited Pro Forma Income
Statement for the nine months ended September 30, 1997 has been prepared
assuming the Permian Basin Acquisition (including the incurrence of indebtedness
under the Credit Facility and the Company's previously existing term loan
facility and the use of proceeds therefrom) and the Debt Offering and the
application of the net proceeds therefrom had been consummated as of January 1,
1997. The pro forma adjustments set forth on the attached Unaudited Pro Forma
Income Statements reflect the following as if they occurred on the dates
hereinabove set forth:

(1) Recent Transactions. The Panoma Acquisition completed in June
1996; the conversion or redemption of the Series B and Series C Preferred
Stock in 1996; the issuance of the TCW Preferred Stock in December 1996;
and the McLean Plant Acquisition in January 1997.

(2) Permian Basin Acquisition. The Permian Basin Acquisition completed
in April 1997 (including the incurrence of indebtedness under the Credit
Facility and the Company's previously existing term loan facility (the
"Term Loan Facility") to finance the Permian Basin Acquisition and repay
the indebtedness under the previous credit facility (the "Previous Credit
Facility")).

(3) The Debt Offering. The Debt Offering and the application of the
net proceeds therefrom.

The unaudited pro forma combined financial data should be read in
conjunction with the notes thereto and with the Consolidated Financial
Statements of the Company and the notes thereto and the historical summaries of
revenues and direct operating expenses of the Permian Basin Properties, all of
which are included herein.

The unaudited pro forma combined financial data are not indicative of the
financial position or results of operations of the Company which would actually
have occurred if the transactions described above had occurred at the dates
presented or which may be obtained in the future. In addition, future results
may vary significantly from the results reflected in such statements due to
normal oil and gas production declines, changes in prices paid for oil and gas,
future acquisitions, drilling activity and other factors.

F-2
<PAGE> 65

UNAUDITED PRO FORMA COMBINED INCOME STATEMENT
YEAR ENDED DECEMBER 31, 1996
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
PRO FORMA RECENT
PRO FORMA PRO FORMA PRO FORMA RECENT PRO FORMA TRANSACTIONS,
MAGNUM ADJUSTMENTS ADJUSTMENTS FOR TRANSACTIONS AND ADJUSTMENTS PERMIAN BASIN
HUNTER FOR RECENT PERMIAN BASIN PERMIAN BASIN FOR DEBT ACQUISITION AND
HISTORICAL TRANSACTIONS ACQUISITION ACQUISITION OFFERING DEBT OFFERING
---------- ------------ --------------- -------------------- ----------- ----------------
<S> <C> <C> <C> <C> <C> <C>
OPERATING REVENUES:
Oil and gas sales......... $10,248 $ 3,267(1) $ 39,433(9) $ 52,948 $ -- $ 52,948
Gas gathering, marketing
and processing.......... 5,768 3,562(2) -- 10,304 -- 10,304
974(1)
Oil field services and
international sales..... 396 -- -- 396 -- 396
------- ------- -------- -------- ---- --------
Total operating
revenue........... 16,412 7,803 39,433 63,648 -- 63,648
Operating Costs and
Expenses:
Oil and gas production.... 4,390 1,049(1) 11,646(9) 17,085 17,085
Gas gathering, marketing
and processing.......... 4,708 695(1) -- 6,879 -- 6,879
1,476(2)
Oil field services and
international sales..... 267 -- -- 267 -- 267
Depreciation and
depletion............... 2,951 1,203(3) 12,961(10) 17,282 -- 17,282
167(4)
General and
administrative.......... 1,225 100(5) 150(11) 1,475 -- 1,475
------- ------- -------- -------- ---- --------
Total operating
costs and
expenses.......... 13,541 4,690 24,757 42,988 -- 42,988
------- ------- -------- -------- ---- --------
Operating profit............ 2,871 3,113 14,676 20,660 -- 20,660
Other income.............. 344 -- -- 344 -- 344
Interest expense.......... (2,394) (1,555)(6) (14,059)(12) (18,008) 262(13) (17,746)
------- ------- -------- -------- ---- --------
Income before taxes and
extraordinary item........ 821 1,558 617 2,996 262 3,258
Provisions for deferred
income taxes............ (312) (584)(7) (231)(7) (1,127) (98)(7) (1,225)
------- ------- -------- -------- ---- --------
Income before extraordinary
item...................... 509 974 386 1,869 164 2,033
389(8)
Dividends applicable to
preferred shares........ (406) (858)(8) -- (875) -- (875)
------- ------- -------- -------- ---- --------
Income applicable to common
shares before
extraordinary item........ $ 103 $ 505 $ 386 $ 994 $164 $ 1,158
======= ======= ======== ======== ==== ========
Income per share before
extraordinary item...... $ .01 $ .03 $ .03 $ .07 $.01 $ .08
======= ======= ======== ======== ==== ========
OTHER FINANCIAL DATA:
EBITDA(14)................ $ 6,166 $ 4,483 $ 27,637 $ 38,286 $ -- $ 38,286
Capital expenditures...... $41,471 $ 2,500 $133,000 $176,971 $ -- $176,971
</TABLE>

See accompanying notes to Unaudited Pro Forma Combined Financial Data

F-3
<PAGE> 66

UNAUDITED PRO FORMA COMBINED INCOME STATEMENT
NINE MONTHS ENDED SEPTEMBER 30, 1997
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

<TABLE>
<CAPTION>
PRO FORMA
PERMIAN
PRO FORMA PRO FORMA BASIN
MAGNUM ADJUSTMENTS FOR PRO FORMA ADJUSTMENTS ACQUISITION
HUNTER PERMIAN BASIN PERMIAN BASIN FOR DEBT AND DEBT
HISTORICAL ACQUISITION ACQUISITION OFFERING OFFERING
---------- --------------- ------------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and gas sales.............. $22,793 $12,627(9) $ 35,420 $ -- $ 35,420
Gas gathering, marketing and
processing.................. 7,721 -- 7,721 -- 7,721
Oil field services and
international sales......... 3,792 -- 3,792 -- 3,792
------- ------- -------- ---- --------
Total operating
revenue.............. 34,306 12,627 46,933 -- 46,933
Operating Costs and Expenses:
Oil and gas production......... 8,521 3,039(9) 11,560 -- 11,560
Gas gathering, marketing and
processing.................. 5,803 -- 5,803 -- 5,803
Oil field services and
international sales......... 3,482 -- 3,482 -- 3,482
Depreciation and depletion..... 8,607 3,629(10) 12,236 -- 12,236
General and administrative..... 1,128 50(11) 1,178 -- 1,178
------- ------- -------- ---- --------
Total operating costs and
expenses.................. 27,541 6,718 34,259 -- 34,259
------- ------- -------- ---- --------
Operating profit................. 6,765 5,909 12,674 -- 12,674
Other income................... 608 -- 608 -- 608
Interest expense............... (9,298) (4,587)(12) (13,885) 87(13) (13,798)
------- ------- -------- ---- --------
Income before tax, minority
interest and extraordinary
item........................... (1,925) 1,322 (603) 87 (516)
Income tax (expense) benefit..... 731 (497)(7) 234 (31)(7) 203
Minority interest in subsidiary
earnings.................... (40) -- (40) -- (40)
------- ------- -------- ---- --------
Income before extraordinary
item........................... (1,234) 825 (409) 56 (353)
Dividends applicable to
preferred stock............. (657) -- (657) -- (657)
------- ------- -------- ---- --------
Income (loss) applicable to
common shares before
extraordinary item.......... $(1,891) $ 825 $ (1,066) $ 56 $ (1,010)
======= ======= ======== ==== ========
Income (loss) per share before
extraordinary item............. $ (0.14) $ 0.07 $ (0.07) $ -- $ (0.07)
======= ======= ======== ==== ========
OTHER FINANCIAL DATA:
EBITDA(14)....................... $15,980 $ 9,538 $ 25,518 $ -- $ 25,518
======= ======= ======== ==== ========
</TABLE>

See accompanying notes to Unaudited Pro Forma Combined Financial Data

F-4
<PAGE> 67

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL DATA
(IN THOUSANDS)

(1) To record the operating revenues and oil and gas production expenses and
gas gathering and marketing expenses for the first six months of 1996 for
the Panoma Properties that were acquired effective July 1, 1996 as if the
Panoma Acquisition had occurred on January 1, 1996.

(2) To record operating revenues and gas gathering and marketing expenses
related to the Company's 50% interest in the McLean Gas Plant, which was
acquired for $2,500 in January 1997, for the year ended December 31, 1996
as if the McLean Gas Plant had been acquired on January 1, 1996. The
Company will receive 100% of the net profits generated by the facility
until the $2,500 purchase price is recovered, after which it will receive
50% of the net profits. If the Company had received 50% of the net profits
generated by the McLean Gas Plant during the pro forma period presented,
its gross margin would have been reduced by $1,043.

(3) To record the pro forma depletion adjustment to reflect the Company's
depletion expense as if the Panoma Properties that were acquired effective
July 1, 1996 had been acquired on January 1, 1996.

(4) To record one year of depreciation expense on the McLean Gas Plant
(depreciable life is 15 years) as if the McLean Gas Plant had been acquired
on January 1, 1996.

(5) To record estimated additional general and administrative expenses that
would have been incurred if the Panoma Properties that were acquired
effective July 1, 1996 had been acquired on January 1, 1996.

(6) To record interest expense as if the McLean Plant Acquisition and the
Panoma Acquisition had occurred on January 1, 1996 as set forth below.
These acquisitions were assumed to be financed by the Previous Credit
Facility with an average interest rate during 1996 of 7.625%.

<TABLE>
<S> <C>
McLean Gas Plant-interest................................... $ 191
Panoma Properties-interest.................................. 1,321
Panoma Properties-amortization of associated debt issuance
costs..................................................... 43
------
$1,555
======
</TABLE>

(7) To record the effect of the pro forma adjustments on deferred and current
federal and state income taxes at an assumed tax rate of 37.5% after
consideration of available net operating losses and other carryforwards.

(8) To remove the $389 of dividends applicable to Series B and Series C
Preferred Stock that was redeemed or converted to Common Stock in late 1996
as if the redemption or conversion had occurred on January 1, 1996, and to
record dividends at a rate of 8.75% on the TCW Preferred Stock issued in
December 1996 as if it had been outstanding since January 1, 1996.

(9) To record the Permian Basin Properties operating revenues and oil and gas
production expenses as if the Permian Basin Acquisition had occurred on
January 1, 1996 for the December 31, 1996 pro forma income statement and on
January 1, 1997 for the pro forma September 30, 1997 income statement.

(10) To record the pro forma depletion adjustment to reflect the Company's
depletion expense as if the Permian Basin Properties had been acquired on
January 1, 1996 for the December 31, 1996 pro forma income statement and on
January 1, 1997 for the pro forma September 30, 1997 income statement.

(11) To record the Company's estimates of general and administrative expenses
that would have been incurred if the Permian Basin Properties had been
acquired on January 1, 1996 for the December 31, 1996 pro forma income
statement and on January 1, 1997 for the September 30, 1997 income
statement,

F-5
<PAGE> 68

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL DATA -- (CONTINUED)
(IN THOUSANDS)

net of estimated fees that would have been earned by the Company from third
parties on the properties it operates, as follows:

<TABLE>
<CAPTION>
1996 1997
----- -----
<S> <C> <C>
Additional general and administrative expenses............ $ 702 $ 235
Operating fees earned from third parties.................. (552) (185)
----- -----
$ 150 $ 50
===== =====
</TABLE>

(12) To record the interest expense associated with the borrowing of $119,500
under the Credit Facility and $60,000 under the Term Loan Facility to
complete the Permian Basin Acquisition and to refinance the Previous Credit
Facility as if the acquisition and refinancing had closed on the beginning
of the respective periods.

The Credit Facility and the Term Loan Facility are assumed to have interest
rates of 9.0% and 11.5%, respectively. The debt issuance costs associated
with the facilities are as follows:

<TABLE>
<S> <C>
Credit Facility debt issuance costs......................... $ 700
Term Loan Facility debt issuance costs...................... 1,800
------
$2,500
======
</TABLE>

The components of this interest expense adjustment are as follows:

<TABLE>
<CAPTION>
1996 1997
------- -------
<S> <C> <C>
Elimination of pro forma interest adjustments for
McLean Plant Acquisition and Panoma Acquisition and
amortization of associated debt issuance costs....... $(1,555) $ --
Elimination of historical interest expense on Previous
Credit Facility...................................... (2,394) (1,415)
Interest on Credit Facility............................ 10,755 3,585
Amortization of debt issuance costs on Credit
Facility............................................. 133 44
Interest on Term Loan Facility......................... 6,900 2,300
Amortization of debt issuance costs on Term Loan
Facility............................................. 220 73
------- -------
$14,059 $ 4,587
======= =======
</TABLE>

(13) To adjust interest expense to reflect the repayment of the Term Loan
Facility and repayment of $75,500 of indebtedness under the Credit Facility
with the net proceeds of the Debt Offering. The interest rate on the Notes
is 10.0%. After repayment of the Term Loan Facility, using the net proceeds
of the Debt Offering, the Credit Facility will bear interest on an assumed
interest rate of 7.6% per annum. The $4,500 of estimated debt issuance
costs are amortized using the effective yield method over the life of the
Notes. This adjustment excludes an extraordinary charge to expense of
$1,800 debt issuance costs

F-6
<PAGE> 69

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL DATA -- (CONTINUED)
(IN THOUSANDS)

associated with repayment of the Term Loan Facility. The components of the
interest expense adjustment are as follows:

<TABLE>
<CAPTION>
1996 1997
------- -------
<S> <C> <C>
Interest on the Notes.................................. $14,000 $ 4,667
Amortization of debt issuance costs on Notes........... 270 90
Elimination of interest on $75,500 of debt under Credit
Facility and effect of reduction of interest rate on
Credit Facility following repayment of Term Loan
Facility............................................. (7,412) (2,471)
Elimination of interest and amortization of associated
debt issuance costs on Term Loan Facility............ (7,120) (2,373)
------- -------
$ (262) $ (87)
======= =======
</TABLE>

(14) EBITDA is defined as net income (loss) before income taxes and minority
interest, plus the sum of depletion and depreciation and interest expense.
EBITDA is not a measure of cash flow as determined by generally accepted
accounting principles. The Company has included information concerning
EBITDA because EBITDA is a measure used by certain investors in determining
the Company's historical ability to service its indebtedness. EBITDA should
not be considered as an alternative to, or more meaningful than, net income
or cash flows as determined in accordance with generally accepted
accounting principles or as an indicator of the Company's operating
performance or liquidity.

F-7
<PAGE> 70

INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
Magnum Hunter Resources, Inc.

We have audited the accompanying consolidated balance sheet of Magnum
Hunter Resources, Inc. (formerly Magnum Petroleum, Inc.) and Subsidiaries as of
December 31, 1995, and the related consolidated statements of operations, cash
flows, and stockholders' equity for the year then ended. 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 audit.

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

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Magnum Hunter Resources,
Inc. and Subsidiaries as of December 31, 1995, and the results of their
operations and their cash flows for the year then ended, in conformity with
generally accepted accounting principles.

As discussed in Note 2 to the financial statements, the Company changed its
method of accounting for oil and gas producing operations from the successful
efforts method to the full cost method.

HEIN + ASSOCIATES LLP

Dallas, Texas
April 3, 1996

F-8
<PAGE> 71

INDEPENDENT AUDITORS' REPORT

Board of Directors and Stockholders
Magnum Hunter Resources, Inc.

We have audited the accompanying consolidated balance sheet of Magnum
Hunter Resources, Inc. and Subsidiaries as of December 31, 1996, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the year then ended. 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 audit.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Magnum Hunter Resources,
Inc. and Subsidiaries as of December 31, 1996, and the results of their
operations and their cash flows for the year then ended, in conformity with
generally accepted accounting principles.

Deloitte & Touche LLP

Dallas, Texas
March 14, 1997 (April 30, 1997 as to Note 16)

F-9
<PAGE> 72

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)

ASSETS

<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1995 1996
------------ ------------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................. $ 1,544 $ 1,687
Securities available for sale............................. 101 233
Accounts receivable:
Trade, net of allowance of $134 and $132................ 1,247 4,372
Due from affiliates....................................... 116 241
Notes receivable from affiliate........................... 121 264
Current portion of long-term note receivable.............. 201 198
Prepaid and other......................................... 22 52
------- -------
TOTAL CURRENT ASSETS................................ 3,352 7,047
------- -------
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, full cost method:
Unproved................................................ 843 459
Proved.................................................. 36,257 70,575
Pipelines................................................. 1,087 7,102
Other property............................................ 146 381
------- -------
TOTAL PROPERTY, PLANT AND EQUIPMENT................. 38,333 78,517
Accumulated depreciation, depletion and impairment........ (1,928) (4,869)
------- -------
NET PROPERTY, PLANT AND EQUIPMENT........................... 36,405 73,648
------- -------
OTHER ASSETS
Deposits and other assets................................. 118 645
Long-term notes receivable, net of imputed interest....... 190 1,732
------- -------
TOTAL ASSETS........................................ $40,065 $83,072
======= =======

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Trade accounts payable and accrued liabilities............ $ 1,283 $ 3,698
Gas imbalance payable..................................... -- 242
Dividends payable......................................... 177 22
Suspended revenue payable................................. 794 784
Current maturities of long-term debt...................... 2,014 22
------- -------
TOTAL CURRENT LIABILITIES........................... 4,268 4,768
------- -------
LONG-TERM LIABILITIES
Long-term debt, less current maturities................... 7,598 38,744
Production payment liability.............................. 288 937
Other..................................................... 290 --
Deferred income taxes..................................... 3,125 3,469
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock -- $.001 par value; 10,000,000 shares
authorized 216,000 designated as Series A; 80,000 and
80,000 issued and outstanding, respectively, liquidation
amount $0............................................... -- --
925,000 designated as Series B; 62,050 and none issued
and outstanding, respectively.......................... -- --
625,000 designated as Series C; 625,000 and none shares
issued and outstanding, respectively................... 1 --
1,000,000 designated as 1996 Series A Convertible; none
and 1,000,000 issued and outstanding, respectively,
liquidation amount none and $10,000,000 respectively... -- 1
Common stock -- $.002 par value; 50,000,000 shares
authorized 11,598,183 shares issued and 14,252,822
issued and outstanding, respectively.................... 23 29
Additional paid-in capital................................ 29,660 40,216
Accumulated deficit....................................... (5,245) (5,142)
Unrealized gain on investments............................ 57 51
------- -------
24,496 35,155
Treasury stock (544,495 shares of common stock)........... -- (1)
------- -------
TOTAL STOCKHOLDERS' EQUITY.......................... 24,496 35,154
------- -------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.......... $40,065 $83,072
======= =======
</TABLE>

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

F-10
<PAGE> 73

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

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

<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
-------------------------
1995 1996
----------- ----------
<S> <C> <C>
OPERATING REVENUE
Oil and gas sales......................................... $ 617 $ 10,248
Gas gathering and marketing............................... -- 5,768
Oil field services and commissions........................ 32 396
----------- ----------
TOTAL OPERATING REVENUE........................... 649 16,412
----------- ----------
OPERATING COSTS AND EXPENSES
Oil and gas production.................................... 268 4,390
Gas gathering and marketing............................... -- 4,708
Costs related to other services........................... 26 267
Depreciation and depletion................................ 421 2,951
General and administrative................................ 977 1,225
----------- ----------
TOTAL OPERATING COSTS AND EXPENSES................ 1,692 13,541
----------- ----------
OPERATING PROFIT (LOSS)..................................... (1,043) 2,871
OTHER INCOME................................................ 77 344
INTEREST EXPENSE............................................ (2) (2,394)
----------- ----------
NET INCOME (LOSS) BEFORE INCOME TAXES....................... (968) 821
Provision for deferred income taxes....................... -- (312)
----------- ----------
NET INCOME (LOSS)........................................... (968) 509
DIVIDENDS APPLICABLE TO PREFERRED SHARES.................... (617) (406)
----------- ----------
INCOME (LOSS) APPLICABLE TO COMMON SHARES................... $ (1,585) $ 103
=========== ==========
INCOME (LOSS) PER COMMON SHARE.............................. $ (0.28) $ 0.01
=========== ==========
COMMON SHARES USED IN PER SHARE CALCULATION................. 5,606,669 12,485,893
=========== ==========
</TABLE>

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

F-11
<PAGE> 74

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995 AND 1996
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
DEFERRED
PREFERRED STOCK COMMON STOCK TREASURY STOCK ADDITIONAL COSTS OF
------------------ ------------------- ----------------- PAID-IN WARRANT
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT CAPITAL OFFERING
--------- ------ ---------- ------ -------- ------ ---------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1994................. 645,775 $ 1 4,537,045 $ 9 -- $ -- $12,606 $(240)
Conversion of preferred stock to common
stock.................................... (11,300) -- 28,900 --
Issuance and costs from exercise of
warrants................................. 20,750 -- 833,324 2 2,841 240
Issuance of Series C preferred stock....... 249
Issuance of common stock to acquire oil and
gas properties........................... 386,615 1 1,378
Issuance of common stock for services...... 602,222 1 1,370
Issued to directors for collateral......... 125,000 --
Sale of investment shares..................
Payments received on receivable from
stockholders.............................
Acquisition of Hunter Resources, Inc. for
Series C preferred stock and common
stock.................................... 111,825 -- 5,085,077 10 11,216
Dividends declared on preferred stock......
Net loss from operations...................
Unrealized gain on investments.............
--------- --- ---------- --- -------- ---- ------- -----
Balance at December 31, 1995................. 767,050 1 11,598,183 23 -- -- 29,660 --
Conversion of preferred stock to common
stock.................................... (658,934) (1) 1,821,638 4 (3)
Redemption of 28,116 shares of Series C
preferred stock.......................... (28,116) -- (294)
Issuance of 1996 Series A convertible
preferred stock, net of offering costs... 1,000,000 1 9,785
Shares issued as collateral, returned and
held as treasury stock................... 610,170 1 (610,170) (1) (1)
Exercise of employees' common stock
options.................................. -- -- 12,258 -- 9
Issuance of common stock to acquire oil and
gas properties........................... 188,410 1 51,300 -- 938
Sale of investment shares..................
Dividends declared on preferred stock...... 34,421 -- 2,117 -- 122
Net income from operations.................
Unrealized gain on investments.............
--------- --- ---------- --- -------- ---- ------- -----
Balance at December 31, 1996................. 1,080,000 $ 1 14,252,822 $29 (544,495) $ (1) $40,216 $ --
========= === ========== === ======== ==== ======= =====

<CAPTION>
UNREALIZED
RECEIVABLE GAIN(LOSS)
ACCUMULATED FROM ON
DEFICIT STOCKHOLDER INVESTMENTS
----------- ----------- -----------
<S> <C> <C> <C>
Balance at December 31, 1994................. $(3,659) $ (63) $ (9)
Conversion of preferred stock to common
stock....................................
Issuance and costs from exercise of
warrants.................................
Issuance of Series C preferred stock.......
Issuance of common stock to acquire oil and
gas properties...........................
Issuance of common stock for services......
Issued to directors for collateral.........
Sale of investment shares.................. 9
Payments received on receivable from
stockholders............................. 63
Acquisition of Hunter Resources, Inc. for
Series C preferred stock and common
stock....................................
Dividends declared on preferred stock...... (618)
Net loss from operations................... (968)
Unrealized gain on investments............. 57
------- ----- ----
Balance at December 31, 1995................. (5,245) -- 57
Conversion of preferred stock to common
stock....................................
Redemption of 28,116 shares of Series C
preferred stock..........................
Issuance of 1996 Series A convertible
preferred stock, net of offering costs...
Shares issued as collateral, returned and
held as treasury stock...................
Exercise of employees' common stock
options..................................
Issuance of common stock to acquire oil and
gas properties...........................
Sale of investment shares.................. (57)
Dividends declared on preferred stock...... (406)
Net income from operations................. 509
Unrealized gain on investments............. 51
------- ----- ----
Balance at December 31, 1996................. $(5,142) $ -- $ 51
======= ===== ====
</TABLE>

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

F-12
<PAGE> 75

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)

<TABLE>
<CAPTION>
FOR THE YEARS ENDED
DECEMBER 31,
-------------------
1995 1996
-------- --------
<S> <C> <C>
CASH FLOW FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ (968) $ 509
Adjustments to reconcile net income (loss) to cash
provided by (used for)
operating activities:
Depreciation and depletion............................. 421 2,951
Deferred income taxes.................................. -- 312
Common stock issued for services....................... 102 --
(Gain) loss on sale of assets.......................... 76 (143)
Interest accrued on notes receivable from
stockholders.......................................... -- --
Other.................................................. 15 32
Changes in certain assets and liabilities:
Accounts receivable.................................. (37) (3,250)
Costs in excess of billings on uncompleted drilling
contracts........................................... 55 --
Deposits and other assets............................ -- (30)
Accounts payable and accrued liabilities............. (513) 2,647
------- -------
Net Cash Provided By (Used By) Operating
Activities....................................... (849) 3,028
------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of assets.............................. 88 318
Additions to property and equipment....................... (1,244) (41,471)
Increase in deposits and other assets..................... -- (527)
Loan made for promissory note receivable.................. (121) (58)
Payments received on promissory notes receivable.......... 334 --
Purchase of securities available for sale................. (30) --
Obligations and property acquisitions funded in Hunter
acquisition............................................ (1,034) --
------- -------
Net Cash Used By Investing Activities............. (2,007) (41,738)
------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt and production
payment................................................ -- 57,262
Payments of principal on long-term debt and production
payment................................................ (186) (27,459)
Payments on other liabilities............................. -- (290)
Proceeds from issuance of common and preferred stock, net
offering costs......................................... 3,332 9,796
Redemption of preferred stock............................. -- (295)
Payments received on notes receivable..................... 62 277
Increase in segregated funds for payments of notes
payable................................................ 130 --
Dividends paid............................................ (583) (438)
------- -------
Net Cash Provided By Financing Activities......... 2,755 38,853
------- -------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS...................................... (101) 143
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............ 1,645 1,544
------- -------
CASH AND CASH EQUIVALENTS AT END OF PERIOD.................. $ 1,544 $ 1,687
======= =======
</TABLE>

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

F-13
<PAGE> 76

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

ORGANIZATION AND NATURE OF OPERATIONS

Magnum Hunter Resources, Inc. (the "Company"), formerly Magnum Petroleum,
Inc., is incorporated under the laws of the state of Nevada. The Company is
engaged in the acquisition, operation and development of oil and gas properties,
the gathering, transmission and marketing of gas, providing management and
advisory consulting services on oil and gas properties for third parties, and
providing consulting and U.S. export services to facilitate Latin American trade
in energy products. In conjunction with the above activities, the Company owns
and operates oil and gas properties in six states, predominantly in the
Southwest region of the United States. In addition, the Company owns and
operates four gathering systems located in Texas, Louisiana and Oklahoma.

MERGER AND CONSOLIDATION

The accompanying consolidated financial statements include the accounts of
the Company and its existing wholly-owned subsidiaries, Gruy Petroleum
Management Company, Hunter Gas Gathering, Inc., Inesco Corporation, Magnum
Hunter Production, Inc., Midland Hunter Petroleum Limited Liability Company, and
SPL Gas Marketing, Inc. and its 51% owned subsidiary, Hunter Butcher
International Limited Liability Company. As more fully discussed in Note 3, the
Company entered into an amended definitive agreement on December 19, 1995 to
acquire all of the assets, subject to the existing liabilities, of Hunter
Resources, Inc. ("Hunter"). The purchase was accounted for by the purchase
method effective December 31, 1995. As such, the accompanying consolidated
financial statements for 1995 include the balance sheet accounts of Hunter.
However, the Statement of Operations for 1995 does not include the operations of
Hunter for that fiscal year. All significant intercompany accounts and
transactions have been eliminated in consolidation. Certain reclassifications
have been made to the consolidated financial statements of the prior year to
conform with the current presentation.

CASH AND CASH EQUIVALENTS

The Company considers all highly liquid debt instruments purchased with a
maturity of three months or less to be cash equivalents. The Company has cash
deposits in excess of federally insured limits.

INVESTMENTS

In 1994, the Company adopted Statement of Financial Accounting Standards
No. 115, Accounting for Certain Investments in Debt and Equity Securities. Under
this standard, the equity securities held by the Company that have readily
determinable fair values are classified as current assets available-for-sale and
are measured at fair value. Unrealized gains and losses for these investments
are reported as a separate component of stockholders' equity.

At December 31, 1995, the Company's available for sale securities had an
amortized cost basis of $44,440, gross unrealized gains reported in equity of
$57,200 and fair market value of $101,640. During 1995, securities were sold for
gross proceeds of $73,083 and the Company realized a gain of $19,370.

At December 31, 1996, the Company's available for sale securities had an
amortized cost basis of $150,000, gross unrealized gains reported in equity of
$51,150 and a fair market value of $232,500. During 1996, securities were sold
for gross proceeds of $187,312 and the Company realized a gain of $142,872.

F-14
<PAGE> 77

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SUSPENDED REVENUES

Suspended revenue interests represent oil and gas sales payable to third
parties largely on properties operated by the Company. The Company distributes
such amounts to third parties upon receipt of signed division orders or
resolution of other legal matters.

OIL AND GAS PRODUCING OPERATIONS

The Company follows the full-cost method of accounting for oil and gas
properties, as prescribed by the Securities and Exchange Commission ("SEC").
Accordingly, all costs associated with acquisition, exploration and development
of oil and gas reserves, including directly related overhead costs, are
capitalized.

All capitalized costs of oil and gas properties, including the estimated
future costs to develop proved reserves, are amortized on the unit-of-production
method using estimates of proved reserves. Cost directly associated with the
acquisition and evaluation of unproved properties are excluded from the
amortization base until the related properties are evaluated. Such unproved
properties are assessed periodically and any provision for impairment is
transferred to the full-cost amortization base. Sales of oil and gas properties
are credited to the full-cost pool unless the sale would have a significant
effect on the amortization rate. Abandonments of properties are accounted for as
adjustments to capitalized costs with no loss recognized. The Company's unproved
properties excluded from the amortization base were $843,000 and $459,000 at
December 31, 1995 and 1996, respectively. The remaining costs associated with
unproved properties were expended in 1995 and are expected to be evaluated and
transferred into the amortization base over the next twelve months.

The net capitalized costs are subject to a "ceiling test," which generally
limits such costs to the aggregate of the estimated present value of future net
revenues from proved reserves discounted at ten percent based on current
economic and operating conditions.

DRILLING OPERATIONS

Fees from fixed-price contracts with other working interest owners to
drill, complete and place oil and gas wells into production, less related costs,
are accounted for as adjustments to oil and gas properties.

PIPELINES

Pipelines are carried at cost. Depreciation is provided using the
straight-line method over an estimated useful life of 15 years. Gain or loss on
retirement or sale or other disposition of assets is included in results of
operations in the period of disposition.

OTHER PROPERTY

Other property and equipment are carried at cost. Depreciation is provided
using the straight-line method over estimated useful lives ranging from five to
ten years. Gain or loss on retirement or sale or other disposition of assets is
included in results of operations in the period of disposition.

OTHER OIL AND GAS RELATED SERVICES

Other oil and gas related services consist largely of fees earned from the
Company's salt water disposal facility. Such fees are recognized in the month
the disposal service is provided.

IMPACT OF RECENTLY ISSUED PRONOUNCEMENTS

The Financial Accounting Standards Board has issued Statement No. 121,
("SFAS No. 121") "Accounting for Impairments of Long-Lived Assets and Assets to
be Disposed of", and Statement No. 123, "Accounting For Stock-Based
Compensation" ("SFAS No. 123"). The Company adopted the provisions of

F-15
<PAGE> 78

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SFAS No.121 in 1996 but it did not have any effect on the Company's consolidated
financial statements, and it adopted the disclosures only portion of SFAS No.123
as it continued to follow the provisions of APB No. 25 which is the intrinsic
value method of accounting for stock-based compensation. See Note 15 which
follows for the effect of stock based compensation on a pro forma basis.

INCOME TAXES

The Company files a consolidated federal income tax return. Income taxes
are provided for the tax effects of transactions reported in the financial
statements and consist of taxes currently due, if any, plus net deferred taxes
related primarily to differences between the basis of assets and liabilities for
financial and income tax reporting. Deferred tax assets and liabilities
represent the future tax return consequences of those differences, which will
either be taxable or deductible when the assets and liabilities are recovered or
settled. Deferred tax assets include recognition of operating losses that are
available to offset future taxable income and tax credits that are available to
offset future income taxes. Valuation allowances are recognized to limit
recognition of deferred tax assets where appropriate. Such allowances may be
reversed when circumstances provide evidence that the deferred tax assets will
more likely than not be realized.

INCOME OR LOSS PER COMMON SHARE

Income or loss per common share is based on the weighted average number of
shares of common stock outstanding. Convertible securities and warrants were
anti-dilutive at December 31, 1995 and 1996 and were not included in the
calculation of income or loss per common share.

DEFERRED COST OF WARRANT EXERCISE OFFERING

The Company incurred costs to update its registration statement relating to
Series C preferred stock that is convertible into common stock and relating to
common stock purchase warrants. The Company made an offer to the warrant holders
allowing them to exercise their warrants at a discount through February 16,
1995. As presented in Note 9, certain of the common stock purchase warrants were
exercised prior to the expiration of the discount period. The Company had
deferred direct costs as of December 31, 1994 of $240,281 related to the
discounted warrant exercise offering. Such costs and $250,488 incurred in 1995
were offset against the proceeds received in 1995 from the exercise of the
warrants. There were no warrants exercised during 1996.

USE OF ESTIMATES AND CERTAIN SIGNIFICANT ESTIMATES

The preparation of the Company's financial statements in conformity with
generally accepted accounting principles requires the Company's management to
make estimates and assumptions that affect the amounts reported in these
financial statements and accompanying notes. Actual results could differ from
those estimates. Significant assumptions are required in the valuation of proved
oil and gas reserves, which as described above may affect the amount at which
oil and gas properties are recorded. It is at least reasonably possible those
estimates could be revised in the near term and those revisions could be
material.

NOTE 2 -- CHANGE IN ACCOUNTING METHOD

The Company accounted for its oil and gas producing activities using the
successful efforts method from inception through June 30, 1995. However, the
full cost method has subsequently been adopted. The Company is of the opinion
that the full cost method of accounting is preferable to the successful efforts
method of accounting for its oil and gas activities for the following reasons:

(1) The Company recently acquired the subsidiaries of Hunter (See note
3),which comprise corporations engaged in oil and gas related activities
and which utilize the full cost method of accounting for these activities.
For both legal and accounting purposes, the Company is the acquiring
entity;

F-16
<PAGE> 79

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

however, the subsidiaries are increasing their oil and gas activities and
have more proved oil and gas reserves than the Company. Furthermore,
management of Hunter became the management of the Company upon completion
of the acquisition. One of the Hunter subsidiaries specializes in the
management of oil and gas properties and all accounting functions and
financial reporting have been undertaken by the subsidiary's personnel. The
individuals employed by the subsidiaries have comprised the vast majority
of the Company's employees and the Company believes that by allowing these
employees and Hunter's management to continue to use the full cost method,
it would greatly benefit in accurately reporting on its oil and gas
operations.

(2) The subsidiaries have established relationships with lending
sources which the Company intends to continue to utilize and expand upon.
These sources are accustomed to evaluating the subsidiaries' financial
statements on the full cost method of accounting. The Company intends to
request additional borrowing arrangements from these lenders and believes
that it is desirable for these lending sources to review financial
statements prepared on a consistent basis.

The accompanying financial statements have been restated to apply the full
cost method retroactively. This change in accounting principle has no
significant effect on income taxes. The effect of the accounting change in
accumulated deficit as previously reported for 1995 is:

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1995
------------
<S> <C>
STATEMENT OF ACCUMULATED DEFICIT:
Balance at Beginning of Period as Previously Reported....... $(4,166,058)
Add Adjustment for the Cumulative Effect on Prior Years of
Applying Retroactively the Full Cost Method............... 506,651
-----------
Balance at Beginning of Period, as Adjusted................. (3,659,407)
Net Loss.................................................... (968,272)
Preferred Dividends......................................... (617,220)
-----------
Balance at End of Year...................................... $(5,244,899)
===========
</TABLE>

The effect on 1995 operations of changing the accounting method was to
increase net loss and net loss per share by $307,000 and $.05, respectively.

NOTE 3 -- ACQUISITIONS AND DISPOSITIONS

During March 1995, the Company acquired an additional fifty percent (50%)
working interest (for a total of 100% working interest) in a proved undeveloped
oil and gas property on which one well is located. The acquisition cost of this
additional interest was $410,000, of which $130,000 was paid in cash and 80,000
shares of the Company's restricted common stock, valued at $3.50 per share, were
issued. During April 1995, the Company also acquired an additional 40 percent
(40%) working interest (for a total of ninety percent (90%) working interest) in
a proved undeveloped property on which one well is located. The acquisition cost
of this additional interest was $480,000, of which $20,000 was paid in cash and
125,000 shares of the Company's restricted common stock were issued, valued at
$3.50 per share, and the transfer of securities held by the Company as an
investment in equity securities at December 31, 1994.

In October 1995, the Company issued 85,131 shares of restricted common
stock, valued at $3.52 per share, in an acquisition completed by a Hunter
subsidiary for the remaining stock ownership interest in a limited liability
company. Also, in October 1995, the Company issued 64,176 shares of restricted
common stock, valued at $4.00 per share, in an acquisition of oil and gas
properties completed by a Hunter subsidiary.

F-17
<PAGE> 80

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In December 1995, the Company issued 32,308 shares of restricted common stock,
valued at $3.25 per share, in an acquisition of a proven undeveloped property by
a Hunter subsidiary.

The Company executed a definitive agreement on July 21, 1995 to acquire all
of the assets, subject to the existing liabilities of Hunter Resources, Inc.
("Hunter"). Pursuant to the agreement, the Company issued, subject to
shareholder approval, 2,750,000 shares of its restricted common stock to Hunter
in exchange for the assets acquired. In addition, 575,000 shares of restricted
common stock were issued to a third party as an additional cost of the
acquisition. The third party distributed a total of 250,000 of the shares to a
former director and a former officer of the Company for their assistance in
completing the acquisition.

On December 19, 1995 to be effective December 22, 1995, the Company and
Hunter entered into an amended agreement. Under the terms of the amendment,
which was executed by Hunter shareholders representing over fifty percent (50%)
of the common stock of Hunter, an additional 2,335,077 shares of restricted
common stock and 111,825 shares of Series C preferred stock were issued to
Hunter. The acquisition was recorded under the "purchase method" of accounting,
based upon the estimated value of the shares issued of $12,495,005. The
operations of Hunter have been consolidated with those of the Company beginning
on December 31, 1995.

On June 28, 1996, the Company purchased 469 gas wells and approximately 427
miles of a gas gathering pipeline system for a net purchase price of
$34,652,395. The properties are located in the Panhandle of Texas and Western
Oklahoma and are referred to as the "Panoma Properties." As the purchase was not
completed until the end of the second quarter of 1996, the consolidated
financial statements for 1996 include the operating results of the Panoma
Properties for only the last six months of the year.

On November 4, 1996, the Company entered into an agreement to sell certain
oil and gas properties for $1,850,000, including $150,000 of restricted
securities of an American Stock Exchange listed company and a $1,700,000
promissory note payable out of 100% of the net oil and gas income of the
properties. The agreement calls for the Company's subsidiary to continue to
operate the properties for a monthly management fee.

The following summary, prepared on a pro forma basis, presents the results
of operations for the years ended December 31, 1995 and 1996, as if the
acquisitions occurred as of the beginning of the respective years. The pro forma
information includes the effects of adjustments for increased general and
administrative expense, interest expense, depreciation, depletion and income
taxes:

<TABLE>
<CAPTION>
1995 1996
----------- -----------
(UNAUDITED)
<S> <C> <C>
Revenue................................................... $12,515,000 $20,653,000
Net Income (Loss) Applicable to Common Stock.............. (4,403,000) (304,000)
Net Income (Loss) Per Common Share........................ $ (.79) $ (.02)
Average shares outstanding................................ 5,606,669 12,485,893
</TABLE>

NOTE 4 -- NOTES RECEIVABLE

During July of 1994, the Company received an interest bearing note due on
May 1, 1995, in exchange for $319,206 paid by the Company. Interest in the
amount of $3,000 per month accrued through February 28, 1995 and was paid in
March 1995. For the remaining two months, interest in the amount of $4,500 per
month was accrued which, along with the principal amount, was paid during May
1995. The note was collateralized by securities, the fair market value of which
was less than the amount of the note.

On July 28, 1995, the Company received a non-interest bearing note
receivable in the amount of $223,500 in exchange for its interest in an oil and
gas property. Interest at 10 percent was imputed on the note

F-18
<PAGE> 81

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

resulting in a discount of $28,366. The note provides for payments of $7,000 per
month which were received timely in 1996. As of December 31, 1996, the unpaid
balance, net of discount, is $112,288.

On November 4, 1996, the Company received an interest bearing note due on
November 1, 1999, in exchange for its interest in oil and gas properties.
Interest is at the rate of 12% per annum. The note is collateralized by stock in
an American Stock Exchange listed company and the oil and gas properties sold.
As of December 31, 1996, the unpaid balance was $1,627,534.

NOTE 5 -- RELATED PARTY TRANSACTIONS

In conjunction with the acquisition of Hunter, the Company assumed a note
receivable with a balance of $120,758 and $178,527 at December 31, 1995 and
1996, respectively, from an owner in an affiliated limited liability company.
The note provides for interest at ten percent and has a due date of January 31,
1997.

In connection with the acquisition of Hunter, the Company assumed a note
receivable from a company affiliated with the President of the Company in the
amount of $54,615 at December 31, 1995 and 1996. This note bears interest at ten
percent and is due on demand. Additionally, trade accounts receivable from this
affiliated company were $51,346 and $30,761 at December 31, 1995 and 1996,
respectively.

In connection with the acquisition of Hunter, the Company assumed unsecured
accounts receivable from the President personally in the amount of $10,000 as of
December 31, 1995, which amount has been subsequently repaid.

A company owned by two former directors of the Company previously operated
several of the wells in which the Company owned an interest. Operating fees paid
this company were $35,519 in 1995. The operations of these wells were
transferred to a subsidiary of Hunter during 1995. In addition, the related
company received a commission of $25,000 from the sale of an oil and gas
property to the Company in 1995.

During 1996, as part of the Company's overall compensation package, the
Company's officers and directors were granted the right to participate in
certain development and exploration projects of the Company on a promoted basis.

As of December 31, 1996, eleven (11) of the Company's officers and
directors as a group spent an aggregate of $137,340 participating in 6 wells.
The Company discontinued this program as of January 1, 1997.

F-19
<PAGE> 82

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 6 -- LONG-TERM DEBT

Long-term debt at December 31, 1995 and 1996 consisted of the following:

<TABLE>
<CAPTION>
1995 1996
---------- -----------
<S> <C> <C>
BANKS
Revolving promissory note, collateralized by pipeline and
oil and gas properties, due June 30, 2001, interest at
LIBOR + 2.25% (total of 7.625% at December 31,
1996)(1)................................................. $ -- $38,700,000
Promissory note, collateralized by pipelines and oil and
gas properties, payable in monthly installments for 1996
of $174,000 through October 1, 1996, then $171,000
thereafter plus interest at prime plus one percent (total
of 9.75% at December 31, 1995), assumed in Hunter
acquisition(2)........................................... 9,555,000 --
Note payable, payable in monthly installments of $498
through July 1996 plus interest at 7.25 percent,
collateralized by truck.................................. 3,000 --
Note payable to bank collateralized by vehicle payable in
monthly installments of $1,031 including interest at 8.5%
through February 1999.................................... -- 24,000
OTHER
Notes payable, non-interest bearing and uncollateralized,
payable in monthly installments of $1,000 through July 1,
2000, assumed in Hunter acquisition...................... 54,000 42,000
---------- -----------
Total Long-Term Debt............................. 9,612,000 38,766,000
Less Current Portion........................ 2,014,000 22,000
---------- -----------
Long-Term Debt................................... $7,598,000 $38,744,000
========== ===========
</TABLE>

Maturities of long-term debt based on contractual requirements for the
years ending December 31, are as follows:

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

(1) The revolving promissory note to the banks is a borrowing under a
$100,000,000 line of credit on which there existed a borrowing base of
$55,000,000 at December 31, 1996. The level of the borrowing base is
dependent on the valuation of the assets pledged, primarily oil and gas
reserve values. The line of credit includes covenants, the most restrictive
of which require maintenance of a current ratio, interest coverage ratio,
and tangible net worth, as specified in the loan agreement. The bank group
must approve all dividends paid on common stock.

(2) The promissory note to bank was a borrowing under a $20,000,000 line of
credit on which there existed a borrowing base of approximately $8.7 million
at December 31, 1995. The balance at December 31, 1995 included $1,125,000
due to the seller of certain oil and gas properties which was refinanced in
February,

F-20
<PAGE> 83

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

1996 under the line of credit. The final principal payments under the line
of credit were due June 1, 2000. The amount that could be borrowed under the
line of credit was based upon a designated percentage of oil and gas reserve
values. The line of credit included covenants, the most restrictive of which
require maintenance of a current ratio and tangible net worth, as
specifically defined in the loan agreement.

NOTE 7 -- PRODUCTION PAYMENT LIABILITY

As a result of the merger with Hunter in 1995, the Company assumed an
obligation under a production payment conveyance. The conveyance provides for a
royalty payment equal to 50% of the monthly net revenue proceeds received by the
Company in certain oil and gas properties. The balance owed under the conveyance
bears interest at 15% per annum and is non-recourse to the Company. The balance
owed under this conveyance was $288,000 and $210,000 at December 31, 1995 and
1996, respectively.

In November, 1996, the Company entered into a second production payment
conveyance with the same party. The Company received a production payment amount
of $750,000 and agreed to make royalty payments of up to 50% of the monthly net
revenue proceeds received from certain oil and gas properties. The balance owed
under the conveyance was $726,000 at December 31, 1996. The production payment
bears interest at the rate of 13.5% per annum and is non-recourse to the
Company.

NOTE 8 -- INCOME TAXES

The Company accounts for income taxes in accordance with Statement of
Financial Accounting Standards No. 109, Accounting for Income Taxes, which
requires the recognition of a liability or asset, net of a valuation allowance,
for the deferred tax consequences of all temporary differences between the tax
bases and the reported amounts of assets and liabilities, and for the future
benefit of operating loss carryforwards. The following is a reconciliation of
income tax expense reported in the statement of operations:

<TABLE>
<CAPTION>
1996
--------
<S> <C>
Tax expense at statutory rates.............................. $279,000
State taxes................................................. 24,000
Other....................................................... 9,000
--------
Total............................................. $312,000
========
</TABLE>

The tax effects of significant temporary differences and carryforwards are
as follows:

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1995 1996
----------- -----------
<S> <C> <C>
Property and equipment, including intangible drilling
costs................................................... $(5,890,000) $(6,381,000)
Annualized gain on investment............................. -- (32,000)
----------- -----------
Total deferred tax liability.............................. (5,890,000) (6,413,000)
----------- -----------
Allowance for doubtful accounts........................... 50,000 49,000
Depletion carryforwards................................... 365,000 361,000
Operating loss carryforwards.............................. 2,350,000 2,534,000
----------- -----------
Total deferred tax assets....................... 2,765,000 2,944,000
----------- -----------
Valuation allowance....................................... -- --
----------- -----------
Net Deferred Tax Liability...................... $(3,125,000) $(3,469,000)
=========== ===========
</TABLE>

The Company and its subsidiaries have net operating loss carryforwards
(NOL) of approximately $6,900,000 that expire, if unused, in years through 2011,
none in 1997. Approximately $1,700,000 of the NOL

F-21
<PAGE> 84

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

carries a limitation of approximately $200,000 per year. In addition, the
Company has depletion carryforwards of approximately $1,000,000.

NOTE 9 -- STOCKHOLDERS' EQUITY

Shares of preferred stock may be issued in such series, with such
designations, preferences, stated values, rights, qualifications or limitations
as determined solely by the Board of Directors. Of the 10,000,000 shares of
$.001 par value preferred stock the Company is authorized to issue, 216,000
shares have been designated as Series A Preferred Stock, 925,000 shares have
been designated as Series B Preferred Stock, 625,000 shares have been designated
as Series C Preferred Stock and 1,000,000 shares have been designated as 1996
Series A Convertible Preferred Stock. Thus, 7,234,000 preferred shares have been
authorized for issuance but have not been issued nor have the rights of these
preferred shares been designated. No dividends can be paid on the common stock
until the dividend requirements of the preferred shares have been satisfied.

Holders of the Series A Preferred Stock are entitled to receive dividends
only to the extent that funds are available from the West Dilley Prospect. Such
dividends are limited to $7.50 per share, in the aggregate. Dividend payments to
Series A preferred shareholders will be based on fifty percent (50%) of the net
operating revenue received by the working interest owners of the West Dilley
Prospect. Due to a decline in production from the well located on this prospect,
the Company has shut this well in and is no longer producing the property. The
Series A dividends are not cumulative except for unpaid amounts due from this
calculation. No dividends have been paid on the Series A preferred stock. There
is no aggregate annual dividend requirement for the Series A preferred stock.

The Series B Preferred Stock was issued as a unit, comprised of 1,000
shares of Series B Preferred Stock and two production certificates. The Series B
preferred stockholders are entitled to receive cumulative dividends of $0.35
annually per share, payable quarterly. The holders of the units are entitled to
receive $10,000 per unit in dividends and in production payments. The production
payments were derived from 50% of the Company's net revenue from production of
oil and gas. The Board of Directors declared dividends on the Series B preferred
stock of $25,172 and $21,893 for the years ended December 31, 1994 and 1995,
respectively. Beginning June 15, 1994, the Company offered to exchange (the
"Exchange Offer") 1,250 shares of common stock for each Series B production
certificate. During 1994, 141.1 production certificates were exchanged for
176,375 shares of common stock and the Series B preferred shareholders agreed to
convert their Series B preferred shares into common stock at December 31, 1995
if all dividends were paid through that date. All of the shares were converted
to common stock during 1996.

Separate and apart from the Exchange Offer, two of the Company's officers
and directors (the "Officers") set aside 125,000 shares (the "Stock") of their
own common stock of the Company for a single individual (the "Individual") who
owned approximately 55% of the Series B production certificates that were
exchanged. The Stock was being held by an independent party to this transaction
until fair market value of the Exchange Shares, when the Exchange Shares become
eligible for sale pursuant to Rule 144 of the Securities Act of 1933, is
determined. The Company issued 125,000 shares of its common stock to the
Officers in exchange for their assignment to the Company of all of the Officers'
rights, title and interest in the Stock. The Company has recorded the new shares
issued at par value. The value of the exchange shares was determined in 1996,
and the Company issued 5,000 shares of its common stock to the Individual.
Subsequent to year-end, the 125,000 shares being held were returned to the
Company and are being held as treasury stock.

The Series C preferred stock was convertible at the option of the holder at
any time into three shares of common stock and, after November 12, 1994, would
automatically convert into common stock any time the closing bid price of the
common stock equals or exceeds $5.00 per share for twenty consecutive trading
days. The Series C preferred stock was redeemable by the Company beginning
November 12, 1995, at $10.50 per share plus accrued and unpaid dividends. If
declared by the Board of Directors, dividends accrue at the annual rate of $1.10
per share, are cumulative from the date of first issuance and are paid quarterly
in arrears. The

F-22
<PAGE> 85

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Board of Directors declared dividends on the Series C preferred stock of
$595,327 and $339,827 for the years ended December 31, 1995 and 1996,
respectively. The aggregate annual dividend requirements for the 625,000 shares
of Series C preferred stock outstanding at December 31, 1995 and 1996 amounts to
$687,500 and none, respectively. As of December 31, 1996, all Series C preferred
stock had been redeemed or converted to common stock.

On December 6, 1996, the Company entered into an agreement to issue
1,000,000 shares of new Series A preferred stock, known as the 1996 Series A
Convertible Preferred Stock, in a private placement. The shares have a stated
and liquidation value of $10 per share and pay a fixed annual cumulative
dividend of eight and three quarters percent (8.75%) payable quarterly in
arrears beginning December 31, 1996. The shares are convertible into shares of
common stock at a conversion price of $5.875 per share. Beginning in December
1998, the Company has an option to exchange the stock into convertible
subordinated debentures of equivalent value. The purpose of the private
placement was to fund the capital cost necessary to drill certain development
projects and to fund the capital costs of several West Texas waterflood
projects. Proceeds from the offering were initially used to reduce the Company's
existing bank indebtedness. Certain capital expenditure requirements for
developmental drilling and waterflood projects are required under the agreement
whereby this stock was issued. In addition, under the terms of the preferred
stock, the Company is required to raise an aggregate of $15 million of
additional equity by March 31, 1998 or the Company is required to redeem on June
30 of each of the years 2006, 2007, and 2008, 333,333 shares of preferred stock.
On December 23, 1996, the 1996 Series A Convertible Preferred Stock was issued,
resulting in net proceeds to the Company after offering costs of $9,787,000.
Dividends of $22,000 were declared in 1996 and paid subsequent to year end.

The preferred shareholders are not entitled to vote except on those matters
in which the consent of the holders of preferred stock is specifically required
by Nevada law. If the Company were to liquidate prior to payment of the full
dividend requirements on the preferred stock, the preferred stock would receive
a liquidation preference from the liquidation proceeds. The Series A preferred
shareholders would receive an amount equal to the lesser of the proceeds from
the liquidation of the West Dilley Prospect or the remaining unpaid dividend.
The 1996 Series A Convertible Preferred Stock would receive an amount of $10 per
share. On liquidation, holders of all series of the preferred stock would be
entitled to receive the par value, $.001 per share, in preference to the common
stock shareholders.

The Series C preferred stock was originally issued as a unit comprised of
one share of Series C preferred stock and warrants to purchase three (3) shares
of common stock. A total of 1,687,500 warrants were issued and are exercisable
at $5.50 per share through November 12, 1998. The Company offered the holders of
the warrants a discount period commencing November 15, 1994 and ending February
16, 1995 during which time the warrants could be exercised at $4.00. During this
time, warrants were exercised for 833,324 shares of common stock. The exercise
of these warrants resulted in cash proceeds of $3,333,298 to the Company. The
warrants are redeemable by the Company at $0.02 per warrant upon 30 day notice
at any time after November 12, 1995 or earlier if the closing bid price of the
common stock equals or exceeds $6.75 for five consecutive trading days. At
December 31, 1995, 854,176 of the warrants remained outstanding.

The Company granted an unrelated company the right to acquire 100,000
shares of common stock under the terms of a consulting agreement. The rights
became exercisable at the rate of 3,325 shares in November 1994, 8,335 shares
per month from December 1994 through October 1995 and 4,990 shares in November
1995. The rights are exercisable at $4.125 per share. The rights expire in June
1997.

In October 1995, in connection with an acquisition of oil and gas
properties, the Company issued 25,000 warrants with an exercise price of $4.00
per share, and 25,000 warrants with an exercise price of $4.50 per share with
each such warrant expiring in October 1997. In December 1995 the Company issued
37,500 warrants at an exercise price of $3.00 per share to an unaffiliated third
party for services rendered. The warrants expire in December 1997.

F-23
<PAGE> 86

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

During 1995, 20,750 representatives' warrants were exercised at $12.00 per
warrant resulting in $249,000 of proceeds to the Company. Each warrant entitles
the holder to receive one share of Series C preferred stock and three (3) common
stock warrants exercisable at $4.00 per share through February 1995 and $5.50
thereafter. 9,300 shares of Series C preferred stock and 2,000 shares of Series
B preferred stock have also been converted into 28,900 shares of common stock.
The Company issued 5,000 shares of common stock, valued at $3.50 per share to
its directors, which resulted in $17,500 of compensation expense in 1995. Also,
22,222 shares of common stock with a value of $3.80 per share were issued for
services rendered in 1995.

In January, 1996, 60,000 warrants were issued at an exercise price of
$3.375 per share and expiring in January 1999. At December 31, 1996, 45,000 of
these warrants had been earned. In connection with the receipt of a production
payment, in October 1996 the Company issued 25,000 warrants with an exercise
price of $5.18 expiring October 1999, 25,000 warrants with an exercise price of
$5.65 expiring October 2000 and 25,000 warrants with an exercise price of $6.13
expiring October 2001. No warrants were exercised in 1996.

At December 31, 1996, the Company had 1,176,676 total warrants issued,
including the publicly traded warrants. Additionally, in 1996, 610,170 shares of
the Company's common stock that had been held as collateral were returned and
held in the treasury, 12,258 shares of common stock were issued upon exercise of
employees' stock options, 239,710 shares of common stock, valued at $939,000,
were issued to acquire oil and gas properties, and 36,538 shares of common stock
were issued as dividends on the Company's Series C Preferred Stock.

NOTE 10 -- SUPPLEMENTAL CASH FLOW INFORMATION

During 1995, as more fully described in Note 3, the Company issued common
stock and preferred stock valued at $12,495,005 in the acquisition of the assets
from Hunter Resources, Inc. Oil and gas properties were acquired by issuing
$1,379,204 of common stock and $22,220 of marketable securities; preferred stock
was converted to common stock; and common stock was issued, creating a
receivable from a shareholder of $250. In addition $17,500 of common stock was
issued as compensation to directors and $84,444 of common stock was issued for
services rendered in 1995.

During 1996, the Company purchased oil and gas properties by issuing
239,710 shares of its common stock, valued at $938,444. The Company converted
658,934 shares of Series B and Series C preferred stock into 1,821,638 shares of
common stock. 36,538 shares of common stock valued at $121,700 were issued in
lieu of cash dividends on preferred stock. The Company received equity
securities with a fair value of $150,000 as partial payment for the sale of
property interests. Interest paid in 1996 was $2,344,308.

NOTE 11 -- ENVIRONMENTAL ISSUES

Being engaged in the oil and gas exploration and development business, the
Company may become subject to certain liabilities as they relate to
environmental clean up of well sites or other environmental restoration
procedures as they relate to the drilling of oil and gas wells and the operation
thereof. In the Company's acquisition of existing or previously drilled well
bores, the Company may not be aware of what environmental safeguards were taken
at the time such wells were drilled or during the time that such wells were
operated. Should it be determined that a liability exists with respect to any
environmental clean up or restoration, the liability to cure such a violation
would most likely fall upon the Company. In certain acquisitions, the Company
has received contractual warranties that no such violations exist, while in
other acquisitions the Company has waived its rights to pursue a claim for such
violations from the selling party. No claim has been made nor has a claim been
asserted, nor is the Company aware of the existence of any material liability
which the Company may have, as it relates to any environmental clean up,
restoration or the violation of any rules or regulations relating thereto.

F-24
<PAGE> 87

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

NOTE 12 -- COMMITMENTS AND CONTINGENCIES

The Company assumed in the Hunter acquisition lease agreements for the use
of office space and office equipment. The office space lease extends through
November 2001 with an option to renew the lease for a three year term. The
various office equipment leases extend until 1999. The leases have been
classified as operating leases. The following is a schedule by years of future
minimum lease payments required under the operating lease agreements:

<TABLE>
<S> <C>
Year Ended December 31:
1997...................................................... $183,046
1998...................................................... 173,168
1999...................................................... 169,815
2000...................................................... 173,711
2001...................................................... 159,235
Thereafter................................................ 0
--------
Total Minimum Payments Required................... $858,975
========
</TABLE>

Rental expense was $61,191 and $129,169 for 1995 and 1996, respectively.

At December 31, 1996, the Company is involved in litigation proceedings
arising in the normal course of business. The Company has accrued $87,750 as of
December 31, 1996 for potential expenses to be incurred in settlement of the
litigation. In the opinion of management, any additional liabilities resulting
from such litigation would not have a material effect on the Company's financial
condition, cash flows or results of operations.

NOTE 13 -- FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISK

Financial instruments that subject the Company to credit risk consist
principally of accounts and notes receivable. The receivables are primarily from
companies in the oil and gas business or from individual oil and gas investors.
These parties are primarily located in the Southwestern regions of the United
States. No single receivable is considered to be sufficiently material as to
constitute a concentration. The Company does not ordinarily require collateral,
but in the case of receivables for joint operations, the Company often has the
ability to offset amounts due against the participant's share of production from
the related property. The Company believes the allowance for doubtful accounts
at December 31, 1995 and 1996 is adequate.

Management estimates the market values of notes receivable and payable
based on expected cash flows and believes those market values approximate
carrying values at December 31, 1995 and 1996. The market values of equity
investments are based upon quoted prices (see Note 1).

NOTE 14 -- COMMODITY DERIVATIVES AND HEDGING ACTIVITIES

Periodically, the Company enters into futures, options, and swap contracts
to reduce the effects of fluctuations in crude oil and gas prices. At December
31, 1996, the Company had open contracts for oil price collars on 12,000 barrels
of oil per month (with cap and floor prices of $22.20 and $18.00, respectively)
through February 1997 and 15,000 barrels of oil per month (with cap and floor
prices of $25.10 and $20.00, respectively) from March 1997 through August, 1997.
At December 31, 1996, the Company had open contracts for gas prices swaps of
302,000 MMbtu of gas per month at $2.16 per MMbtu during January 1997, 100,000
MMbtu of gas per month at $1.905 per MMbtu from February 1997 through January
1998 and another 100,000 MMbtu of gas per month at $1.77 per MMbtu from February
1997 through January 1998. These contracts expire monthly as indicated above.
The gains or losses on the Company's hedging transactions are determined as the
difference between the contract price and a reference price, generally closing
prices on the NYMEX. The resulting transaction gains and losses are determined
monthly and are included in the

F-25
<PAGE> 88

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

period the hedged production or inventory is sold. Net losses relating to these
derivatives for the years ended December 31, 1995 and 1996 were none and
$272,000, respectively.

NOTE 15 -- STOCK COMPENSATION PLAN

The Company adopted in 1996 two stock compensation plans for its employees
and directors, (i) the Magnum Hunter Resources Employee Stock Ownership Plan,
(the "ESOP"), and (ii) the Magnum Hunter Resources, Inc. 1996 Incentive Stock
Option Plan (the "Option Plan"). In addition, the Company authorized the
issuance of its common stock to participants in the Magnum Hunter Resources,
Inc. 401(k) plan in an amount that matched employee contributions up to one
hundred percent (100%). The cost of this matching contribution was $59,000 in
1996.

ESOP

The Company established an ESOP and a related trust as a long-term benefit
for its employees. Under terms of the ESOP, eligible participants may elect to
make elective deferred contributions of not less than 1% or more than 15% of
their annual compensation, limited in combination with the 401(k) plan to the
maximum allowable per year by the Internal Revenue Code. The Plan also allows
for the Company to make discretionary contributions to the ESOP, but it is not
the intent of the Company to do so. It is also the Company's intent to invest
all contributions in Common Stock. In this regard, on October 11, 1996, the ESOP
purchased 22,556 shares of the Company's Common Stock for $3.75 per share from a
third party. To fund this purchase, the ESOP borrowed $84,585 from a bank.
Participant contributions will be used to acquire shares at the price stated
above by retiring the principal and interest of this debt. As of December 31,
1996, no participant contributions had been made to the ESOP.

1996 Incentive Stock Option Plan

The Company established this plan effective April 1, 1996, and is governed
by Section 422 of the Internal Revenue Code, and Section 16(b) of the Securities
Exchange Act of 1934. The Option Plan covers 1,200,000 shares of the Company's
Common Stock. Eligibility is limited to employees and directors of the Company
and its subsidiaries. The actual selection of grantees is made by the Board of
Directors. The term of the Option Plan is 10 years, and the term of the options
is at the discretion of the Board, with a term of 5 years. All options are fully
vested and exercisable when granted. The exercise price is fair market value at
the date of grant, except for individuals who own 10% or more of the Company's
stock.

Prior to 1995, Hunter had granted certain of its employees and directors
options to purchase its common shares. In connection with the Hunter
Combination, the Company has substituted the Hunter options with 264,558 options
under the Plan, 239,022 of which have an exercise price of $.73425 per share and
25,536 of which have an exercise price of $1.65 per share. During 1996, 12,258
of these options were exercised. In addition, during 1996, the Board granted the
remaining 935,442 options to employees and directors at an exercise price of
$4.50 per share.

F-26
<PAGE> 89

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following is a summary of stock option activity under the Option Plan:

<TABLE>
<CAPTION>
1995 1996
-------------------------- --------------------------
WEIGHTED WEIGHTED
AVERAGE AVERAGE
SHARES EXERCISE PRICE SHARES EXERCISE PRICE
--------- -------------- --------- --------------
<S> <C> <C> <C> <C>
Outstanding -- Beginning of Year..... 264,558 $0.82 264,558 $0.82
Granted.............................. -- -- 935,442 4.50
Exercised............................ -- -- (12,258) .73
Canceled............................. -- -- -- --
--------- ----- --------- -----
Outstanding -- End of Year........... 264,558 $0.82 1,187,742 $3.72
========= ===== ========= =====
</TABLE>

The following is a summary of plan stock options outstanding at December
31, 1996:

<TABLE>
<CAPTION>
WEIGHTED
AVERAGE
NUMBER OF REMAINING
OPTIONS CONTRACTUAL LIFE NUMBER OF
EXERCISE PRICE OUTSTANDING (YEARS) EXERCISABLE OPTIONS
-------------- ----------- ---------------- -------------------
<S> <C> <C> <C>
$ .73................................ 226,764 1.0 35,242
1.65................................ 25,536 3.0 --
4.50................................ 935,442 4.3 935,442
--------- -------
1,187,742 970,684
========= =======
</TABLE>

The Company adopted the disclosures only portion of SFAS No. 123 as it
continued to follow the provisions of APB No. 25, which is the intrinsic value
method of accounting for stock-based compensation.

On a pro forma basis, the effect of stock based compensation had the
Company adopted Statement No. 123 is as follows:

<TABLE>
<CAPTION>
1996
-----------
<S> <C>
Net Income (Loss):
As reported............................................... $ 103,000
Pro Forma................................................. (1,540,000)
Primary Earnings per Share:
As reported............................................... .01
Pro Forma................................................. (.12)
Fully Diluted Earnings per Share:
As reported............................................... .01
Pro Forma................................................. (.12)
</TABLE>

The weighted average grant date fair value of options granted was $2.56 and
of warrants granted was $1.09 during 1996. Fair value of options and warrants
was calculated by using the Black-Scholes options pricing model using the
following weighted average assumptions for 1996 activity: risk free interest
rate of 5.74%, expected life of 4.28 years, expected volatility of 60.8% and no
dividend yield.

NOTE 16 -- SUBSEQUENT EVENTS

In January, 1997, the Company purchased a fifty percent (50%) interest in
the McLean Gas Plant, the gas processing facility connected to the Company's
Panoma gas gathering system for $2.5 million. Under the terms of the purchase
agreement, the Company will receive 100% of the net profits of the plant until
it receives the $2.5 million purchase price, at which point its net profits
interest will revert to fifty percent (50%), the

F-27
<PAGE> 90

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company's ownership position. The acquisition was funded through the Company's
revolving credit agreement with certain banks.

On April 30, 1997, the Company acquired from a subsidiary of Burlington
Resources, Inc., effective as of January 1, 1997, the Permian Basin Properties,
consisting of 25 field areas in west Texas and 22 field areas in southeast New
Mexico, for a net purchase price of $133.0 million after adjustments of $10.5
million for production cash flow from January 1, 1997 to the closing date and
other minor adjustments.

The Company financed the acquisition of the Permian Basin Properties with a
new $130.0 million credit facility (the "New Credit Facility") and a senior
subordinated credit facility of $60.0 million (the "Term Loan Facility").
Borrowings of $119.5 million under the New Credit Facility and $60.0 million
under the Term Loan Facility were used to pay the $123.0 million balance of the
$133.0 million net purchase price for the Permian Basin Properties, to repay the
$53.7 million in outstanding indebtedness as of April 30, 1997 under the
Company's previous $100.0 million credit facility (the "Previous Credit
Facility") and to pay the costs associated with the Permian Basin Acquisition
and the related financings. The New Credit Facility currently bears interest at
9.0% per annum. After repayment of the Term Loan Facility using the proceeds of
a $140.0 million offering of Senior Subordinated Notes due 2007, the New Credit
Facility bore interest at LIBOR plus 1.75% per annum, which was 7.6% based on
the LIBOR rate at April 30, 1997. The unpaid principal amount under the New
Credit Facility matures on April 30, 2002. At April 30, 1997, the interest rate
on the Term Loan Facility was 11.5% per annum. The Term Loan Facility initially
matures on April 30, 1998, at which time the Company has the option to extend
such facility for an additional five years.

NOTE 17 -- EMPLOYMENT CONTRACTS AND TERMINATION OF EMPLOYMENT AND
CHANGE-IN-CONTROL ARRANGEMENTS

Mr. Gary C. Evans and Mr. Matthew C. Lutz have employment agreements with
Magnum Hunter Resources, Inc. Mr. Evans' agreement terminates December 31, 1997
and continues thereafter on a year to year basis and provides for a base salary
of $200,000 per annum. Mr. Lutz's agreement terminates September 30, 1998 and
continues thereafter on a year to year basis and provides for a base salary of
$100,000 per annum. Both agreements provide that the same benefits supplied to
other Company employees shall be available to the employee. The employment
agreements also contain, among other things, covenants by the employee that in
the event of termination, he will not associate with a business that competes
with the Company for a period of one year after cessation of employment. The
Company also has key man life insurance on Mr. Evans in the amount of
$1,000,000.

F-28
<PAGE> 91

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)

Proved oil and gas reserves consist of those estimated quantities of crude
oil, gas, and natural gas liquids that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are reserves that can be expected to be recovered
through existing wells with existing equipment and operating methods.

Estimates of petroleum reserves have been made by independent engineers and
Company employees. These estimates include reserves in which the Company holds
an economic interest under production-sharing and other types of operating
agreements. These estimates do not include probable or possible reserves. The
estimated net interests in proved reserves are based upon subjective engineering
judgments and may be affected by the limitations inherent in such estimation.
The process of estimating reserves is subject to continual revision as
additional information becomes available as a result of drilling, testing,
reservoir studies and production history. There can be no assurance that such
estimates will not be materially revised in subsequent periods.

Estimated quantities of proved oil and gas reserves of the Company were as
follows:

<TABLE>
<CAPTION>
GAS
OIL (THOUSAND
(BARRELS) CUBIC FEET)
--------- -----------
<S> <C> <C>
December 31, 1995
Proved reserves........................................... 3,767,739 14,071,916
Proved developed reserves................................. 1,681,841 8,796,748
December 31, 1996
Proved reserves........................................... 5,338,255 90,565,997
Proved developed reserves................................. 1,962,184 71,275,141
</TABLE>

The changes in proved reserves for the year ended December 31, 1995 and
1996 were as follows:

<TABLE>
<CAPTION>
GAS
OIL (THOUSAND
(BARRELS) CUBIC FEET)
--------- -----------
<S> <C> <C>
RESERVES AT DECEMBER 31, 1994............................... 1,260,520 4,914,207
Purchase of minerals-in-place............................... 3,122,382 10,973,298
Extensions and discoveries.................................. 38,498 564,247
Production.................................................. (29,972) (102,056)
Revisions of estimates...................................... (623,689) (2,277,780)
--------- ----------
RESERVES AT DECEMBER 31, 1995............................... 3,767,739 14,071,916
Purchase of minerals-in-place............................... 2,678,579 81,943,557
Sale of minerals-in-place................................... (214,381) (1,318,164)
Extensions and discoveries.................................. -- 151,606
Production.................................................. (191,203) (2,674,793)
Revisions of estimates...................................... (702,479) (1,608,125)
--------- ----------
RESERVES AT DECEMBER 31, 1996............................... 5,338,255 90,565,997
========= ==========
</TABLE>

F-29
<PAGE> 92

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)

The aggregate amounts of capitalized costs relating to oil and gas
producing activities and the related accumulated depreciation, depletion and
impairment as of December 31, 1995 and 1996 were as follows:

<TABLE>
<CAPTION>
1995 1996
----------- -----------
<S> <C> <C>
Unproved oil and gas properties........................... $ 842,889 $ 459,254
Proved properties......................................... 36,256,428 70,574,890
----------- -----------
Gross Capitalized Costs................................... 37,099,317 71,034,144
Accumulated depreciation, depletion and impairment........ (1,914,602) (4,513,541)
----------- -----------
Net Capitalized Costs........................... $35,184,715 $66,520,603
=========== ===========
</TABLE>

Costs incurred in oil and gas producing activities, both capitalized and
expensed, during the years ended December 31, 1995 and 1996 were as follows:

<TABLE>
<CAPTION>
1995 1996
----------- -----------
<S> <C> <C>
Property acquisition costs
Proved properties......................................... $27,983,521 $31,982,821
Unproved properties..................................... 142,545 --
Exploration costs....................................... 340,411 1,114,733
Development costs......................................... -- 837,273
----------- -----------
Total Costs Incurred............................ $28,466,477 $33,934,827
=========== ===========
</TABLE>

Results of operations from oil and gas producing activities for the years
ended December 31, 1995 and 1996 were as follows:

<TABLE>
<CAPTION>
1995 1996
--------- -----------
<S> <C> <C>
Oil and gas production revenue............................. $ 616,596 $10,247,688
Disposal services revenue.................................. 31,978 20,487
Production costs........................................... (267,647) (4,389,465)
Depreciation and depletion................................. (421,101) (2,598,939)
--------- -----------
Results of Operations for Producing Activities... $ (40,174) $ 3,279,771
========= ===========
</TABLE>

The standardized measure of discounted estimated future net cash flows
related to proved oil and gas reserves at December 31, 1995 and 1996 were as
follows:

<TABLE>
<CAPTION>
1995 1996
------------ -------------
<S> <C> <C>
Future cash inflows.................................... $ 95,068,694 $ 492,157,062
Future development and production costs................ (37,746,877) (138,614,804)
------------ -------------
Future net cash flows, before income tax............... 57,321,817 353,542,258
Future income taxes.................................... (11,381,779) (102,341,098)
------------ -------------
Future Net Cash Flows.................................. 45,940,038 251,201,160
10% annual discount.................................... (16,120,359) (134,116,299)
------------ -------------
Standardized Measure of Discounted Future Net
Cash Flows................................. $ 29,819,679 $ 117,084,861
============ =============
</TABLE>

F-30
<PAGE> 93

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)

The primary changes in the standardized measure of discounted estimated
future net cash flows for the years ended December 31, 1995 and 1996 were as
follows:

<TABLE>
<CAPTION>
1995 1996
----------- ------------
<S> <C> <C>
Purchases of minerals-in-place............................ $30,507,745 $129,544,769
Sales of minerals-in-place................................ -- (2,195,780)
Extensions, discoveries and improved recovery, less
related costs........................................... 582,001 302,785
Sales of oil and gas produced, net of production costs.... (350,083) (5,858,223)
Development costs incurred during the period.............. -- --
Revision of prior estimates:
Net change in prices and costs.......................... 4,864,688 14,993,539
Change in quantity estimates............................ (7,637,000) (10,107,737)
Accretion of discount..................................... 623,512 2,981,968
Net change in income taxes................................ (5,006,300) (42,396,139)
----------- ------------
Net Change...................................... $23,584,563 $ 87,265,182
=========== ============
</TABLE>

Estimated future cash inflows are computed by applying year-end prices of
oil and gas to year-end quantities of proved reserves. Estimated future
development and production costs are determined by estimating the expenditures
to be incurred in developing and producing the proved oil and gas reserves at
the end of the year, based on year-end costs and assuming continuation of
existing economic conditions. Estimated future income tax expense is calculated
by applying year-end statutory tax rates to estimated future pre-tax net cash
flows related to proved oil and gas reserves, less the tax basis of the
properties involved.

The assumption used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and as such, do not
necessarily reflect the Company's expectations of actual revenues to be derived
from those reserves nor their present worth. The limitations inherent in the
reserve quantity estimation process are equally applicable to the standardized
measure computations since these estimates are the basis for the valuation
process.

F-31
<PAGE> 94

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
(IN THOUSANDS)

ASSETS

<TABLE>
<CAPTION>
SEPTEMBER 30,
1997
-------------
<S> <C>
CURRENT ASSETS:
Cash and cash equivalents................................. $ 3,081
Accounts receivable
Trade, net of allowance of $133......................... 14,211
Due from affiliates..................................... 119
Notes receivable from affiliate........................... 412
Current portion of long-term note receivable.............. 619
Prepaid and other......................................... 1,024
--------
TOTAL CURRENT ASSETS................................ 19,466
--------
PROPERTY, PLANT AND EQUIPMENT
Oil and gas properties, full cost method
Unproved................................................ 460
Proved.................................................. 215,513
Pipelines................................................. 9,841
Other property............................................ 653
--------
TOTAL PROPERTY, PLANT AND EQUIPMENT................. 226,467
Accumulated depreciation, depletion and impairment........ (13,467)
--------
NET PROPERTY, PLANT AND EQUIPMENT................... 213,000
--------
OTHER ASSETS
Deposits and other assets................................. 6,046
Long-term notes receivable, net of imputed interest....... 1,646
--------
TOTAL ASSETS........................................ $240,158
========

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Trade payables and accrued liabilities.................... $ 13,753
Dividends payable......................................... 219
Suspended revenue payable................................. 846
Current maturities of long-term debt...................... 22
Notes payable............................................. 2,699
--------
TOTAL CURRENT LIABILITIES........................... 17,539
--------
LONG-TERM LIABILITIES
Long-term debt, less current maturities................... 188,027
Production payment liability.............................. 790
Deferred income taxes..................................... 1,858
Minority interest......................................... 40
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock -- $.001 par value; 10,000,000 shares
authorized, 216,000 designated as Series A; 80,000
shares issued and outstanding, liquidation amount $0.... --
1,000,000 shares designated as 1996 Series A
Convertible; 1,000,000 issued and outstanding,
liquidation amount $10,000,000......................... 1
Common stock -- $.002 par value; 50,000,000 shares
authorized, 14,271,975 shares issued.................... 29
Additional paid-in capital................................ 40,291
Accumulated deficit....................................... (8,416)
--------
31,905
Treasury stock (538,633 shares of common stock)........... (1)
--------
TOTAL STOCKHOLDERS' EQUITY.............................. 31,904
--------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.............. $240,158
========
</TABLE>

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

F-32
<PAGE> 95

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

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

<TABLE>
<CAPTION>
THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------------ ------------------------
1996 1997 1996 1997
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
Operating Revenues:
Oil and gas sales....................... $ 3,536 $ 11,002 $ 6,357 $ 22,793
Gas gathering, marketing and
processing........................... 1,615 2,438 3,143 7,721
Oil field services and international
sales................................ 184 186 385 3,792
---------- ---------- ---------- ----------
Total Operating Revenues........ 5,335 13,626 9,885 34,306
---------- ---------- ---------- ----------
Operating Costs and Expenses
Oil and gas production.................. 1,179 3,781 2,305 8,521
Gas gathering, marketing and
processing........................... 1,315 1,865 2,629 5,803
Oil field services and international
sales................................ 194 58 521 3,482
Depreciation and depletion.............. 804 4,147 1,888 8,607
General and administrative.............. 227 477 670 1,128
---------- ---------- ---------- ----------
Total Operating Costs and
Expenses...................... 3,719 10,328 8,013 27,541
---------- ---------- ---------- ----------
Operating Profit (Loss)................... 1,616 3,298 1,872 6,765
Other income............................ 28 453 214 608
Interest expense........................ (1,051) (4,540) (1,550) (9,298)
---------- ---------- ---------- ----------
Net Income (Loss) before income tax and
minority interest....................... 593 (789) 536 (1,925)
Benefit (Provision) for deferred income
tax.................................. (204) 300 (204) 731
---------- ---------- ---------- ----------
Net Income (Loss) before minority
interest................................ 389 (489) 332 (1,194)
Minority interest in subsidiary
earnings............................. -- (20) -- (40)
---------- ---------- ---------- ----------
Net Income (Loss) Before Extraordinary
Loss.................................... 389 (509) 332 (1,234)
Extraordinary Loss From Early
Extinguishment of Debt.................. -- -- -- (1,384)
---------- ---------- ---------- ----------
Net Income (Loss)......................... 389 (509) 332 (2,618)
Dividends Applicable to Preferred Stock... (42) (219) (382) (657)
---------- ---------- ---------- ----------
Income (Loss) Applicable to Common
Shares.................................. $ 347 $ (728) $ (50) $ (3,275)
========== ========== ========== ==========
Income (Loss) Before Extraordinary Loss
per Common Share........................ $ 0.03 $ (0.05) $ 0.00 $ (0.14)
Extraordinary Loss per Common Share....... $ -- $ -- $ -- $ (0.10)
---------- ---------- ---------- ----------
Income (Loss) per Common Share............ $ 0.03 $ (0.05) $ (0.00) $ (0.24)
========== ========== ========== ==========
Common Shares Used In Per Share
Calculation............................. 12,924,967 13,687,278 12,084,041 13,659,170
========== ========== ========== ==========
</TABLE>

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

F-33
<PAGE> 96

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

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

<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
--------------------
1996 1997
-------- ---------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)......................................... $ 332 $ (2,618)
Adjustments to reconcile net income (loss) to cash
provided by (used for) operating activities:
Extraordinary loss..................................... -- 1,384
Depreciation and depletion............................. 1,888 8,607
Amortization of financing fees......................... -- 330
Deferred income taxes.................................. 204 (732)
Minority interest...................................... -- 40
(Gain) Loss on sale of assets.......................... (143) (333)
Other.................................................. -- 32
Change in certain assets and liabilities:
Accounts and notes receivables....................... (2,317) (9,717)
Other current assets................................. (160) (972)
Deposits and other assets............................ (376) --
Accounts payable and accrued liabilities............. 2,436 9,875
-------- ---------
NET CASH PROVIDED BY (USED BY) OPERATING ACTIVITIES......... $ 1,864 $ 5,897
-------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of assets.......................... 188 953
Additions to property and equipment....................... (38,787) (148,429)
Loan made for promissory note receivable.................. -- (666)
Payments received on promissory note receivable........... -- 183
-------- ---------
NET CASH USED BY INVESTING ACTIVITIES....................... (38,599) (147,959)
-------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt and production
payment................................................ 55,313 337,500
Fees paid related to financing activities................. -- (7,936)
Proceeds from short-term notes payable.................... -- 2,699
Payments of principal on long-term debt and production
payment................................................ (17,710) (188,364)
Payment of fees on issuance of preferred stock............ -- (505)
Proceeds from issuance of common and preferred stock, net
of offering costs...................................... -- 522
Redemption of preferred stock............................. (295) --
Dividends paid............................................ (438) (460)
-------- ---------
NET CASH PROVIDED BY FINANCING ACTIVITIES................... 36,870 143,456
-------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........ 135 1,394
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD............ 1,544 1,687
-------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD.................... $ 1,679 $ 3,081
======== =========
</TABLE>

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

F-34
<PAGE> 97

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 -- MANAGEMENT'S REPRESENTATION

The consolidated balance sheet as of September 30, 1997, the consolidated
statements of operations for the nine months ended September 30, 1996 and 1997,
and the consolidated statements of cash flows for the nine month periods then
ended are unaudited. In the opinion of management, all necessary adjustments
(which include only normal recurring adjustments) have been made to present
fairly the financial position, results of operations and changes in cash flows
for the nine month periods.

Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted. It is suggested that these condensed financial
statements be read in conjunction with the financial statements and notes
thereto included in the December 31, 1996 annual report on Form 10-KSB for the
Company. The results of operations for the nine month and three month periods
ended September 30, 1997, are not necessarily indicative of the operating
results for the full year.

The accompanying consolidated financial statements include the accounts of
the Company and its wholly-owned subsidiaries. All significant intercompany
transactions and balances have been eliminated in consolidation. Certain items
have been reclassified to conform with the current presentation.

The Company is a holding company with no significant assets or operations
other than its investments in its subsidiaries. The wholly-owned subsidiaries of
the Company are direct guarantors of the Company's Notes and have fully and
unconditionally guaranteed the Notes on a joint and several basis. The
guarantors comprise all of the direct and indirect subsidiaries of the Company
(other than inconsequential subsidiaries), and the Company has not presented
separate financial statements and other disclosures concerning each guarantor
because management has determined that such information is not material to
investors. There is no restriction on the ability of consolidated or
unconsolidated subsidiaries to transfer funds to the Company in the form of cash
dividends, loans, or advances.

NOTE 2 -- RECENT EVENTS

In February, 1997, the Company entered into a definitive agreement with
Burlington Resources, Inc. to acquire for $143.5 million, subject to certain
purchase price adjustments, effective January 1, 1997, the Permian Basin
Properties consisting of 25 field areas in West Texas and 22 field areas in
Southeast New Mexico containing 1,852 producing oil and gas wells. In accordance
with the definitive acquisition agreement, the Company made a performance
deposit of $10 million against the purchase price.

On April 30, 1997, the Company closed on the purchase of the Permian Basin
Properties for a net purchase price of approximately $133 million, including,
but not limited to, certain adjustments for a January 1, 1997 effective date.

The Company financed the acquisition of the Permian Basin Properties with a
new $130.0 million credit facility (the "Credit Facility") and a senior
subordinated credit facility of $60.0 million (the "Bridge Loan Facility").
Borrowings of $119.5 million under the Credit Facility and $60.0 million under
the Bridge Loan Facility were used to pay the $123.0 million balance of the
$133.0 million net purchase price for the Permian Basin Properties, to repay the
$53.7 million in outstanding indebtedness as of April 30, 1997 under the
Company's previous $100.0 million credit facility and to pay the costs
associated with the Permian Basin acquisition and the related financings.

On May 28, 1997, the Company completed an offering of $140 million
aggregate principal amount of its 10% Senior Notes due 2007 (the "Notes").
Interest on the Notes will accrue from their date of original issuance and will
be payable semi-annually in arrears on June 1 and December 1 of each year,
commencing on December 1, 1997, at the rate of 10% per annum. The Notes will be
redeemable, in whole or in part, at the option of the Company on or after June
1, 2002, at the redemption prices set forth herein, plus accrued interest

F-35
<PAGE> 98

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

to the date of redemption. The Notes will be general unsecured obligations of
the Company and will rank pari passu with any unsubordinated indebtedness of the
Company and will rank senior in right of payment to all subordinated obligations
of the Company. The net proceeds from the offering were approximately $135.5
million after deducting estimated fees and expenses of $4.5 million payable by
the Company. The Company utilized the net proceeds to repay the $60.0 million of
outstanding indebtedness under the Bridge Loan Facility and to reduce
indebtedness under the Credit Facility by approximately $75.0 million which
reduced the borrowing base to $60.0 million. Total long-term debt under the
Credit Facility at September 30, 1997 was $48.0 million. The Company recently
amended its Credit Facility with its lenders effective as of September 30, 1997,
to increase the amount of the Credit Facility to $125.0 million, to increase the
amount of the borrowing base to $65.0 million, and to modify a loan covenant.

The Company has called its publicly traded Warrants for redemption on
November 7, 1997 at a redemption price of $0.02 per Warrant. The Warrants are
presently exercisable for Common Stock at an exercise price of $5.50 per share.
The Company anticipates that substantially all the Warrants will be exercised,
and if so, the Company will receive cash proceeds in the amount of approximately
$4.7 million.

On October 30, 1997, the Company filed a registration statement with the
Securities and Exchange Commission to register 6.5 million shares of Common
Stock to be sold by the Company and an additional 150,000 shares of Common Stock
to be sold by a selling shareholder. The proceeds received from the sale of
shares by the Company will be used to repay substantially all of the outstanding
indebtedness under the Credit Facility.

F-36
<PAGE> 99

INDEPENDENT AUDITORS' REPORT

Board of Directors
Magnum Hunter Resources, Inc.
Irving, Texas

We have audited the accompanying historical summaries of revenue and direct
operating expenses of properties to be acquired April 30, 1997 (the "Permian
Basin Properties"), for the years ended December 31, 1996 and 1995. The
historical summaries are the responsibility of the Company's management. Our
responsibility is to express an opinion on the historical summaries based on our
audit.

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

The accompanying historical summaries were prepared for the purpose of
complying with the rules and regulations of the Securities and Exchange
Commission (for inclusion in the Form S-3 of Magnum Hunter Resources, Inc.) as
described in Note 1 and are not intended to be a complete presentation of the
properties' revenues and expenses.

In our opinion, the historical summaries referred to above present fairly,
in all material respects, the revenue and direct operating expenses of the
properties to be acquired April 30, 1997, in conformity with generally accepted
accounting principles.

HEIN + ASSOCIATES LLP

April 23, 1997
Dallas, Texas

F-37
<PAGE> 100

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

PERMIAN BASIN PROPERTIES

HISTORICAL SUMMARIES OF REVENUES AND DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1995 AND 1996
AND FOR THE UNAUDITED FOUR MONTH PERIODS ENDED APRIL 30, 1996 AND 1997

<TABLE>
<CAPTION>
YEAR ENDED
----------------------------
1995 1996
------------ ------------
<S> <C> <C>
Oil and gas sales........................................... $ 30,098,000 $ 39,433,000
Direct operating expenses................................... (11,711,000) (11,646,000)
------------ ------------
Net revenue................................................. $ 18,387,000 $ 27,787,000
============ ============
</TABLE>

<TABLE>
<CAPTION>
FOUR MONTHS ENDED
APRIL 30,
--------------------------
1996 1997
----------- -----------
(UNAUDITED)
<S> <C> <C>
Oil and gas sales........................................... $12,323,000 $12,627,000
Direct operating expenses................................... (3,891,000) (3,039,000)
----------- -----------
Net revenue................................................. $ 8,432,000 $ 9,588,000
=========== ===========
</TABLE>

See Notes to Historical Summaries of Revenues and Direct Operating Expenses
for the Years Ended December 31, 1995 and 1996 and for the Four Month Periods
Ended April 30, 1996 and 1997.

F-38
<PAGE> 101

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

PERMIAN BASIN PROPERTIES

NOTES TO HISTORICAL SUMMARIES OF REVENUES AND
DIRECT OPERATING EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1995 AND 1996
AND FOR THE UNAUDITED FOUR MONTH PERIODS ENDED APRIL 30, 1996 AND 1997

NOTE 1 -- BASIS OF PREPARATION

The accompanying historical summaries of revenues and direct operating
expenses relate to the operations of the oil and gas properties to be acquired
by Magnum Hunter Resources, Inc. (the "Company") on April 30, 1997 from
Burlington Resources Oil and Gas Company (Burlington). The properties are to be
acquired for approximately $133,000,000, net of purchase adjustments.

Revenues are recorded when the Company's share of oil or gas and related
liquids are sold. Direct operating expenses are recorded when the related
liability is incurred. Direct operating expenses include lease operating
expenses, ad valorem taxes and production taxes. Depreciation and amortization
of oil and gas properties, general and administrative expenses and income taxes
have been excluded from operating expenses in the accompanying historical
summaries because the amounts would not be comparable to those resulting from
proposed future operations. Sales of gas and oil (until August 1996) have
generally been made to an affiliated entity of Burlington.

The historical summaries presented herein were prepared for the purposes of
complying with the financial statement requirements of a business acquisition to
be filed on Form S-3 as promulgated by Regulation S-B Item 3-10 of the
Securities Exchange Act of 1934.

Unaudited Information

The historical summaries for the four month periods ended April 30, 1996
and 1997 were taken from Burlington's books and records without audit. However,
in the opinion of management, such information includes all adjustments
(consisting only of normal recurring accruals) which are necessary to properly
reflect the historical summaries of the Permian Basin Properties for the four
month periods ended April 30, 1996 and 1997.

NOTE 2 -- CONTINGENCIES

The properties to be acquired are subject to several lawsuits against
Burlington that have arisen from the ordinary course of operations. Burlington
has indemnified the Company in the Purchase and Sale Agreement against any
liability from those claims.

In the Purchase and Sale Agreement, Burlington agreed to indemnify the
Company against environmental claims relating to the acquired properties and
arising prior to January 1, 1997 provided that the Company notifies Burlington
of such claims by December 31, 1997. Burlington will provide indemnification
against such claims up to $10,762,500 and share the next $21,525,000 of claims
with the Company on an equal basis. Burlington represented in the Purchase and
Sale Agreement that no material environmental claims have been asserted; however
certain of these properties require remediation which, in the Company's opinion,
will not result in material costs.

NOTE 3 -- SUPPLEMENTAL INFORMATION ON OIL AND GAS RESERVES (UNAUDITED)

F-39
<PAGE> 102

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

PERMIAN BASIN PROPERTIES

NOTES TO HISTORICAL SUMMARIES OF REVENUES AND DIRECT OPERATING
EXPENSES -- (CONTINUED)

The following estimates of proved reserves have been made by independent
engineers. The estimated net interests in proved reserves are based upon
subjective engineering judgments and may be affected by the limitations inherent
in such estimation. The process of estimating reserves is subject to continual
revision as additional information becomes available as a result of drilling,
testing, reservoir studies and production history. There can be no assurance
that such estimates will not be materially revised in subsequent periods.

Estimated quantities of proved oil and gas reserves of the properties to be
acquired April 30, 1997 are as follows:

<TABLE>
<CAPTION>
OIL NATURAL GAS
(BARRELS) (THOUSAND CUBIC FEET)
---------- ---------------------
<S> <C> <C>
December 31, 1995
Proved reserves................................... 16,176,000 108,476,000
========== ===========
Proved developed reserves......................... 9,853,000 85,973,000
========== ===========
December 31, 1996
Proved reserves................................... 15,291,000 99,876,000
========== ===========
Proved developed reserves......................... 8,968,000 77,373,000
========== ===========
</TABLE>

The changes in proved reserves for the years ended December 31, 1995 and
1996 were as follows:

<TABLE>
<CAPTION>
OIL NATURAL GAS
(BARRELS) (THOUSAND CUBIC FEET)
---------- ---------------------
<S> <C> <C>
Reserves at December 31, 1994......................... 17,121,000 118,076,000
Revisions and other................................... 73,000 730,000
Production............................................ (1,018,000) (10,330,000)
---------- -----------

Reserves at December 31, 1995......................... 16,176,000 108,476,000
Revisions and other................................... 29,000 808,000
Production............................................ (914,000) (9,408,000)
---------- -----------

Reserves at December 31, 1996......................... 15,291,000 99,876,000
========== ===========
</TABLE>

The standardized measure of discounted estimated future net cash flows
related to proved oil and gas reserves at December 31, 1995 and 1996 were as
follows:

<TABLE>
<CAPTION>
1995 1996
------------- -------------
<S> <C> <C>
Future cash inflows.................................... $ 410,721,000 $ 769,681,000
Future development and production costs................ (275,252,000) (300,868,000)
------------- -------------
Future net cash flows, before income tax............... 135,469,000 468,813,000
Future income taxes.................................... -- (116,660,000)
------------- -------------
Future Net Cash Flows.................................. 135,469,000 352,153,000
10% annual discount.................................... (60,181,000) (169,385,000)
------------- -------------
Standardized Measure of Discounted Future Net Cash
Flows................................................ $ 75,288,000 $ 182,768,000
============= =============
</TABLE>

F-40
<PAGE> 103

MAGNUM HUNTER RESOURCES, INC. AND SUBSIDIARIES

PERMIAN BASIN PROPERTIES

NOTES TO HISTORICAL SUMMARIES OF REVENUES AND DIRECT OPERATING
EXPENSES -- (CONTINUED)

The primary changes in the standardized measure of discounted estimated
future net cash flows for the years ended December 31, 1995 and 1996 were as
follows:

<TABLE>
<CAPTION>
1995 1996
------------ ------------
<S> <C> <C>
Beginning of year...................................... $ 78,153,000 $ 75,288,000
Sales of oil and gas produced, net of production
costs................................................ (18,387,000) (27,787,000)
Net change in price and costs.......................... 6,800,000 182,919,000
Change in quantity estimates and other................. 432,000 933,000
Accretion of discount.................................. 7,800,000 7,528,000
Net change in income taxes............................. 490,000 (56,113,000)
------------ ------------
End of year............................................ $ 75,288,000 $182,768,000
============ ============
</TABLE>

Estimated future cash inflows are computed by applying year-end prices of
oil and gas to year-end quantities of proved reserves. Estimated future
development and production costs are determined by estimating the expenditures
to be incurred in developing and producing the proved oil and gas reserves at
the end of the year, based on year-end costs and assuming continuation of
existing economic conditions. Estimated future income tax expense is calculated
by applying year-end statutory tax rates to estimated future pre-tax net cash
flow related to proved oil and gas reserves, less the tax basis of the
properties involved.

The assumptions used to compute the standardized measure are those
prescribed by the Financial Accounting Standards Board and as such, do not
necessarily reflect the Company's expectations of actual revenues to be derived
from those reserves nor their present worth. The limitations inherent in the
reserve quantity estimation process are equally applicable to the standardized
measure computations since these estimates are the basis for the valuation
process.

F-41
<PAGE> 104

[THIS PAGE INTENTIONALLY LEFT BLANK]
<PAGE> 105

[THIS PAGE INTENTIONALLY LEFT BLANK]
<PAGE> 106

[THIS PAGE INTENTIONALLY LEFT BLANK]
<PAGE> 107

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

NO DEALER, SALESMAN OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS IN CONNECTION WITH THE OFFERING HEREIN CONTAINED AND, IF GIVEN OR
MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN
AUTHORIZED BY THE COMPANY OR THE UNDERWRITERS. THIS PROSPECTUS DOES NOT
CONSTITUTE AN OFFER TO SELL AFFAIRS OF THE COMPANY OR A SOLICITATION TO BUY ANY
OF THE SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS
UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS
PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCE, CREATE ANY
IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY DATE
SUBSEQUENT TO THE DATE HEREOF OR THERE HAS BEEN NO CHANGE IN SUCH DATE.

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary.......................... 3
Risk Factors................................ 11
Use of Proceeds............................. 17
Price Range of Common Stock and Dividend
Policy.................................... 18
Capitalization.............................. 19
Selected Consolidated Financial Data........ 20
Management's Discussion and Analysis of
Financial Condition and Results of
Operations................................ 22
Business and Properties..................... 28
Management.................................. 44
Principal and Selling Shareholders.......... 48
Description of Capital Stock................ 49
Description of Indebtedness................. 53
Underwriting................................ 56
Legal Matters............................... 57
Experts..................................... 58
Available Information....................... 58
Incorporation of Certain Documents by
Reference................................. 59
Glossary.................................... 60
Index to Consolidated Financial
Statements................................ F-1
</TABLE>

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

6,600,000 SHARES

[MAGNUM LOGO]

MAGNUM HUNTER
RESOURCES, INC.
COMMON STOCK
------------------------

PROSPECTUS
------------------------

RAUSCHER PIERCE REFSNES, INC.

CIBC OPPENHEIMER

JOHNSON RICE & COMPANY L.L.C.

VAN KASPER & COMPANY

NOVEMBER 21, 1997

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