HARCOR ENERGY INC, 424B4, 1996-07-26

HARCOR ENERGY INC
424B4, 1996-07-26
CRUDE PETROLEUM & NATURAL GAS

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<PAGE> 1
Filed Pursuant to Rule 424(b)(4)
Registration No. 333-04987

6,400,000 SHARES

[HARCOR ENERGY, HARCOR ENERGY, INC.
INC. LOGO]
COMMON STOCK

Of the 6,400,000 shares (the "Shares") of Common Stock, $.10 par value per
share (the "Common Stock"), of HarCor Energy, Inc., a Delaware corporation
("HarCor" or the "Company"), offered hereby (the "Offering"), 5,059,059 are
being sold by the Company and 1,340,941 are being sold directly by the Selling
Stockholders. See "Principal and Selling Stockholders." The Company will not
receive any proceeds from the sale of shares of Common Stock by the Selling
Stockholders.

The Common Stock is traded on the Nasdaq National Market under the symbol
"HARC." On July 25, 1996, the closing price of the Common Stock on the Nasdaq
National Market was $5.00 per share. See "Price Range of Common Stock."

SEE "RISK FACTORS" BEGINNING ON PAGE 12 FOR A DISCUSSION OF CERTAIN RISK
FACTORS THAT SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS.

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

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

<TABLE>
<CAPTION>
================================================================================================
UNDERWRITING PROCEEDS TO
PRICE DISCOUNTS AND PROCEEDS TO THE THE SELLING
TO PUBLIC COMMISSIONS(1) COMPANY(2) STOCKHOLDERS(2)
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Per Share............. $4.50 $0.29 $4.21 $4.21
- ------------------------------------------------------------------------------------------------
Total(3).............. $28,800,000 $1,872,000 $21,285,991 $5,642,009
================================================================================================
</TABLE>

(1) See "Underwriting" for information concerning indemnification of the
Underwriters.

(2) Before deducting expenses of the Offering, estimated at $250,000, payable by
the Company.

(3) The Company has granted to the Underwriters a 30-day option to purchase up
to 960,000 additional shares of Common Stock solely to cover
over-allotments, if any. If such option is exercised in full, the total
Price to Public, Underwriting Discounts and Commissions, Proceeds to the
Company and Proceeds to the Selling Stockholders will be $33,120,000,
$2,152,800, $25,325,191 and $5,642,009, respectively. See "Underwriting."

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

The shares of Common Stock are offered by the several Underwriters named
herein subject to prior sale, when, as and if delivered to and accepted by the
Underwriters, subject to the 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 July 31, 1996.

RAUSCHER PIERCE REFSNES, INC.

PETRIE PARKMAN & CO.

SOUTHCOAST CAPITAL CORPORATION

The date of this Prospectus is July 25, 1996.
<PAGE> 2

AVAILABLE INFORMATION

The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance
therewith, files reports and other information with the Securities and Exchange
commission (the "Commission"). Reports, proxy statements and other information
filed by the Company are available at the web site that the Commission maintains
at http: (w)ww.sec.gov. and can be inspected and copied at the public reference
facilities maintained by the Commission at 450 Fifth Street, N.W., Washington,
D.C. 20549, and the Commission's Regional Offices at Seven World Trade Center,
13th Floor, New York, New York, 10048 and CitiCorp Center, 500 West Madison
Street, Suite 1400, Chicago, Illinois 60661-2511. Copies of such material can be
obtained by mail from the Public Reference Branch of the Commission at 450 West
Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates.

The Company has filed with the Commission a Registration Statement on Form
S-1 (herein, together with all amendments and exhibits, referred to as the
"Regulation Statement") under the Securities Act of 1933, as amended (the
"Securities Act"). This prospectus does not contain all of the information set
forth in the Registration Statement, certain parts of which were omitted in
accordance with the rules and regulations of the Commission. For further
information, reference is hereby made to the Registration Statement. Any
statements contained herein concerning the provisions of any document filed as
an exhibit to the Registration Statement or otherwise filed with the Commission
are not necessarily complete, and in each instance reference is made to the copy
of such document so filed. Each such statement is qualified in its entirety by
such reference.

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

IN CONNECTION WITH THE OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT
A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH
TRANSACTIONS MAY BE EFFECTED ON THE NASDAQ NATIONAL MARKET, IN THE
OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE
DISCONTINUED AT ANY TIME.

2
<PAGE> 3

PROSPECTUS SUMMARY

This summary is qualified in its entirety by the more detailed information
and the consolidated financial statements and notes thereto appearing elsewhere
in this Prospectus. Unless otherwise indicated all information in this
Prospectus assumes that the Underwriters' over-allotment option will not be
exercised. Certain terms relating to the oil and gas industry are defined in the
Glossary of Oil and Gas Terms included elsewhere in this Prospectus. Investors
should carefully consider the information set forth in "Risk Factors."

THE COMPANY

GENERAL

HarCor Energy, Inc. is an independent energy company engaged in the
acquisition, exploitation and exploration of onshore crude oil and natural gas
properties in the United States. Since 1987 when the present management group
acquired control of the Company, HarCor has grown through selective acquisitions
and development drilling, with estimated proved reserves increasing from 1.35
MMBOE as of January 1, 1990 to 29.9 MMBOE as of January 1, 1996, at an average
replacement cost of $2.62 per BOE.

The Company's operations are currently focused in the San Joaquin Basin of
California, South Texas and the Permian Basin of West Texas. As of January 1,
1996, the Company's proved reserves, as estimated by the Company's independent
petroleum engineers, consisted of 15.3 MMBbls of crude oil and NGLs and 87.6 Bcf
of natural gas with a Pre-tax SEC 10 Value of $124.5 million, approximately 84%
of which was attributable to net proved reserves located in the Lost Hills Field
in the San Joaquin Basin.

The Company conducts its exploration, development and production activities
through strategic alliances with industry partners that are experienced and
knowledgeable in the particular geologic basins of activity and that own a
significant interest in the jointly owned properties. The industry partner is
generally designated as the operator of the jointly owned properties, thereby
allowing the Company to avoid the cost of maintaining the personnel and other
resources necessary to be an operator. The Company believes, however, that its
ownership of meaningful working interests in its properties, its contractual
rights to approve drilling budgets or propose wells and its experienced team of
oil and gas professionals allow the Company to control or significantly
influence the operators' decisions affecting the magnitude and timing of
exploration, development and production activities on its properties.

Through geographic concentration and tight control over oil and gas
operating and general and administrative expenses, the Company has maintained a
relatively low cost structure. For the year ended December 31, 1995, the Company
had an average production cost of $3.99 per BOE and general and administrative
expenses of $1.80 per BOE.

BUSINESS STRATEGY

The Company's business objective is to increase its hydrocarbon reserves as
economically as possible by:

- Continuing to develop its San Joaquin Basin, South Texas and Permian
Basin properties through additional drilling and secondary recovery
activities;

- Using the cash flow from its existing properties and the proceeds from
the Offering to engage in exploration activities with experienced and
technologically knowledgeable industry partners, initially onshore Texas
and Louisiana;

- Acquiring onshore oil and gas properties with significant development
potential; and

- Continuing to maintain relatively low production costs through geographic
concentration and tight control over operating and general and
administrative expenses.

3
<PAGE> 4

DEVELOPMENT ACTIVITIES

San Joaquin Basin. Approximately 20.8 MMBOE, or 69.4%, of the Company's
total proved reserves as of January 1, 1996 were classified as proved
undeveloped by Ryder Scott Company ("Ryder Scott"). Substantially all of the
Company's undeveloped reserves are located in the Lost Hills Field in the San
Joaquin Basin. Bakersfield Energy Resources, Inc. ("Bakersfield Energy"), a
company with extensive experience in the San Joaquin Basin, is the operator of
substantially all of HarCor's oil and gas properties in the San Joaquin Basin.
As of March 31, 1996, the Company had identified 173 new gross wells which it
intends to drill during the next five years to fully develop the proved reserves
on the properties, of which 48 are expected to be drilled in 1996. The Company
also plans to commence a secondary recovery waterflood project in the fourth
quarter of 1996 with respect to a portion of its properties in the Lost Hills
Field. In addition, the Company has completed a horizontal well in the Lost
Hills Field to test a possible extension of the current proved area of the field
and to evaluate the use of horizontal wells to eliminate the need to drill
certain infill vertical wells. The Company has identified 60 potential locations
for future development of probable and possible reserves located on the San
Joaquin Basin properties.

The San Joaquin Basin properties produce a light (approximately 40()
gravity), low sulfur crude oil that commands a substantial price premium to the
heavier crude oils typically produced in California. The associated natural gas
produced with the crude oil has a high Btu content (approximately 1,240 Btu)
which yields in excess of 2 gallons of NGLs per Mcf of natural gas when
processed in the Company's gas processing plant located in the San Joaquin
Basin. Since acquiring the properties in June 1994, the Company has drilled 76
gross development wells on the San Joaquin Basin properties, through March 31,
1996. As a result of such drilling activity, the Company's average daily
production has increased from 546 Bbls of oil and 7,195 Mcf of gas for the month
ended June 30, 1994 to 1,336 Bbls of oil and 13,895 Mcf of gas based on the
quarter ended March 31, 1996. Since acquiring the San Joaquin Basin properties,
the Company's net proved reserves attributable to such properties have increased
from 14.1 MMBOE as of June 30, 1994, to 22.7 MMBOE as of January 1, 1996, at an
average replacement cost of $1.65 per BOE. The Pre-tax SEC 10 Value of the
Company's San Joaquin Basin properties as of January 1, 1996 was $105.2 million
as estimated by Ryder Scott.

In addition to the extensive development drilling program in the Lost Hills
Field, the Company also plans to undertake a secondary oil recovery program to
further increase reserves and production from the field. Using primary
production techniques, it is estimated by Ryder Scott, as of January 1, 1996,
that the Ellis Lease located in the Lost Hills Field has proved reserves net to
the Company of approximately 9.0 MMBbls of crude oil. In addition to primary
development, the Company intends to increase recovery rates by implementing a
secondary recovery waterflood project in the Diatomite Zone on the Ellis Lease,
which is similar to waterflood projects currently used by other oil and gas
companies operating in the Lost Hills Field. The first phase of the Ellis Lease
waterflood project is planned to be initiated in the fourth quarter of 1996,
with expansion planned in 1997 and 1998 to cover the entire area currently
estimated to cover proved reserves. Ryder Scott estimates that the Company's
Ellis Lease will yield an additional 3.7 MMBbls of proved undeveloped secondary
recovery crude oil reserves utilizing the waterflood recovery method. In
addition, the Company will commence a feasibility study for waterflooding the
Reef Ridge Shale and Antelope Shale formations on its San Joaquin Basin
properties. During 1995, the Company and Bakersfield Energy completed a
three-dimensional ("3-D") reservoir model of the Diatomite Zone on the Ellis
Lease, the results of which are being used to examine various means of further
optimizing its planned Ellis Lease waterflood, including the use of horizontal
drilling on the property, as well as to assist the Company with additional
computer simulation modeling of hot water, steam and CO(2) recovery techniques.

4
<PAGE> 5

well is planned to evaluate its applicability to producing the deeper MacDonald
Shale formation at a depth of approximately 5,200 feet on the Ellis Lease. If
these wells are successful, potential additional horizontal locations may be
identified for future drilling on the Ellis Lease as well as in areas currently
outside the proved areas of the Company's Truman and Tisdale Leases.

The Company acquired its San Joaquin Basin properties from Bakersfield
Energy in June 1994. Bakersfield Energy, which originally acquired these
properties in 1990, retained a 25% working interest in these properties and has
continued to serve as the operator. In addition, the Company entered into a
joint acquisition agreement with Bakersfield Energy which gives each party the
right through June 1997 to participate equally in any acquisition of oil and gas
interests located within the state of California by the other party.

Gas Plant. As part of the acquisition of the San Joaquin Basin properties,
the Company purchased a modern, refrigeration liquid extraction facility with a
rated inlet capacity of 23 MMcf of gas per day and a rated liquid fractionation
capacity of 100,000 gallons of NGLs per day. Currently, the plant processes all
of the gas produced from the Company's San Joaquin Basin properties as well as
gas produced by third parties. The plant can deliver dry, residue gas into
multiple pipeline systems allowing the Company to enter into contract and
marketing arrangements that are not tied to the sometimes unfavorable and
volatile California spot market.

South Texas. In October 1992, the Company acquired an interest in nine gas
fields located in South Texas for a total purchase price of approximately $5.3
million. Subsequent development activities have resulted in average daily
production on the South Texas properties of 36 Bbls of crude oil and 4,068 Mcf
of natural gas for the quarter ended March 31, 1996 and net proved reserves as
estimated by Ryder Scott of 1.7 MMBOE at January 1, 1996. Approximately 51% of
the Company's reserves in the South Texas properties is attributable to its
interests in the Hostetter Field. The Company owns interests in 17 gross (four
net) wells and owns approximately 2,525 gross (956 net) acres in the Hostetter
Field. These wells are operated by Texaco Exploration and Production Company
("Texaco") and Cabot Oil and Gas Corporation ("Cabot"). The Company currently
believes that there are opportunities for additional development and
recompletion work in this field.

Permian Basin (West Texas/New Mexico). Since 1989, the Company, in
conjunction with Penroc Oil Corporation, has jointly identified and acquired
interests in oil and gas properties located in the Permian Basin with total
acquisition costs net to the Company of $3.4 million. Subsequent remedial work,
development drilling activity and secondary recovery procedures have resulted in
average daily production of 269 Bbls of crude oil and 416 Mcf of natural gas
based on production in the quarter ended March 31, 1996. Ryder Scott's estimate
of the Company's net proved reserves in the Permian Basin as of January 1, 1996
was 2.1 MMBOE.

EXPLORATION ACTIVITIES

Consistent with its core objective of increasing its reserves as
economically as possible, the Company has commenced a program of identifying and
developing exploratory prospects in areas where the Company or its partners have
expertise. HarCor intends to manage its exploration and economic risks by (i)
generating prospects with the assistance of strategic industry partners that are
experienced in 3-D seismic and computer assisted exploration ("CAEX")
technology, (ii) identifying and pursuing prospects with multiple potential
productive zones, (iii) funding its exploration activities with proceeds from
the Offering and internally generated cash flow and (iv) limiting its cash
exposure to approximately $500,000 for each well. In addition, the Company
intends to further manage the drilling risks associated with the exploration
projects in South Texas and South Louisiana by drilling multipay prospects that
combine shallower lower risk zones that have previously proven productive in the
area with deeper potential target zones. In furtherance of this strategy, the
Company has recently entered into an agreement with South Coast Exploration
Company and its affiliated company Interactive Exploration Solutions, Inc.
(collectively, "South Coast Exploration"), which have extensive experience
utilizing 3-D seismic and CAEX techniques, to jointly pursue exploration
projects on developed and undeveloped properties in South Texas, the Permian
Basin of West Texas and South Louisiana.

5
<PAGE> 6

The Company and South Coast Exploration have jointly formed an experienced
geologic team (the "GeoTeam") to work exclusively to pursue these joint
projects.

The following table sets forth certain information as of May 30, 1996
relating to the exploration prospects that the Company currently plans to pursue
over the 18-month period ending December 31, 1997, including the estimated cost
to the Company for 3-D seismic surveys, leasehold acquisitions and drilling of
exploratory and development wells relating to such prospects through such date.

<TABLE>
<CAPTION>
GROSS ACREAGE
OWNED OR PROSPECTIVE PROSPECTIVE ESTIMATED COST TO COMPANY(3)
UNDER SQUARE MILES OF GROSS -------------------------------------
PROSPECT AREA OPTION(1) 3-D SEISMIC DATA WELLS(2) SEISMIC LAND DRILLING TOTAL
------------- ------------- ---------------- ----------- ------- ------ -------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
South Texas (Upper Wilcox Trend)........ 23,000 83 18 $ 720 $ 640 $ 8,900 $10,260
West Texas (Permian Basin).............. 80,320 210 4 330 480 900 1,710
South Louisiana (Terrebonne Parish)..... 5,529 46 4 235 240 1,300 1,775
--
------- --- ------ ------ ------- -------
Total........................... 108,849 339 26 $1,285 $1,360 $11,100 $13,745
======= === == ====== ====== ======= =======
</TABLE>

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

(1) Includes acreage in which the Company currently has leases, options to
acquire leases, contingent lease rights or fee interests.

(2) Includes 10 exploratory wells and 16 development wells.

(3) The estimated cost to the Company is based on (i) preliminary estimates of
seismic survey costs, leasehold acquisition costs and drilling and
completion costs and (ii) assumed levels of participation by the Company in
the costs thereof. Actual costs and participation levels may vary from such
estimates.

The following sets forth a brief summary of each exploration prospect that
the Company has in progress. This discussion only includes prospects on which
the Company has acquired substantial leasehold interests, options to acquire
leasehold interests or other contingent lease rights and has performed or is in
the process of arranging related 3-D seismic surveys. See "Risk Factors -- Risk
of Exploratory Drilling Activities" for a discussion of the risks associated
with these exploration prospects.

South Texas (Upper Wilcox Trend). HarCor has entered into an agreement with
Cabot to participate in an 83 square mile 3-D seismic survey in southeast
McMullen and northwest Duval Counties, Texas. The expanded and over-pressured
Upper Wilcox Trend in the survey area has significant potential for the
application of 3-D seismic technology due to complex faulting in the area and
stacking of multiple pay zones in both the shallow normal-pressured zones such
as the Cole Sand at 1,600 feet and the over-pressured zones such as the House
Sand at approximately 12,000 feet. The 3-D seismic survey in the Upper Wilcox
Trend commenced in April 1996 and is expected to be completed in July 1996. The
survey is designed to evaluate prospects already identified and generate new
drilling prospects with both development and exploration potential in the area
of the Hostetter Field and the nearby Bonne Terre Field. The survey will
evaluate approximately 40 geologic formations at depths ranging between 8,500
feet and 13,000 feet for the expanded over-pressured Upper Wilcox formation and
as shallow as 1,500 feet for other intervals. HarCor has joined with Cabot to
acquire, or to acquire options for, leasehold interests in 23,000 gross acres
inside the 3-D survey area as of May 30, 1996. Production to date in the survey
area, including production from the Hostetter Field and the Bonne Terre Field,
is estimated to be approximately 450 Bcf of natural gas equivalent. On May 29,
1996, HarCor assigned to South Coast Exploration and one of its affiliates 40%
of its rights in its agreement with Cabot in exchange for the interest it
received in the South Louisiana project described below.

West Texas (Permian Basin). In May 1996, the Company entered into an
agreement to participate in a 210 square mile 3-D seismic survey in Reeves
County, Texas with Penwell Energy, Inc. ("Penwell") which, along with its
investment partner MCN Energy, has extensive recent experience in the Permian
Basin. Penwell initially derived its rights to about half of the area in the
Penwell survey (74,880 fee mineral acres held by Texaco) from an agreement dated
September 1995 among Texaco, Penwell and Meridian Oil Inc. Production in the
field within or adjoining gross acreage in which Penwell presently owns or has
contingent lease rights is estimated to be 455 Bcf of natural gas equivalents,
most of which has been produced from the

6
<PAGE> 7

Silurian/Devonian Fusselman formation at depths between 10,000 feet and 17,000
feet, where the Company intends to focus.

South Louisiana (Terrebonne Parish). South Coast Exploration and its
affiliate have acquired an interest in a 46 square mile 3-D seismic survey to be
conducted in south Terrebonne Parish, Louisiana. To date, the Lapeyrouse Field,
which is located in the survey area, has produced approximately 350 Bcf of
natural gas equivalents. Based upon 2-D seismic surveys and reports from
independent engineers, South Coast Exploration's joint venture preliminarily has
identified potential exploration sites in the area to drill an estimated four
test wells in the next 18 months. Two of these potential exploration sites have
been identified in the Bourg Sands between 14,500 feet and 15,500 feet and the
remaining two potential exploration sites have been identified in traps
associated with faulting in a series of Upper Middle Miocene Sands between
15,000 feet and 17,000 feet. South Coast Exploration and its affiliate have each
assigned to HarCor a portion of their interest in this survey.

SELECTIVE OPPORTUNISTIC ACQUISITIONS

The Company also intends to pursue selective strategic acquisitions of
attractively priced, underexploited onshore oil and gas properties in the United
States. As a consequence of its working relationship with South Coast
Exploration, the Company will also pursue property acquisitions where it can
utilize 3-D seismic and CAEX technology to identify additional potential
reserves. Management intends to continue to be active in developing acquisition
opportunities rather than pursuing opportunities in the auction market.
Management believes that this strategy has resulted in lower acquisition prices
for its oil and gas properties.

7
<PAGE> 8

THE OFFERING

<TABLE>
<S> <C>
Shares of Common Stock Offered:
By the Company(1)........................... 5,059,059 shares
By the Selling Stockholders................. 1,340,941 shares
Total............................... 6,400,000 shares
Shares of Common Stock Outstanding(1)(2):
Before the Offering......................... 8,696,207 shares
After the Offering.......................... 13,755,266 shares
Use of Proceeds............................... To redeem approximately $9.5 million of
principal amount of, together with accrued
interest and prepayment premium on, the
Company's 14 7/8% Senior Notes due 2002; and
to fund 3-D seismic and leasehold
acquisitions, 3-D seismic and CAEX processing
and interpretation, exploratory and
development drilling expenditures and other
general corporate purposes.
Nasdaq National Market Symbol................. "HARC"
</TABLE>

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

(1) Does not include up to 960,000 shares of Common Stock which may be sold by
the Company pursuant to the Underwriters' over-allotment option.

(2) Does not include (i) options to purchase 898,500 shares of Common Stock
which have been granted under the Company's stock option plans and (ii)
1,697,772 shares of Common Stock issuable upon conversion of the Company's
outstanding Series A, B, C and E Preferred Stock. Also does not include
2,289,791 shares of Common Stock issuable upon exercise of outstanding
warrants of the Company. See "Description of Capital Stock and Other
Securities."

8
<PAGE> 9

SUMMARY FINANCIAL DATA

The following table presents summary historical consolidated financial data
of the Company for the five years ended December 31, 1995, which have been
derived from the Company's consolidated financial statements. The consolidated
financial data of the Company for the three months ended March 31, 1995 and 1996
have been derived from the Company's interim consolidated financial statements
which, in the opinion of management of the Company, have been prepared on the
same basis as the annual consolidated financial statements and include all
adjustments (consisting of only normal recurring adjustments) necessary for a
fair presentation of the financial data for such periods. The information in
this table should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Consolidated
Financial Statements and the notes thereto included elsewhere herein.

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
---------------------------------------------------- ------------------
1991 1992 1993 1994 1995 1995 1996
------- ------- ------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA(1):
Revenues:
Oil and gas revenues........................ $ 5,776 $ 6,162 $ 6,507 $10,982 $16,030 $ 3,683 $ 5,956
Gas plant revenues.......................... -- -- -- 1,978 6,362 1,786 1,624
Interest income and other................... 258 504 218 253 203 15 17
------- ------- ------- ------- ------- ------- -------
Total revenues........................ 6,034 6,666 6,725 13,213 22,595 5,484 7,597
------- ------- ------- ------- ------- ------- -------
Costs and expenses:
Production costs............................ 2,670 2,676 2,249 3,610 5,263 1,263 1,437
Gas plant costs............................. -- -- -- 1,708 3,704 1,410 956
Dry hole, impairment and abandonment
costs..................................... 1,287 402 41 75 4 -- --
Engineering and geological costs............ 770 536 188 254 307 89 101
Depletion, depreciation and amortization.... 2,222 2,142 2,641 3,897 5,973 1,346 1,707
General and administrative expenses......... 2,372 2,085 2,105 2,014 2,744 666 721
Interest expense(2)......................... 872 1,048 542 2,269 6,847 1,130 2,642
Other....................................... -- -- -- 203 483 -- 261
------- ------- ------- ------- ------- ------- -------
Total costs and expenses.............. 10,193 8,889 7,766 14,030 25,325 5,904 7,825
------- ------- ------- ------- ------- ------- -------
Loss before minority interests................ (4,159) (2,223) (1,041) (817) (2,730) (421) (228)
Loss attributable to minority interests....... 2,698 809 -- -- -- -- --
Loss attributable to early extinguishment of
debt........................................ -- -- -- (122) (1,888) -- --
------- ------- ------- ------- ------- ------- -------
Net loss...................................... (1,461) (1,414) (1,041) (939) (4,618) (421) (228)
Dividends on preferred stock.................. (40) (32) (246) (795) (1,000) (335) (132)
Accretion on redeemable preferred stock....... -- -- -- (156) (2,147) (81) --
------- ------- ------- ------- ------- ------- -------
Net loss applicable to common stock........... $(1,501) $(1,446) $(1,287) $(1,890) $(7,765) $ (837) $ (360)
======= ======= ======= ======= ======= ======= =======
Net loss applicable to common stock per common
and common equivalent share................. $ (0.50) $ (0.41) $ (0.23) $ (0.29) $ (0.98) $ (0.12) $ (0.04)
Weighted average number of common and
common equivalent shares.................... 2,973 3,512 5,492 6,447 7,904 7,226 8,685
OTHER DATA:
EBITDAX(3).................................... $ 992 $ 1,906 $ 2,371 $ 5,881 $10,884 $ 2,145 $ 4,483
Capital expenditures.......................... 2,593 4,237 4,283 45,608(4) 8,953 18 9,635(5)
</TABLE>

<TABLE>
<CAPTION>
MARCH 31, 1996
--------------------------
ACTUAL AS ADJUSTED(6)
------- --------------
(IN THOUSANDS)
<S> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents.............................................................. $ 3,977 $ 14,319
Total assets........................................................................... 86,770 96,522
Total debt............................................................................. 71,276 61,993
Stockholders' equity................................................................... 9,564 28,774
</TABLE>

9
<PAGE> 10

(1) Includes results of operations in 1991 and 1992 from HCO Energy, Ltd.
("HCO"), the Company's former Canadian affiliate. In December 1992, the
Company deconsolidated HCO, and in January 1993 the Company sold all of its
remaining shares of HCO common stock.

(2) Interest expense includes $29,000, $42,000, $64,000, $220,000 and $709,000
in 1991, 1992, 1993, 1994 and 1995, respectively, and $117,000 and $240,000
in the three months ended March 31, 1995 and 1996, respectively, related to
amortization of deferred financing costs.

(3) EBITDAX represents income (loss) before provision for income tax and
extraordinary items and before depletion, depreciation, amortization,
interest expense, minority interests, non-recurring charges and exploration
expenses. EBITDAX is presented because it is a widely accepted financial
indicator of a company's ability to service and/or incur indebtedness.
However, EBITDAX should not be considered as an alternative to net income
as a measure of operating results or to cash flows as a measure of
liquidity.

(4) Includes $42 million of cash acquisition costs incurred in connection with
the acquisition of the San Joaquin Basin properties.

(5) Includes $8.2 million relating to drilling costs which were accrued but
unpaid at December 31, 1995 resulting from the Company's 1995 drilling
program.

(6) As adjusted to (i) reflect the public offering price of $4.50 per share and
(ii) an extraordinary charge estimated at $1,826,000 relating to early
extinguishment of debt. Does not include (i) options to purchase 898,500
shares of Common Stock which have been granted under the Company's stock
option plans; (ii) 1,697,772 shares of Common Stock issuable upon
conversion of the Company's outstanding Series A, B, C and E Preferred
Stock; and (iii) 2,289,791 shares of Common Stock issuable upon exercise of
outstanding warrants of the Company. See "Description of Capital Stock and
Other Securities." The Company repaid $2 million of the outstanding balance
under the Credit Facility subsequent to March 31, 1996 from cash flow
generated by operations. Pending the use of proceeds from the Offering to
fund certain exploration expenditures, the Company will use approximately
$5.5 million to repay amounts outstanding under the Credit Facility. The
Company will reborrow under the Credit Facility to fund capital
expenditures and operations as necessary. See "Use of Proceeds."

SUMMARY OIL AND GAS RESERVE DATA

The following table sets forth summary information with respect to the
Company's estimated proved oil and gas reserves. The estimates of the Company's
proved reserves and future net revenues were primarily derived from reports
prepared by Ryder Scott. As of December 31, 1993, 1994 and 1995, the average
sales prices used for estimating the proved reserves and future net revenues
were $11.65, $15.86 and $17.10 per Bbl of crude oil and $2.16, $2.11 and $2.35
per Mcf of natural gas, respectively (which prices with respect to natural gas
reflect the effects of the Company's hedging activities). See "Risk
Factors -- Reliance on Estimates of Proved Reserves," "-- Certain Business
Risks" and "Management's Discussion and Analysis of Financial Condition and
Results of Operations." A summary report of Ryder Scott is included as Annex A
hereto.

<TABLE>
<CAPTION>
TOTAL PROVED RESERVES AS OF
DECEMBER 31,
--------------------------------
1993 1994 1995
------- ------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Estimated Proved Reserves:
Liquids (MBbl)............................ -- 2,908 2,979
Crude oil (MBbl).......................... 1,724 10,581 12,358
Natural gas (MMcf)........................ 17,169 69,802 87,637
Crude oil equivalents (MBOE).............. 4,586 25,123 29,943
Pre-tax SEC 10 Value........................ $20,780 $86,680 $124,498
Percent Proved Undeveloped Reserves (BOE)... 39.8% 67.4% 69.4%
</TABLE>

10
<PAGE> 11

SUMMARY OPERATING DATA

The following table sets forth summary information with respect to the
Company's operations for the periods indicated.

<TABLE>
<CAPTION>
THREE MONTHS
ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------ ----------------
1993 1994 1995 1995 1996
----- ----- ------ ------ ------
<S> <C> <C> <C> <C> <C>
Average Net Daily Production:
Crude oil and plant NGLs (Bbls)................. 505 1,128 1,834 1,657 2,450
Natural gas (Mcf)............................... 5,514 9,239 14,074 12,860 19,240
Crude oil equivalents (BOE)..................... 1,424 2,668 4,180 3,800 5,657

Average Sales Price(1):
Crude oil (per Bbl)............................. $16.46 $15.79 $16.49 $16.15 $17.33
Natural gas (per Mcf)........................... $ 1.77 $ 1.82 $ 1.64 $ 1.62 $ 1.86

Cost Data (per BOE)(2):
Average production costs(3)..................... $ 4.41 $ 4.13 $ 3.99 $ 4.14 $ 3.22
Depletion, depreciation and amortization........ $ 5.13 $ 4.14 $ 3.60(4) $ 4.26 $ 3.60
General and administrative expense.............. $ 4.13 $ 2.32 $ 1.80 $ 2.19 $ 1.61
Total Proved Reserves to Production Ratio......... 8.8 25.8 19.6 -- --
Crude Oil and NGLs as a Percentage of Total Proved
Reserve Volumes................................. 37.6% 53.7% 51.2% -- --

Producing Wells (at end of period):
Gross wells..................................... 334 379 424 379 431
Net wells....................................... 104 150 183 150 187
</TABLE>

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

(1) Calculation of average selling price per barrel of crude oil and condensate
excludes certain revenues attributable to hydrocarbon liquids and plant
product sales. All average price data reflect the effects of the Company's
fixed-price sales and hedging contracts. See Note 10 of Notes to the
Consolidated Financial Statements.

(2) Excludes operating costs related to the gas plant.

(3) Includes production and ad valorem taxes.

(4) Excludes the effect of the impairment write-down pursuant to implementation
of SFAS 121 ("Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed of"). See "Management's Discussion and
Analysis of Financial Condition and Results of Operations."

11
<PAGE> 12

RISK FACTORS

Prospective investors should carefully consider the following factors
regarding an investment in the Common Stock.

LEVERAGE AND DEBT SERVICE

As of March 31, 1996, after giving effect to the Offering and the
application of a portion of the net proceeds thereof, the Company's total
long-term debt and stockholders' equity would have been approximately $61
million and $31 million, respectively.

As a result of the Company's indebtedness: (i) the Company incurs
significant interest expense and principal repayment obligations in connection
with its outstanding indebtedness; (ii) the Company's ability to obtain
additional financing in the future, as needed, may be limited; (iii) the
Company's leveraged position and the covenants contained in certain of its debt
agreements could limit the Company's ability to expand and compete; and (iv) the
Company's substantial leverage may make it more vulnerable to economic
downturns, limit its ability to withstand competitive pressures and reduce its
flexibility in responding to changing business and economic conditions.

The Company's ability to pay interest and principal on its outstanding
indebtedness and to satisfy its other debt obligations depends upon its future
operating performance, which will be affected by prevailing economic conditions
and financial, business and other factors, certain of which are beyond its
control. The Company anticipates that its operating cash flow, together with
borrowings available under its $15 million credit facility (the "Credit
Facility") with ING Capital Corporation ("ING Capital"), will be sufficient to
meet its operating needs and to service its debt requirements as they become
due. However, if the Company is unable to service its indebtedness, it will be
forced to pursue one or more alternative strategies such as selling assets,
curtailing its development drilling activities, restructuring or refinancing its
indebtedness or seeking additional equity capital. There can be no assurance
that any of these strategies could be effected on satisfactory terms, if at all.
See "Management's Discussion and Analysis of Results of Operations and Financial
Condition -- Liquidity and Capital Resources."

CAPITAL EXPENDITURES FOR UNDEVELOPED PROPERTIES

As of December 31, 1995, approximately 69.4% of the Company's total proved
reserves on a BOE basis were classified as proved undeveloped. Recovery of such
reserves will require significant capital expenditures and successful drilling
operations. Based on the Company's estimates, aggregate capital expenditures by
the Company of approximately $58.7 million, including $55 million on the San
Joaquin Basin properties, will be required to develop such undeveloped reserves,
of which $12.1 million and $12 million are expected to be incurred during the
remainder of 1996 and in 1997, respectively. The Company intends to finance the
development of its properties out of the proceeds from the Offering and cash
from operations and, to the extent necessary, borrowings under the Credit
Facility. There can be no assurance that the Company's estimates of capital
expenditures will prove accurate, that such sources of financing will be
sufficient to fully fund the Company's planned development activities or that
the development activities will be either successful or completed in accordance
with the Company's development schedule. Additionally, any decrease in oil and
gas prices or any increase in the costs of development of the Company's
properties could result in a significant reduction in the number of wells
expected to be drilled. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."

RISK OF EXPLORATORY DRILLING ACTIVITIES

The ability of the Company to add reserves in a cost-effective manner will
be in part dependent upon the success of its exploratory drilling program, which
will be funded in part with the proceeds from this Offering. Although the
Company has significant experience in the development and production of oil and
natural gas, the Company has a limited history of conducting exploratory
drilling. In that regard, the ability of the Company to pursue its exploratory
drilling program is dependent on a number of factors, including (i) favorable
results of 3-D seismic surveys, (ii) the availability of leases on favorable
terms and permitting for

12
<PAGE> 13

the prospects, (iii) the availability of future capital resources by the Company
and the other participants for the purchasing of leases and the drilling of
prospects, (iv) the approval of other participants to the purchasing of leases
and the drilling of wells on the prospects and (v) the economic conditions at
the time of drilling, including the prevailing and anticipated prices for
natural gas. Additionally, although the Company's prospects are located within
geographic areas in which significant quantities of natural gas equivalents have
been produced, the proximity to other successful exploratory or development
wells provides no assurance that any particular well will be successful due to
the complex faulting and fracturing of oil and gas formations and the inherent
risks and uncertainties of exploratory drilling. Exploratory drilling is subject
to numerous risks, including the risk that no commercially productive oil and
natural gas reservoirs will be encountered. The cost of drilling, completing and
operating wells is often uncertain, and drilling operations may be curtailed,
delayed or canceled as a result of a variety of factors, including unexpected
formation and drilling conditions, pressure or other irregularities in
formations, equipment failures or accidents, as well as weather conditions,
compliance with governmental requirements and shortages or delays in the
delivery of equipment. In addition, the Company's strategy of focusing on
exploratory drilling for larger reserves using 3-D seismic and CAEX technology
requires greater pre-drilling expenditures than alternative forms of traditional
drilling strategies. Although the Company believes that its use of 3-D seismic
and CAEX technology will increase the probability of success of its exploratory
wells and should reduce average finding costs through the elimination of
prospects that might otherwise be drilled solely on the basis of 2-D seismic
data and other traditional methods, unsuccessful wells are likely to occur and
there can be no assurance as to the future success of the Company's drilling
program, especially in light of the Company's limited exploratory drilling
experience. See "Business and Properties."

HISTORY OF LOSSES

For its fiscal years ended December 31, 1991, 1992, 1993, 1994 and 1995 and
the three months ended March 31, 1996, the Company incurred operating losses
(before dividends and accretion on preferred stock) of $1,461,000, $1,414,000,
$1,041,000, $939,000, $4,618,000 and $228,000, respectively. There can be no
assurance that the Company will be profitable in the future. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the Consolidated Financial Statements and Notes thereto.

VOLATILITY OF OIL AND GAS PRICES AND MARKETS

The Company's revenues and earnings are dependent upon prevailing prices
for oil and gas. The prices for oil and gas historically have been volatile and
are subject to wide fluctuations in response to changes in the supply of and
demand for oil and gas, market uncertainties and a variety of additional factors
beyond the control of the Company. These factors include the level of consumer
product demand, weather conditions, domestic and foreign governmental
regulation, political conditions in the Middle East, the foreign supply of oil
and gas, the price and availability of alternative fuels and overall oil and gas
market conditions. It is impossible to predict future oil and gas price
movements with any certainty. Although the Company hedges a substantial portion
of its production which provides some protection from price declines, any
substantial or extended decline in the price of oil and gas would have a
material adverse effect on the Company's financial condition and results of
operations, as well as reduce the amount of the Company's oil and gas that could
be produced economically. The posted price for West Texas Intermediate crude oil
(the "WTI price") varied during 1995 from a high of $19.00 per Bbl in April
1995, to a low of $15.00 per Bbl in July 1995. The price for 40() gravity crude
oil in the Lost Hills Field (the location of most of the Company's San Joaquin
Basin properties) as stated in the Chevron U.S.A. Products Company Crude Oil
Price Bulletin varied during 1995 from a high of $18.10 per Bbl in April 1995 to
a low of $15.85 per Bbl in October 1995. Market prices received for crude oil
sold in California have in the recent past been generally lower than WTI prices
for similar quality oil as a result of certain market and regulatory conditions
particular to the California market, including (i) a foreign export ban on
Alaskan oil which results in the supply of most of such oil to the California
market, (ii) the lack of pipelines to transport large quantities of oil produced
in California to other states which limits the ability of producers to respond
to price imbalances between California and other domestic markets and (iii)
fewer independent refiners in California than in other oil producing states
which results in less competition among

13
<PAGE> 14

crude oil purchasers in California than in other domestic markets. The posted
price for gas at Henry Hub, Louisiana ("Henry Hub price") varied during 1995
from a high of $2.28 per MMBtu in December 1995 to a low of $1.38 per MMBtu in
August 1995. The Southern California border monthly average price for natural
gas as stated in the Natural Gas Intelligence Gas Price Index varied during 1995
from a high of $1.63 per MMBtu in January 1995 to a low of $1.25 per MMBtu in
July 1995. Market prices received for gas sold in the California market during
1996 have been generally similar to Henry Hub prices. Due to fairly stable
demand as a result of stable weather conditions in California, gas prices in
California do not generally experience fluctuations during the winter and summer
months as large as those experienced by Henry Hub prices.

Declines in oil and gas prices, if sustained, could require a writedown of
the book value of the Company's oil and gas properties unless the Company has
sufficient net additions in reserves and/or production to offset the decline in
oil and gas prices. Such declines, if sustained, could also result in a
reduction in the Company's borrowing base under its Credit Facility, requiring
the Company to repay the amount by which outstanding advances exceed the
redetermined borrowing base.

RISKS OF FIXED PRICE SALES AND HEDGING CONTRACTS

The Company manages the risk associated with fluctuations in the price of
gas, and to a lesser extent oil, primarily through certain fixed price sales and
hedging contracts. The Company's price risk management strategy reduces the
Company's sensitivity to changes in market prices of oil and gas, but is subject
to a number of other risks. If the Company's reserves are not produced at the
rates estimated by the Company due to inaccuracies in the reserve estimation
process, operational difficulties or regulatory limitations, the Company would
be required to satisfy its obligations under fixed price sales and hedging
contracts on potentially unfavorable terms without the ability to hedge such
risk through sales of comparable quantities of its own production. Further, the
terms under which the Company enters into fixed price sale and hedging contracts
are based on assumptions and estimates of numerous factors such as cost of
production and pipeline and other transportation costs to delivery points.
Substantial variations between the assumptions and estimates used by the Company
and actual results experienced could materially adversely affect the Company's
anticipated profit margins and its ability to manage in the future the risk
associated with fluctuations in oil and gas prices. Additionally, the fixed
price sales and hedging contracts limit the benefits the Company will realize if
actual prices rise above the contract prices.

In addition, fixed price sales and hedging contracts are subject to the
risk that the counterparty may prove unable or unwilling to perform its
obligations under such contracts. Currently, an affiliate of ING Capital is the
counterparty for a significant portion of the Company's hedging contracts.
Although the Company has not experienced and does not anticipate significant
nonperformance by counterparties, such significant nonperformance could have a
material adverse financial effect on the Company.

As of March 31, 1996, the Company had approximately 45% of its oil
production and approximately 42% of its gas production committed to sales and
hedging contracts based on first quarter 1996 production.

RELIANCE ON ESTIMATES OF PROVED RESERVES

There are numerous uncertainties inherent in estimating quantities of
proved oil and gas reserves, including many factors beyond the control of the
Company. Certain events, including changes in oil and gas prices, production,
acquisitions and future drilling and development, could result in increases or
decreases in estimated proved quantities of oil and gas reserves. In addition,
estimates of the Company's quantities of proved oil and gas reserves, future net
revenues from proved reserves and the present value thereof are based on certain
assumptions regarding future oil and gas prices, production levels and operating
and development costs that may not prove to be correct. In particular, estimates
of proved oil and gas reserves, future net revenues from proved reserves and the
present value thereof for the Company's oil and gas properties as of December
31, 1995 included in this Prospectus are based on the assumption that future oil
and gas prices remain the same as oil and gas prices at December 31, 1995. As of
December 31, 1995, the average sales prices used for purposes of such estimates
were $17.21 per Bbl of oil and $2.35 per Mcf of gas with respect to the San
Joaquin Basin properties and $17.69 per Bbl of oil and $1.91 per Mcf of gas with
respect to the

14
<PAGE> 15

Company's other properties in the aggregate. Average oil prices with respect to
the San Joaquin Basin properties and the Company's other properties were, for
the year ended December 31, 1995, lower than oil prices at December 31, 1995,
with average oil prices realized by the Company of $16.85 per Bbl and $15.78 per
Bbl, respectively. Average gas prices for the San Joaquin Basin properties and
the Company's other properties were, for the year ended December 31, 1995, lower
than those received at year-end 1995, with average gas prices realized by the
Company of $1.74 per Mcf and $1.46 per Mcf, respectively. Also assumed is the
Company's planned expenditures of approximately $60.7 million in future capital
expenditures, including $55 million on the San Joaquin Basin properties,
necessary to develop and realize the value of its proved undeveloped reserves.
Any significant variance in these assumptions could materially affect the
estimated quantity and value of reserves set forth herein. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."

DEPENDENCE ON LOCAL OPERATORS

None of the Company's oil and gas properties are operated by the Company.
As a result, the Company has limited control over the manner in which operations
are conducted on such properties, including the safety and environmental
standards used in connection therewith. Pursuant to the operating agreements
governing operations on the properties in which the Company has an interest, the
Company maintains significant influence or control over the nature and timing of
exploration and development activities on the majority of its properties. Such
agreements do not, however, allow the Company such influence or control with
respect to a portion of its properties; in such cases, the operators of such
properties generally have control with respect to the nature and timing of
exploration or development activities. In such instances, the operators of such
properties could undertake exploration or development projects at a time when
the Company does not have the funds required to finance its share of the costs
of such projects. In such event, pursuant to the operating agreements relating
to properties in which the Company has an interest, the other parties to such
agreements who fund their shares of the cost of such a project are generally
entitled to receive all cash flow from such project, subject to rights of third
party royalty or other interest owners, until they have recovered a multiple of
the costs of such project (usually 300% to 400%) prior to the Company's receipt
of any production or revenues from such project or, in the event drilling is
necessary to maintain certain leasehold interests, the Company may be required
to forfeit its interests in such projects. Conversely, the operators of such
properties could refuse to initiate exploration or development projects, in
which case the Company would be required to propose such activities and may be
required to proceed with such activities at much higher levels of participation
than expected and without receiving any funding from the other interest owners
or the operators may initiate exploration or development projects on a slower
schedule than that preferred by the Company. Any of these events could have a
significant effect on the Company's anticipated exploration and development
activities and financing thereof. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."

OPERATING HAZARDS AND UNINSURED RISKS

The Company's operations are subject to risks inherent in the oil and gas
industry, such as blowouts, cratering, explosions, uncontrollable flows of oil,
gas or well fluids, fires, pollution and other environmental risks. These risks
could result in substantial losses to the Company due to injury and loss of
life, severe damage to and destruction of property and equipment, pollution and
other environmental damage and suspension of operations. In accordance with
customary industry practice, the Company is not fully insured against all risks
incident to its business. Because of the nature of industry hazards, it is
possible that liabilities for pollution and other damages arising from a major
occurrence could exceed insurance coverage or policy limits. Any such
liabilities could have a materially adverse effect on the Company.

CERTAIN BUSINESS RISKS

The Company intends to continue acquiring oil and gas properties. Although
the Company performs a review of the properties to be acquired that it believes
is consistent with industry practices, such reviews are inherently incomplete.
Generally, it is not feasible to review in-depth every individual property
involved in

15
<PAGE> 16

each acquisition. Ordinarily, the Company will focus its review efforts on the
higher-valued properties and will sample the remainder. However, even an
in-depth review of all properties and records may not necessarily reveal
existing or potential problems nor will it permit a buyer to become sufficiently
familiar with the properties to assess fully their deficiencies and
capabilities. Inspections may not always be performed on every well, and
environmental problems, such as ground water contamination, are not necessarily
observable even when an inspection is undertaken. Furthermore, the Company must
rely on information, including financial, operating and geological information,
provided by the seller of the properties without being able to verify fully all
such information and without the benefit of knowing the history of operations of
all such properties.

In addition, a high degree of risk of loss of invested capital exists in
almost all exploration and development activities which the Company undertakes.
No assurance can be given that oil or gas will be discovered to replace reserves
currently being developed, produced and sold, or that if oil or gas reserves are
found, they will be of a sufficient quantity to enable the Company to recover
the substantial sums of money incurred in their acquisition, discovery and
development. Drilling activities are subject to numerous risks, including the
risk that no commercially productive oil or gas reservoirs will be encountered.
The cost of drilling, completing and operating wells is often uncertain. The
Company's operations may be curtailed, delayed or cancelled as a result of
numerous factors including title problems, weather conditions, compliance with
governmental requirements and shortages or delays in the delivery of equipment.
The availability of a ready market for the Company's gas production depends on a
number of factors, including, without limitation, the demand for and supply of
natural gas, the proximity of gas reserves to pipelines, the capacity of such
pipelines and government regulations. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Liquidity and Capital
Resources" and "Business and Properties."

DEPENDENCE ON KEY PERSONNEL

The success of the Company will depend almost entirely upon the ability of
a small group of key executives to manage the business of the Company. Should
one or more of these executives leave the Company or become unable to perform
his duties, no assurance can be given that the Company will be able to attract
competent new management. The Company maintains a $10 million key man life
insurance policy on Mark G. Harrington, the proceeds of which are payable to the
Company.

COMPETITION

The acquisition, exploration and development of oil and gas properties is a
highly competitive business. Many companies and individuals are engaged in the
business of acquiring interests in and developing onshore oil and gas properties
in the United States. The industry is not dominated by any single competitor or
a small number of competitors. The Company competes with major and independent
oil and gas companies for the acquisition of desirable oil and gas properties,
as well as for the equipment and labor required to operate and develop such
properties. Many of these competitors have financial and other resources
substantially in excess of those available to the Company. Such competitive
disadvantages could adversely affect the Company's ability to acquire desirable
properties or to develop existing properties.

GOVERNMENTAL REGULATION

The Company's business is subject to certain federal, state and local laws
and regulations relating to the exploration for and development and production
of oil and gas, as well as environmental and safety matters. Such laws and
regulations have generally become more stringent in recent years, often imposing
greater liability on a larger number of potentially responsible parties. Because
the requirements imposed by such laws and regulations are frequently changed,
the Company is unable to predict the ultimate cost of compliance with such
requirements and their effect on the Company. See "Business and
Properties -- Regulation."

16
<PAGE> 17

USE OF PROCEEDS

The net proceeds to the Company from the sale of the shares of Common Stock
offered hereby, after deducting underwriters' discounts and commissions and
estimated expenses of the Offering, are estimated to be approximately $21
million ($25 million if the Underwriters' over-allotment option is exercised in
full).

The purpose of the Offering is to further strengthen the Company's
financial position and to provide it with the financial flexibility necessary to
implement its business strategy. The Company is obligated and intends to use 50%
of the net proceeds (estimated to be approximately $10.6 million to redeem $9.5
million in principal amount of its outstanding $65 million of senior notes due
2002 (the "Senior Notes") at a price equal to 110% of the principal amount of
such Senior Notes plus accrued and unpaid interest thereon (estimated to be
approximately $400,000). The Senior Notes mature on July 15, 2002 and bear
interest at the rate of 14 7/8% per annum. The resulting reduction in interest
costs should permit the Company to devote an increased portion of its cash flow
to efforts to expand its reserve base. See "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Financing Activities."

The balance of the proceeds from the Offering (estimated to be
approximately $10.4 million), the Company's cash flow from operations and
borrowings from available capacity under the Credit Facility will be used to
finance the Company's anticipated capital expenditures to implement its
exploration and development program in South Texas, West Texas and South
Louisiana, utilizing advanced 3-D seismic and CAEX technology, for the remainder
of 1996 and in 1997. Based on current plans, the Company expects to make capital
expenditures with respect to its exploratory prospects of approximately $14.3
million during the next 18 months, of which approximately $3.2 million is
expected to be spent during the second half of 1996, and approximately $11.1
million is expected to be spent during 1997. See "Business and Properties" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."

Prior to funding its exploration program, the Company will use
approximately $5.5 million to repay amounts outstanding under the Credit
Facility. Such repayment will not affect the borrowing availability of the
Company under the Credit Facility. The Company anticipates that it will reborrow
under the Credit Facility to finance a portion of its exploration and
development program. Amounts outstanding under the Credit Facility bear interest
at an adjusted Eurodollar rate plus 2.5%. The effective interest rate under the
Credit Facility at March 31, 1996 was 8.125%. Unless otherwise renewed by mutual
agreement, amounts outstanding under the Credit Facility will convert to a term
loan on September 30, 1997, with a set amortization schedule of a percentage of
the outstanding principal continuing through December 31, 2000.

The Company currently estimates that the net proceeds to the Company from
the Offering will be at least $20.8 million. Pursuant to the terms of the Series
E Preferred Stock, if the holder of the Series E Preferred Stock does not
otherwise convert all of the 30,000 shares of Series E Preferred Stock
outstanding at $3.50 per share into 857,143 shares of Common Stock, the Series E
Preferred Stock is required to be redeemed by the Company in cash, at a price of
$110 per share plus accrued and unpaid dividends. The aggregate amount necessary
to redeem all of the 30,000 shares of Series E Preferred Stock outstanding is
$3.3 million. Any amount used to redeem the Series E Preferred Stock will reduce
(i) the amount of the net proceeds available from the Offering to finance the
Company's anticipated capital expenditures to implement its exploration and
development program described above and (ii) the amount that will be used to
temporarily repay amounts outstanding under the Credit Facility. The Company has
not been advised by the holder of the Series E Preferred Stock whether or not it
intends to convert all of its shares of the Series E Preferred Stock at $3.50
per share into 857,143 shares of Common Stock prior to the mandatory redemption
of the Series E Preferred Stock. See "Description of Capital Stock and Other
Securities."

17
<PAGE> 18

CAPITALIZATION

The following table sets forth the total consolidated capitalization of the
Company at March 31, 1996, and as adjusted (i) to give effect to the
consummation of the Offering (including the issuance and sale of 5,059,059
shares of Common Stock by the Company at the offering price of $4.50 per share
and (ii) the application of the estimated net proceeds to the Company therefrom,
as described under "Use of Proceeds." This table should be read in conjunction
with the consolidated financial statements of the Company and the related notes
and other financial information included elsewhere in this Prospectus.

<TABLE>
<CAPTION>
MARCH 31, 1996
------------------------
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
Cash and cash equivalents..................................... $ 3,977 $ 14,319
======== =========
Total debt, including current maturities:
Credit Facility(1).......................................... 7,500 7,500
14 7/8% Senior Secured Notes due 2002....................... 63,180 53,897
Other....................................................... 596 596
-------- -----------
Total debt.......................................... 71,276 61,993
-------- -----------
Stockholders' equity:
Preferred stock, $.01 par value -- 1,500,000 shares
authorized; 65,000 shares outstanding (35,000 shares
outstanding
as adjusted)............................................. 1 1
Common Stock, $.10 par value -- 25,000,000 shares authorized;
8,696,207 shares outstanding(2); 13,755,266 shares
outstanding as adjusted(2).................................. 870 1,376
Additional paid-in capital.................................... 28,734 49,264
Accumulated deficit(3)........................................ (20,041) (21,866)
-------- -----------
Total stockholders' equity.......................... 9,564 28,774
-------- -----------
Total capitalization................................ $ 80,840 $ 90,770
======== =========
</TABLE>

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

(1) The Company repaid $2 million of the outstanding balance under the Credit
Facility subsequent to March 31, 1996 from cash flow generated by
operations. Pending the use of proceeds from the Offering, to fund certain
exploration expenditures the Company will use approximately $5.5 million to
repay amounts outstanding under the Credit Facility. The Company will
reborrow under the Credit Facility to fund capital expenditures and
operations as necessary. See "Use of Proceeds."

(2) Does not include (i) options to purchase 898,500 shares of Common Stock
which have been granted under the Company's stock option plans; (ii)
1,697,772 shares of Common Stock issuable upon conversion of the Company's
outstanding Series A, B, C and E Preferred Stock; and (iii) 2,289,791 shares
of Common Stock issuable upon exercise of outstanding warrants of the
Company. See "Description of Capital Stock and Other Securities."

(3) As adjusted includes an extraordinary charge estimated at $1,826,000
relating to early extinguishment of debt.

18
<PAGE> 19

PRICE RANGE OF COMMON STOCK

The Common Stock trades on the Nasdaq National Market ("NASDAQ") under the
symbol "HARC." Quotations of the sales volume and the closing sales prices of
the Common Stock are listed daily in NASDAQ's national market listings. The
following table sets forth the range of high and low sale prices of the Common
Stock as quoted by NASDAQ's monthly statistical report for the periods
indicated.

<TABLE>
<CAPTION>
HIGH LOW
----- -----
<S> <C> <C>
1996
Third Quarter (through July 25, 1996).............................. $6.25 $4.38
Second Quarter..................................................... $5.13 $4.06
First Quarter...................................................... $5.38 $2.31
1995
Fourth Quarter..................................................... $3.38 $1.88
Third Quarter...................................................... $3.50 $2.50
Second Quarter..................................................... $4.38 $2.75
First Quarter...................................................... $4.38 $2.88
1994
Fourth Quarter..................................................... $4.25 $2.75
Third Quarter...................................................... $4.25 $3.00
Second Quarter..................................................... $4.13 $3.25
First Quarter...................................................... $4.13 $3.13
</TABLE>

On July 25, 1996, the closing sale price for the Common Stock as reported
by NASDAQ was $5.00 per share. As of April 23, 1996, the Company had
approximately 1,746 stockholders of record. None of the Company's warrants or
preferred stock trade on any public trading market.

DIVIDEND POLICY

The Company has never paid and does not currently intend to pay dividends
on its Common Stock, and pursuant to the terms of the Company's Credit Facility
and the Senior Notes, it is currently restricted from the payment of dividends
on its Common Stock (except dividends paid in shares of Common Stock).
Additionally, pursuant to the terms of the Company's outstanding preferred
stock, the Company is restricted from the payment of dividends on its Common
Stock (except dividends paid in shares of Common Stock) unless the Company is
current in its payment of dividends on such preferred stock.

19
<PAGE> 20

DILUTION

The net tangible book value of the Common Stock at March 31, 1996 was
$9.564 million or $1.10 per share. The net tangible book value per share
represents the amount of the Company's total tangible assets less the Company's
total liabilities (excluding deferred tax liabilities) divided by the number of
shares of Common Stock outstanding. After giving effect to the sale of the
shares of Common Stock offered by the Company (at the public offering price of
$4.50 per share and after deducting estimated underwriters' discounts and
offering expenses of approximately $1.73 million), at March 31, 1996 the pro
forma net tangible book value of the Common Stock would have been $28.8 million
or $2.09 per share, representing an immediate decrease in net tangible book
value of $2.41 per share to new stockholders. Dilution in net tangible book
value represents the difference between the price per share to be paid by
purchasers of the shares of Common Stock offered in this Offering and the pro
forma net tangible book value as of March 31, 1996, as illustrated by the
following per share amounts.

<TABLE>
<S> <C>
Assumed public offering price...................................... $ 4.50
Net tangible book value at March 31, 1996........................ 1.10
Increase attributable to new stockholders........................ .99
Adjusted net tangible book value after Offering, before debt
repayment........................................................ 2.09
Dilution to new stockholders....................................... 2.41
</TABLE>

The foregoing information excludes (i) 898,500 shares of Common Stock
issuable pursuant to stock options that have been granted under the Company's
stock option plans; (ii) an additional 656,500 shares of Common Stock, which may
be granted in the future under such plans; (iii) 1,697,772 shares of Common
Stock issuable upon conversion of outstanding preferred stock; (iv) 2,289,791
shares of Common Stock issuable upon exercise of outstanding warrants of the
Company; and (v) the use of proceeds from the Offering. See "Shares Eligible for
Future Sale."

20
<PAGE> 21

SELECTED FINANCIAL DATA

The historical financial data presented below for the five years ended
December 31, 1995 are derived from the Company's audited financial statements.
Such audited financial statements were examined by Arthur Andersen LLP, with the
exception of the 1991 and 1992 financial data with respect to HCO Energy, Ltd.,
the Company's former Canadian affiliate, which were examined by Peat Marwick
Thorne. The historical data for the three-month periods ended March 31, 1995 and
1996 are derived from the unaudited financial statements of the Company. In the
opinion of management, such unaudited financial statements include all
adjustments (consisting of only normal recurring adjustments) necessary for a
fair presentation of the financial data for such periods. The information in
this table should be read in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the Consolidated
Financial Statements and the notes thereto included elsewhere herein.

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
---------------------------------------------------- ------------------
1991 1992 1993 1994 1995 1995 1996
------- ------- ------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA(1):
Revenues:
Oil and gas revenues............................... $ 5,776 $ 6,162 $ 6,507 $10,982 $16,030 $ 3,683 $ 5,956
Gas plant revenues................................. -- -- -- 1,978 6,362 1,786 1,624
Interest income and other.......................... 258 504 218 253 203 15 17
------- ------- ------- ------- ------- ------- -------
Total revenues............................... 6,034 6,666 6,725 13,213 22,595 5,484 7,597
------- ------- ------- ------- ------- ------- -------
Costs and expenses:
Production costs................................... 2,670 2,676 2,249 3,610 5,263 1,263 1,437
Gas plant costs.................................... -- -- -- 1,708 3,704 1,410 956
Dry hole, impairment and abandonment costs......... 1,287 402 41 75 4 -- --
Engineering and geological costs................... 770 536 188 254 307 89 101
Depletion, depreciation and amortization........... 2,222 2,142 2,641 3,897 5,973 1,346 1,707
General and administrative expenses................ 2,372 2,085 2,105 2,014 2,744 666 721
Interest expense(2)................................ 872 1,048 542 2,269 6,847 1,130 2,642
Other.............................................. -- -- -- 203 483 -- 261
------- ------- ------- ------- ------- ------- -------
Total costs and expenses..................... 10,193 8,889 7,766 14,030 25,325 5,904 7,825
------- ------- ------- ------- ------- ------- -------
Loss before minority interests....................... (4,159) (2,223) (1,041) (817) (2,730) (421) (228)
Loss attributable to minority interests.............. 2,698 809 -- -- -- -- --
Loss attributable to early extinguishment of debt.... -- -- -- (122) (1,888) -- --
------- ------- ------- ------- ------- ------- -------
Net loss............................................. (1,461) (1,414) (1,041) (939) (4,618) (421) (228)
Dividends on preferred stock......................... (40) (32) (246) (795) (1,000) (335) (132)
Accretion on redeemable preferred stock.............. -- -- -- (156) (2,147) (81) --
------- ------- ------- ------- ------- ------- -------
Net loss applicable to common stock.................. $(1,501) $(1,446) $(1,287) $(1,890) $(7,765) $ (837) $ (360)
======= ======= ======= ======= ======= ======= =======
Net loss applicable to common stock per common and
common equivalent share............................ $ (0.50) $ (0.41) $ (0.23) $ (0.29) $ (0.98) $ (0.12) $ (0.04)
Weighted average number of common and
common equivalent shares........................... 2,973 3,512 5,492 6,447 7,904 7,226 8,685
OTHER DATA:
EBITDAX(3)........................................... $ 992 $ 1,906 $ 2,371 $ 5,881 $10,884 $ 2,145 $ 4,483
Capital expenditures................................. 2,593 4,237 4,283 45,608(4) 8,953 18 9,635(5)
BALANCE SHEET DATA (END OF PERIOD):
Cash and cash equivalents.......................... $ 389 $ 929 $ 2,162 $ 899 $12,204 $ 1,653 $ 3,977
Total assets....................................... 15,586 12,580 17,937 68,573 94,231 67,150 86,770
Total debt......................................... 10,427 7,100 8,541 39,400 69,087 39,400 71,276
Stockholders' equity............................... 1,798 4,645 7,536 15,353 10,215 14,748 9,564
</TABLE>

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

(1) Includes results of operations in 1991 and 1992 from the Company's Canadian
operations. In December 1992, the Company deconsolidated HCO, and in January
1993, the Company sold all of its remaining shares of HCO common stock.

(3) EBITDAX represents income (loss) before provision for income tax and
extraordinary items and before depletion, depreciation, amortization,
interest expense, minority interests, non-recurring charges and exploration
expenses. EBITDAX is presented because it is a widely accepted financial
indicator of a company's ability to service and/or incur indebtedness.
However, EBITDAX should not be considered as an alternative to net income as
a measure of operating results or to cash flows as a measure of liquidity.

(4) Includes $42 million of cash acquisition costs incurred in connection with
the acquisition of the San Joaquin Basin properties.

(5) Includes $8.2 million relating to drilling costs which were accrued but
unpaid at December 31, 1995 resulting from the Company's 1995 drilling
program.

21
<PAGE> 22

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

OVERVIEW

Since acquiring control of HarCor in 1987, management has grown the Company
significantly, increasing its reserve base from 1.35 MMBOE at January 1, 1990 to
29.9 MMBOE at January 1, 1996, primarily through selective acquisitions of oil
and gas properties. Historically, the Company has financed its growth
predominantly with debt and preferred stock, which generally require regular
principal and interest payments or dividend payments, as the case may be. As a
result of the cash requirements of the debt and preferred stock, the Company's
early acquisition strategy focused on proved producing properties which would
provide relatively stable cash flow, while at the same time providing
exploitation potential beyond the estimated proved reserves.

In June 1994, the Company acquired 75% of Bakersfield Energy's interests in
the Lost Hills Field and a 23 MMcf per day gas processing plant in the San
Joaquin Basin of California for approximately $46 million, consisting of $42
million in cash and a combination of preferred stock, common stock and warrants.
To finance the cash portion of the purchase price, the Company increased its
borrowings under its existing credit facility and issued a combination of
preferred stock, common stock and warrants.

To further improve its liquidity and ability to develop its San Joaquin
Basin properties, in July 1995 the Company consummated the sale of 65,000 units
consisting of $65 million aggregate principal amount of its 14 7/8% Senior Notes
due in the year 2002 and warrants to purchase 1,430,000 shares of common stock.
The Company used the net proceeds of approximately $61 million to repay an
aggregate of $39.3 million outstanding under its credit agreement and bridge
loan with ING Capital; redeem $10.9 million in outstanding shares of Series D
Preferred Stock which were issued in connection with the acquisition of the San
Joaquin Basin properties and acquire interests in additional producing wells in
the San Joaquin Basin properties for $2.3 million. The Company used the balance
of the proceeds to finance a portion of the development of the San Joaquin Basin
properties over the remainder of 1995.

In order to protect against the effects of declines in oil and gas prices
and maintain predictable cash flow to service its outstanding debt, the Company
generally enters into either fixed-price sales or hedging contracts covering
significant portions of the Company's estimated future production. The Company
believes that its hedging strategy has allowed it to grow more rapidly by
providing more predictable cash flows with which to finance its acquisitions and
development drilling activities. As of March 31, 1996, the Company was a party
to various gas contracts covering volumes of approximately 1.8 Bcf and 1.2 Bcf
for 1996 and 1997, respectively, at prices ranging from $1.68/MMBtu to
$2.07/MMBtu; a gas contract covering 2.2 Bcf for 1996 and 2.2 Bcf for 1997 which
fixes volumes to be sold at $0.3675 less than the NYMEX gas future price for
each month; and oil hedges covering notional volumes of approximately 243 MBOE
and 98 MBOE for 1996 and 1997, respectively, at prices ranging from $15.80/Bbl
to $18.75/Bbl. As of March 31, 1996 the Company had approximately 45% of its oil
production and approximately 42% of its gas production committed to sales and
hedging contracts based on first quarter 1996 production.

COMPARISON OF RESULTS FOR THE THREE MONTHS ENDED MARCH 31, 1996 AND 1995

Revenues. The Company's total revenues increased $2,113,000 (39%) from
$5,484,000 in the first quarter of 1995 to $7,597,000 in the first quarter of
1996.

The Company's oil and gas revenues increased $2,273,000 (62%) from
$3,683,000 in the first three months of 1995 to $5,956,000 in the same period in
1996. Oil revenues increased $940,000 (52%) from $1,801,000 in the first quarter
of 1995 to $2,741,000 in the same period in 1996 due to higher oil production
and slightly higher prices. Oil production increased 46,700 barrels (42%) from
111,500 barrels in the first three months of 1995 to 158,200 barrels in the same
period in 1996. The increased production was primarily a result of the continued
drilling and development of the San Joaquin Basin properties, which contributed
an incremental 48,600 barrels during the first quarter of 1996 as compared to
the first quarter of 1995. Oil production from the Company's Permian and other
properties declined slightly (1,900 barrels) in the

22
<PAGE> 23

aggregate due to normal production declines. The average price received for oil
was $17.33 per barrel during the first quarter of 1996 compared to $16.15 per
barrel for the same period in 1995.

The Company's gas revenues increased $1,332,000 (71%) from $1,883,000 in
the first three months of 1995 to $3,215,000 in the same period in 1996 also due
to increased production and higher prices. Gas production increased 574,000 Mcf
(50%) from 1,157,000 Mcf in the first quarter of 1995 to 1,731,000 Mcf in the
first quarter of 1996 primarily due to the continued drilling and development of
the San Joaquin Basin properties, which contributed an incremental 523,000 Mcf
during the first quarter of 1996 as compared to the first quarter of 1995. Gas
production from the Company's South Texas properties increased 50,000 Mcf during
the first quarter of 1996 primarily due to the drilling of an additional
development well, while gas production from the Company's Permian and other
properties remained flat from period to period. Average prices received for gas
were $1.86 per Mcf in the first quarter of 1996 as compared to $1.62 per Mcf in
the first three months of 1995.

During the first quarter of 1996, the Company realized revenues of
$1,624,000 from its natural gas processing plant. These revenues consisted of
$1,131,000 from the sale of 2,615,000 gallons of processed natural gas liquids
(NGLs), $468,000 from the resale of natural gas purchased from third parties,
and $25,000 in gas processing fees. During the first quarter of 1995, the
Company realized revenues of $1,785,000 from the natural gas plant, consisting
of $1,139,000 in the resale of natural gas purchased from third parties,
$622,000 from the sale of 1,561,000 gallons of NGLs, and $24,000 in gas
processing fees. Although total gas plant revenues decreased slightly in the
first quarter of 1996, the plant's net operating margin increased $293,000 (78%)
due to an increase in NGLs sales as a result of higher lease production.

The Company realized total interest and other income of approximately
$17,000 in the first quarter of 1996 as compared to $15,000 during the first
three months of 1995.

Costs and Expenses. Total costs and expenses increased $1,920,000 (32%)
from $5,904,000 in the first quarter of 1995 to $7,824,000 in the first quarter
of 1996.

The Company's production costs increased $174,000 (14%) from $1,263,000 in
the first three months of 1995 to $1,437,000 in the first quarter of 1996. This
was primarily due to the continuing development of the San Joaquin Basin
properties and resulting increase in number of producing wells in that area.
Production costs on the Company's South Texas and Permian properties decreased
slightly in the first quarter of 1996. Average production cost decreased to
$3.22 per BOE in the first quarter of 1996 as compared to $4.14 per BOE in the
first quarter of 1995.

During the first quarter of 1996, the Company incurred costs of $956,000
resulting from the operations of its natural gas processing plant. These costs
included $359,000 from the purchase of natural gas for processing and resale and
$597,000 of direct operating expenses. During the first quarter of 1995, the
Company incurred costs of $1,410,000 in the operations of its natural gas
processing plant, consisting of $958,000 from the purchase of natural gas for
processing and resale and $452,000 of direct operating expenses. This represents
a decrease of $454,000 (32%) in plant costs during the first quarter of 1996.

The Company incurred engineering and geological expenses of $101,000 and
$89,000 during the three months ended March 31, 1996 and 1995, respectively.

The Company's depletion, depreciation, amortization and impairment expense
("DD&A") increased $360,000 (27%) from $1,346,000 in the first quarter of 1995
to $1,706,000 in the first quarter of 1996 as a result of increases in
depreciable oil and gas assets due to costs incurred in the continued
development of the San Joaquin Basin properties. The DD&A rate per BOE for oil
and gas reserves was $3.60 per BOE in the first quarter of 1996 as compared to
$4.14 during the first quarter of 1995.

The Company's general and administrative expenses increased slightly in the
first quarter of 1996 ($55,000 or 8%) due to the Company's continued growth and
expansion.

The Company's interest expense increased $1,513,000 from $1,130,000 in the
first quarter of 1995 to $2,643,000 in the first quarter of 1996. This was due
to the refinancing of the Company's bank debt and the Series D Preferred Stock
with $65,000,000 in 14 7/8% Senior Secured Notes in July 1995. Also affecting
interest

23
<PAGE> 24

expense in the first quarter of 1996 was an increase in amortization of deferred
financing costs resulting from the Senior Note and related warrant offering.

Total dividends on preferred stock were $132,500 in the first three months
of 1996, as compared to $335,000 in the first quarter of 1995. First quarter
1996 dividends consisted of cash, while first quarter 1995 dividends consisted
of $70,000 in cash, $235,000 in Series D Preferred Stock and $30,000 in Common
Stock of the Company. The Company also incurred a non-cash charge of $81,000
attributable to accretion on its Series D Preferred Stock in 1995. The Series D
Preferred Stock was redeemed in July 1995.

Non-Recurring Charge. During the first quarter of 1996 the Company incurred
a non-cash write-off of $261,000, representing the remaining portion of a
long-term investment made in a gas marketing company which recently declared
bankruptcy.

Net Loss. The Company's net operating loss for the first quarter of 1996
was $228,000 while net loss attributable to common stockholders was $360,000
($.04 per share) after preferred dividends. In the first quarter of 1995, the
Company had a net operating loss of $421,000 and net loss to common shareholders
of $837,000 ($.12 per share) after preferred dividends and accretion.

COMPARISON OF RESULTS OF 1995 TO 1994

Acquisition of San Joaquin Basin Properties. Included in results of
operations for 1995 are twelve months of operations from the San Joaquin Basin
properties, as compared to six months of operations in the comparable period of
1994. The San Joaquin Basin properties were acquired on June 30, 1994. (See Note
4 of Notes to Consolidated Financial Statements included elsewhere is this
Prospectus.)

Revenues. The Company's total revenues increased $9,382,000 (71%) from
$13,213,000 in 1994 to $22,595,000 in 1995.

The Company's total oil and gas revenues increased $5,048,000 (46%) from
$10,982,000 in 1994 to $16,030,000 in 1995. Oil revenues increased $2,688,000
(54%) due primarily to an increase in oil production volumes of 151,000 barrels
(48%), from 312,000 barrels in 1994 to 463,000 barrels in 1995. The increased
production was a result of the acquisition of the San Joaquin Basin properties,
which produced 304,200 barrels of oil in 1995 as compared to 131,400 barrels in
1994 (six months). Oil production from the Company's other properties decreased
30,000 barrels (16%) in the aggregate due to normal production declines. The
average price received for oil was $16.49 per barrel during 1995 compared to
$15.79 per barrel in 1994.

The Company's gas revenues increased $2,360,000 (39%) in 1995 in spite of
lower gas prices due to increased production. Gas production increased 1,811,000
Mcf (54%) from 3,326,000 Mcf in 1994 to 5,137,000 Mcf in 1995. The San Joaquin
Basin properties contributed 3,217,000 Mcf of production in 1995 as compared to
1,315,000 Mcf in 1994 (six months). Gas production from the Company's other
properties decreased 90,000 Mcf (5%) in the aggregate during 1995 due to normal
production declines. The average price received for gas was $1.64 per Mcf in
1995 as compared to $1.82 per Mcf in 1994.

During 1995, the company realized revenues of $6,362,000 from its share of
the operations of the natural gas processing plant acquired with the San Joaquin
Basin properties. These revenues consisted of $2,320,000 in the resale of
natural gas purchased from third parties, $3,321,000 in the sale of processed
natural gas liquids, $111,000 in gas processing fees and $610,000 from the
monetization of certain index-based gas contracts. In 1994, the Company realized
gas plant revenues of $1,978,000 (six months), which consisted of $718,000 in
the resale of purchased natural gas, $1,199,000 from the sale of processed
natural gas liquids and $61,000 in gas processing fees.

The Company realized interest and other income of $164,000 and $39,000,
respectively, in 1995. This compares to interest and other income of $16,000 and
$237,000, respectively, in 1994. The increase in 1995 interest income is due to
significantly larger cash balances resulting from the Senior Note offering in
July 1995. Other income in 1994 was primarily a gain on sale of miscellaneous
oil and gas properties.

Costs and Expenses. Total costs and expenses increased $11,295,000 (81%)
from $14,030,000 in 1994 to $25,325,000 in 1995.

24
<PAGE> 25

The Company's production costs increased $1,653,000 (46%) from $3,610,000
in 1994 to $5,263,000 in 1995. This was primarily due to the acquisition of the
San Joaquin Basin properties, which accounted for $3,050,000 of production costs
incurred in 1995 as compared to $1,373,000 in 1994 (six months). Production
costs on the Company's other properties decreased $33,000 in the aggregate
during 1995. Average production costs decreased to $3.99 per BOE in 1995 as
compared to $4.13 per BOE in 1994.

During 1995, the Company incurred costs of $3,704,000 resulting from its
share of the operations of the natural gas processing plant acquired with the
San Joaquin Basin properties. These costs included $1,998,000 for the purchase
of natural gas for processing and resale and $1,706,000 of direct operating
expenses. During 1994, the Company incurred gas plant costs of $1,708,000 (six
months) consisting of $876,000 of natural gas purchased for resale and $832,000
of direct operating expenses.

The Company incurred incidental abandonment costs of $4,000 in 1995 as
compared to $75,000 during 1994. Engineering and geological expenses increased
$53,000 (21%) from $254,000 in 1994 to $307,000 in 1995 due to an increase in
the number of oil and gas properties owned by the Company and activities related
to their evaluation and management.

The Company adopted in 1995 the provisions of Statement of Financial
Accounting Standards No. 121 ("SFAS 121") which resulted in a non-cash
impairment charge of $876,000 which is included in DD&A. Excluding the
impairment charge, the Company's DD&A increased $1,200,000 (31%) from $3,897,000
in 1994 to $5,097,000 in 1995. This was a result of the substantial increase in
acquisition and development costs related to the San Joaquin Basin property
acquisition. The DD&A rate, excluding the effects of SFAS 121, was $3.60 per BOE
in 1995 as compared to $4.14 during 1994 as a result of an increase in oil and
gas reserves attributable to the San Joaquin Basin properties during 1995.
Further affecting the increase in overall DD&A expense was $314,000 in
depreciation expense in the current period relating to the natural gas
processing plant acquired with the San Joaquin Basin properties as compared to
$145,000 in 1994 (six months).

The Company's general and administrative expenses increased $730,000 (36%)
from $2,014,000 in 1994 to $2,744,000 in 1995. Increases in G&A were a result of
the Company's increased development and financing activities and general
expansion.

The Company's interest expense increased $4,578,000 from $2,268,000 in 1994
to $6,846,000 in 1995. This was due to the increased bank debt resulting from
the original financing of the San Joaquin Basin properties in June 1994 and
subsequent refinancing of that bank debt and Series D Preferred Stock with
$65,000,000 in 14 7/8% Senior Secured Notes in July 1995. Also increasing
interest expense in 1995 was increased amortization of deferred financing costs
resulting from these financings.

Other expense of $483,000 in 1995 resulted from the write-down of a
long-term investment of $261,000, bad debt expense of $90,000 and a $132,000
loss on the disposition of miscellaneous oil and gas properties. In 1994, the
Company recorded a charge of $203,000 from a write-off of a portion of its
interests in the South Texas Properties, a portion of which was conveyed to a
third party pursuant to the terms of the dissolution of the South Texas Limited
Partnership, a partnership in which the Company was a partner.

Extraordinary Item. In connection with the refinancing of its long-term
debt, the Company incurred in 1995 a non-cash extraordinary charge of $1,888,000
resulting from the early extinguishment of debt. This was primarily the
write-off of all deferred financing costs associated with the Company's bank
debt and Series D Preferred Stock which were repaid in July 1995. During 1994,
the Company incurred an extraordinary non-operating charge of $122,000 resulting
from the early extinguishment of debt in the refinancing of the South Texas
properties in connection with the dissolution of the South Texas Limited
Partnership.

Accretion. During 1995, the company incurred a non-cash accretion charge of
$2,147,000 on its Series D Preferred Stock. This accretion charge was primarily
the result of the early redemption of the Series D Preferred Stock in connection
with the refinancing of the Company's long-term debt.

Preferred Dividends. Dividends on preferred stock were $1,000,000 for 1995
as compared to $795,000 in 1994. Increased dividends in 1995 were a result of
the Series D and Series E Preferred Stocks being outstanding for a longer
portion of the year during 1995 as compared to 1994 and an increase in the
Series E

25
<PAGE> 26

coupon rate from 4% to 9% effective July 1995. Dividends in 1995 consisted of
$464,000 in cash, $476,000 in shares of Series D Preferred Stock and $60,000 in
Common Stock of the Company. Dividends for 1994 consisted of $280,000 in cash,
$455,000 in shares of Series D Preferred Stock and $60,000 in Common Stock of
the Company.

Net Loss. The Company's net loss from continuing operations for 1995 was
$2,730,000 ($0.35 per share), while net loss attributable to common stockholders
after extraordinary item, preferred dividends and accretion was $7,765,000
($0.98 per share). In 1994, the Company had a net loss from continuing
operations of $816,000 and net loss to common shareholders of $1,890,000 ($0.29
per share) after extraordinary item, preferred dividends and accretion.

COMPARISON OF RESULTS OF 1994 TO 1993

Acquisition. Included in results of operations for 1994 are six months of
operations from the San Joaquin Basin properties, which were acquired on June
30, 1994.

Revenues. The Company's total revenues increased $6,488,000 (96%) from
$6,725,000 in 1993 to $13,213,000 in 1994.

The Company's oil and gas revenues increased $4,475,000 (69%) from
$6,507,000 in 1993 to $10,982,000 in 1994. Oil revenues increased $1,975,000
(67%) from $2,950,000 in 1993 to $4,925,000 in 1994 due to higher oil
production. The Company's oil production increased approximately 133,000 barrels
(74%) from 179,000 barrels in 1993 to 312,000 barrels in 2994. The increased
production was primarily a result of the acquisition of the San Joaquin Basin
properties, which contributed 131,400 barrels during the last six months of
1994. The Company's Permian Basin properties experienced an increase of 5,400
barrels in 1994 due to the Company's acquisition of additional oil and gas
interests in that area in late 1994. Additionally, oil production from the South
Texas properties increased by 2,100 barrels due to the additional 12.625%
interest in those properties acquired by the Company in May 1993 and the
drilling of four development wells in late 1993 and early 1994. Oil production
from the Company's Gulf Coast and other properties declined approximately 6,200
barrels in the aggregate due to normal production declines. The average price
received for oil was $15.79 per barrel during 1994 compared to $16.46 per barrel
in 1993.

The Company's gas revenues increased $2,527,000 (72%) from $3,518,000 in
1993 to $6,045,000 in 1994 also due to increased production. Gas production
increased 1,341,000 Mcf (68%) from 1,985,000 Mcf in 1993 to 3,326,000 Mcf in
1994. The acquisition of the San Joaquin Basin properties contributed 1,315,000
Mcf of the increase while production from the South Texas properties increased
174,000 Mcf due to the additional 12.625% interest acquired by the Company and
the drilling of four development wells. Gas production from the Royalty
Interests decreased 76,000 Mcf in 1994 as compared to 1993 as a result of
mechanical problems with a gas purchaser's compression facilities which serve a
significant gas lease. These facility problems were corrected in the fourth
quarter of 1994. Gas production from the Company's other properties deceased
72,000 Mcf in the aggregate in 1994 due to normal production declines. Average
prices received for gas were $1.82 per Mcf in 1994 as compared to $1.77 per Mcf
in 1993. Excluding natural gas liquids attributable to the Bakersfield gas
plant, the Company also realized $12,000 in natural gas liquids sales in 1994 as
compared to $39,000 in 1993.

During 1994, the Company realized revenues of $1,978,000 from its share of
the operations of the natural gas processing plant acquired as part of the San
Joaquin Basin properties. These revenues consisted of $718,000 in the resale of
natural gas purchased from third parties, $1,199,000 in the sale of processed
natural gas liquids, including the sale of natural gas liquids extracted from
the natural gas purchased from third parties and $61,000 in gas processing fees.

The Company realized other income of $237,000 in 1994 resulting primarily
from a gain on the sale of securities. During 1993, the company had other income
of $197,000 resulting primarily from the sale of its interests in several minor
oil and gas properties.

Costs and Expenses. Total costs and expenses increased $6,264,000 (81%)
from $7,766,000 in 1993 to $14,030,000 in 1994.

26
<PAGE> 27

The Company's production costs increased $1,361,000 (61%) from $2,249,000
in 1993 to $3,610,000 in 1994. This was primarily due to the acquisition of the
San Joaquin Basin properties, which accounted for $1,373,000 in production costs
during the last six months of 1994. Production costs on the South Texas
properties increased $143,000 in the current year due to developmental drilling
activities while production costs from the Company's other oil and gas
properties decreased $155,000 in the aggregate as a result of lower workover
costs.

During 1994, the Company incurred operating costs of $1,708,000 associated
with the natural gas processing plan acquired as part of the San Joaquin Basin
properties. These costs included $876,000 from the purchase of natural gas for
processing and resale of $832,000 of directing operating expenses.

The Company incurred incidental abandonment costs on older non-productive
leases of $75,000 in 1994 as compared to $41,000 in 1993. Engineering and
geological expenses increased $66,000 (35%) from $188,000 in 1993 to $254,000 in
1994 due to the Company's increased activities.

The Company's depletion, depreciation and amortization expense increased
$1,256,000 (48%) from $2,641,000 in 1993 to $3,897,000 in 1994 as a result of
increases in depreciable oil and gas assets due to acquisitions and development
costs. The DD&A rate per BOE for oil and gas reserves decreased from $5.13 per
BOE in 1993 to $4.14 per BOE in 1994 due to lower acquisition costs per BOE for
oil and gas reserves acquired during 1994 and positive reserve revisions during
1994. Further affecting the increase in overall DD&A expense was depreciation
expense relating to the natural gas processing plant acquired as part of the San
Joaquin Basin properties in 1994.

The Company's general and administrative expenses decreased slightly from
$2,105,000 in 1993 to $2,014,000 in 1994 (4%). The Company experienced $142,000
in nonrecurring costs resulting from its relocation from California to Texas
during 1993.

The Company's interest expense increased $1,727,000 from $542,000 in 1993
to $2,269,000 in 1994 primarily as a result of the bank debt used to finance the
acquisition of the San Joaquin Basin properties in June 1994. The Company's bank
debt increased from $8,541,000 at December 31, 1993 to $39,400,000 at December
31, 1994, resulting in a significantly higher average debt balance during the
current year.

The Company recorded a charge of $203,000 in 1994 from a write-off of a
portion of its interests in the South Texas Properties, which portion was
conveyed to a third party pursuant to the terms of the dissolution of the South
Texas Limited Partnership. Also in connection with the dissolution of the South
Texas Limited Partnership, the Company incurred an extraordinary non-operating
charge of $122,000 in 1994 resulting from the early extinguishment of debt in
the refinancing of the South Texas properties.

Dividends on preferred stock were $795,000 in 1994, as compared to $246,000
in 1993. The increase in dividends was a result of the issuance of additional
preferred stock as part of the financing for the acquisition of the San Joaquin
Basin properties. Dividends in 1994 consisted of $280,000 in cash, $455,000 in
Series D Preferred Stock and detachable warrants and $60,000 in common stock of
the Company. All 1993 dividends were paid in cash. The Company also incurred a
non-cash charge of $156,000 attributable to accretion on its Series D Preferred
Stock in 1994.

Net Loss. The Company's net loss before the extraordinary item in 1994 was
$816,000, and $939,000 after the extraordinary item. Net loss attributable to
common stockholders was $1,890,000 ($.29 per share) after preferred dividends,
accretion on preferred stock and the extraordinary item. In 1993, the Company
had a net loss of $1,041,000 and a loss of $1,287,000 ($.23 per share)
attributable to common shareholders after preferred dividends.

LIQUIDITY AND CAPITAL RESOURCES

Summary. The Company's sources of working capital have primarily been cash
flows from operations and a combination of debt and equity financings as needs
for capital have arisen. During the three months ended March 31, 1996, the
Company used net cash from operations of $88,000 as compared to $944,000 cash
flows generated from operations during the same period in 1995. The Company
realized net proceeds of $1,597,000

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<PAGE> 28

from financing activities during the first quarter of 1996, which consisted
primarily of a draw-down on its credit facility net of dividends and
miscellaneous financing costs. During the first quarter of 1995, the Company had
nominal financing activities. The Company utilized a net of $9,736,000 for
investing activities in the first quarter of 1996 as compared to $107,000 during
the first quarter of 1995. Included in investing activities in the first quarter
of 1996 were payments of $8,188,000 relating to drilling costs incurred but
unpaid at the end of 1995.

Working Capital. The Company had net working capital of $1,789,000 with a
current ratio of 1.3:1 at March 31, 1996 as compared to net working capital of
$1,325,000 and a current ratio of 1.1:1 at December 31, 1995.

Operating Activities. Discretionary cash flow is a measure of performance
which is useful for evaluating exploration and production companies. It is
derived by adjusting net income or loss to eliminate the non-cash effects of
exploration expenses, depletion, depreciation, amortization and non-recurring
charges, if applicable. The effects of non-cash working capital changes are also
excluded. This measure reflects an amount that is available for capital
expenditures, debt service and repayment and dividend payments.

During the three months ended March 31, 1996, the Company generated
discretionary cash flow of $2,080,000. This compares to $1,132,000 during the
same period in 1995. The improvement in 1996, in spite of significantly
increased debt service, was primarily due to increased oil and gas production
resulting from the continued drilling and development of the San Joaquin Basin
properties. The Company had a total of 144 producing wells in this area at March
31, 1996, as compared to 96 producing wells at March 31, 1995. As a consequence
of these drilling activities and the acquisition of certain additional interests
in these properties in July 1995, HarCor's share of sales production from the
San Joaquin Basin properties averaged 1,336 Bbls per day and 13,895 Mcf per day
during the first quarter of 1996, showing increases of 68% and 72%,
respectively, over first quarter 1995 average rates of 796 Bbls per day and
8,085 Mcf per day. Additionally, first quarter 1996 production rates on the San
Joaquin Basin properties demonstrated a continuing increase over fourth quarter
average production rates of 1,174 Bbls per day and 11,734 Mcf per day.

The Company also realized a net operating margin of $668,000 on its gas
plant operations in the first quarter of 1996 as compared to $375,000 in the
first quarter of 1995. This was primarily due to increased gas production
volumes from the San Joaquin Basin properties processed through the plant,
resulting in increased NGLs sales in the first quarter of 1996.

Early in the first quarter of 1996, the Company deferred drilling vertical
wells in the San Joaquin Basin pending the results of its first horizontal well
in this area. The Company anticipates resuming drilling certain vertical wells
required for implementation of the waterflood program towards the end of the
second quarter of 1996. Results of the Company's first horizontal well on the
Ellis Lease, which was completed in June 1996 and is currently being tested,
will determine if additional horizontal wells will be drilled to eliminate
certain planned vertical wells. See "Capital Expenditures and Future Outlook"
below.

Financing Activities: Credit Facility. Availability under the Company's
Credit Facility with ING Capital is limited to a "borrowing base" amount. The
borrowing base is determined semi-annually by ING Capital, at its sole
discretion, and may be established at an amount up to $15 million. The borrowing
base is currently $15 million. The Credit Facility will terminate on June 30,
1997 unless renewed by mutual agreement. If not so renewed, amounts outstanding
will convert to a term loan on September 30, 1997, with a set amortization
schedule of a percentage of the outstanding principal balance continuing through
December 31, 2000. The Company drew down $1.9 million on this facility during
the first quarter of 1996 and there was $7.5 million outstanding at March 31,
1996. The effective interest rate on the balance outstanding was 8.125% at that
date. Amounts advanced under this facility bear interest at an adjusted
Eurodollar rate plus 2.50%. The Company repaid $2 million of the outstanding
balance under the Credit Facility subsequent to March 31, 1996 from cash flows
generated by operations.

The Credit Facility contains restrictive covenants which impose limitations
on the Company and its subsidiaries with respect to, among other things, certain
financial ratios or limitations, incurrence of indebtedness, the sale of the
Company's oil and gas properties and other assets, hedging transactions, payment

28
<PAGE> 29

of dividends, mergers or consolidations and investments outside the ordinary
course of business. The Credit Facility also contains customary default
provisions.

All indebtedness of the Company under the Credit Facility is secured by a
first lien upon substantially all of the Company's oil and gas properties as
well as by the accounts receivable, inventory, general intangibles, machinery
and equipment and other assets of the Company. All assets not subject to a lien
in favor of the lender are subject to a negative pledge, with certain
exceptions. See Notes 6 and 7 of Notes to Consolidated Financial Statements
included herein for a complete description of the Senior Notes and the Credit
Facility.

Senior Notes. In July 1995, the Company consummated the sale of 65,000
units consisting of $65 million aggregate principal amount of its 14 7/8% Senior
Notes due in the year 2002 and warrants to purchase 1,430,000 shares of Common
Stock. Each unit consisted of a $1,000 principal amount note and 22 warrants to
purchase an equal number of shares of Common Stock. The Senior Notes and the
warrants became separately transferrable immediately after July 24, 1995.

The Company used the net proceeds of approximately $61 million to repay an
aggregate of $39.3 million outstanding under its Credit Facility and bridge loan
with ING Capital; redeem $10.9 million in outstanding shares of Series D
Preferred Stock which were issued in connection with the acquisition of the San
Joaquin Basin properties; and acquire additional interests in additional
producing wells in the San Joaquin Basin properties for $2.3 million. The
Company used the balance of the proceeds from the Senior Notes to finance a
portion of the development of its San Joaquin Basin properties over the
remainder of 1995. This refinancing of the Company's debt and capital structure
resulted in an extraordinary loss on early extinguishment of debt of $1.9
million and accretion on Series D Preferred Stock of $2.1 million in the current
year.

The Company's Senior Notes bear interest at the rate of 14 7/8% per annum.
Interest accrues from the date of issue and will be payable semi-annually on
January 15 and July 15 of each year, commencing on January 15, 1996. The Senior
Notes are redeemable, in whole or in part, at the option of the Company at any
time on or after July 15, 1999, at the following redemption prices (expressed as
percentages of the principal amount) if redeemed during the 12-month period
commencing on July 15 of the year set forth below plus, in each case, accrued
interest thereon to the date of redemption:

<TABLE>
<CAPTION>
YEAR PERCENTAGE
--------------------------------------------------------------
<S> <C>
1999................................................ 110%
2000................................................ 107%
2001 and thereafter................................. 100%
</TABLE>

In the event that the Company has excess cash flow (defined as the amount
by which the sum of consolidated net income and certain other consolidated
non-cash charges exceeds the sum of capital expenditures and payments required
to be made pursuant to the scheduled maturities of certain indebtedness) in
excess of $2 million in any fiscal year, beginning with the fiscal year ending
December 31, 1996, the Company will be required to make an offer to purchase
notes from all holders thereof in an amount equal to 50% of all such excess cash
flow for such fiscal year (not just the amount in excess of $2 million) at a
purchase price equal to 101% of the principal amount thereof, plus accrued and
unpaid interest thereon. The Company does not expect to have any excess cash
flow in the foreseeable future due to its planned capital expenditures.

In the event that the Company consummates on or prior to July 15, 1997 an
offering of qualified capital stock, which includes Common Stock, of the Company
for cash having proceeds in excess of $5 million, then following the offering
the Company is obligated to make an offer to purchase Senior Notes from all of
the holders of the Senior Notes on a date within 90 days after the consummation
of the offering at a purchase price equal to 110% of the aggregate principal
amount of the Senior Notes that the Company is required to offer to repurchase,
plus accrued and unpaid interest thereon, if any. The aggregate principal amount
of the Senior Notes to be repurchased will be an amount equal to the lesser of
(i) 40% of the aggregate principal amount of the Senior Notes originally issued
and (ii) the maximum amount of the Senior Notes which could be purchased with
50% of the amount of net proceeds received or receivable by the Company from the
offering of qualified capital stock. The Company also has the option to redeem a
portion of the Senior Notes at a

29
<PAGE> 30

redemption price of 110% of the principal amount of the Senior Notes to be
redeemed, plus accrued and unpaid interest to the date of redemption, utilizing
net proceeds from such an offering to the extent that such proceeds could have
otherwise been utilized to purchase Senior Notes as described above. The Company
intends to use 50% of the net proceeds of the Offering to redeem a portion of
the Senior Notes as described above. The Company estimates that it will incur an
extraordinary charge of approximately $2,081,000 relating to the early
extinguishment of debt.

All of the obligations of the Company under the Senior Notes and related
indenture are secured by a second priority lien on substantially all of the
assets of the Company, which assets also collateralize the Company's obligations
under the Credit Facility.

The Company also used an aggregate of $303,000 for the payment of dividends
and miscellaneous financing costs during the current period.

Hedging Activities. The Company's hedging activities during the three years
ended December 31, 1995 and the three months ended March 31, 1996 have not had
any material effect on the Company's liquidity or results of operations. In the
fourth quarter of 1995, the Company received $610,000 in revenues from the
privatization of certain index-based gas contracts.

The following table presents all hedge contracts that the Company was a
party to at March 31, 1996 including the type of contract, volumes contracted,
period of contract and unit contract price.

<TABLE>
<CAPTION>
TYPE OF CONTRACT CONTRACTED VOLUMES PERIOD UNIT CONTRACT PRICE
- ---------------- ------------------ ------------------------- ----------------------
<S> <C> <C> <C>
Hedge 8,000 Bbls/month Feb. 1994 to Aug. 1996 $18.75/$15.80 Bbl(A)
Hedge 300 Bbls/day May 1995 to April 1996 $18.50/Bbl
Hedge 250 Bbls/day May 1996 to April 1997 $18.50/Bbl
Hedge 6,750 Bbls/month Jan. 1996 to Dec. 1996 $17.25/Bbl(B)
Hedge 5,625 Bbls/month Jan. 1997 to Dec. 1997 $17.25/Bbl(B)
Hedge 4,875 Bbls/month Jan. 1998 to Dec. 1998 $17.25/Bbl(B)
Physical 3,000 MMBtu/day Oct. 1995 to Sept. 1996 $2.03/MMBtu
Physical 2,000 MMBtu/day Oct. 1995 to Sept. 1997 $1.68/MMBtu
Physical 2,500 MMBtu/day Oct. 1996 to Sept. 1997 $2.07/MMBtu
Physical 6,000 MMBtu/day Jan. 1996 to Dec. 1997 NYMEX-indexed(C)
</TABLE>

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

(A) Pursuant to such hedge contract, if the NYMEX price of light, sweet crude
oil ("NYMEX price") is lower than $15.80, then the Company is paid the
difference between the NYMEX price and $15.80 for each barrel hedged; and,
if the NYMEX price is higher than $18.75, then the Company pays the
difference between the NYMEX price and $18.75 for each barrel hedged.

(B) Pursuant to such hedge contract, the Company pays half of the difference
between $17.25 and the NYMEX price if the index price is higher than $17.25;
and the Company receives the difference between $17.25 and the index price
if the index price is lower than $17.25, as determined on a monthly basis.

(C) Firm gas sales contract which fixes volumes to be sold at $0.3675 less than
the NYMEX gas future price for each applicable month.

As of March 31, 1996 the Company had approximately 45% of its oil
production and approximately 42% of its gas production committed to the above
sales and hedging contracts based on first quarter 1996 production.

Capital Expenditures and Future Outlook. Subsequent to the refinancing of
its debt in July 1995, the Company spent $2.3 million on the acquisition of
interests in additional producing wells on the San Joaquin Basin properties and
spent approximately $15 million on developmental and drilling activities on
these properties through March 31, 1996. The Company also spent an aggregate of
$848,000 on the development of its Permian and South Texas properties during
1995. See "Operating Activities" for current production rates.

The Company intends to spend an additional estimated $56.6 million for
capital expenditures to develop the proved reserves of the San Joaquin Basin
properties during the period from 1996 through the year 2000, of

30
<PAGE> 31

which $16 million is planned to be spent during 1996, $12 million in 1997, $13
million in 1998 and $15.6 million thereafter. The Company currently anticipates
that total additional development of the San Joaquin Basin properties will
result in approximately 173 new gross wells, including 145 development wells and
a secondary recovery waterflood project in the Diatomite Zone of the Ellis
Lease. The first phase of the waterflood project is planned to be initiated in
the fourth quarter of 1996, with expansion of the project planned in 1997 and
1998 to cover the entire area of proved reserves. The Company plans to fund 1996
and future capital expenditures from operating cash flows and borrowings under
the Credit Facility.

The Company also plans to spend approximately $1.5 million to drill two
horizontal wells on these properties during 1996. The first of these wells has
been drilled and completed on the Ellis Lease in the Diatomite formation to test
a possible extension of the current proved area of the field and to evaluate the
use of horizontal wells to eliminate the drilling of certain planned infill
vertical wells on the Ellis Lease. A second horizontal well is planned to
evaluate its applicability to producing the deeper MacDonald formation on the
Ellis Lease. If successful, additional horizontal locations may be identified
for future drilling on the Ellis Lease as well as the Company's Truman and
Tisdale Leases in areas currently outside the proven areas of these fields. No
assurances can be given, however, that any of such wells will be drilled, or
that if such wells are drilled, they will be either successful or completed in
accordance with the Company's development schedule.

The Company is also involved in two small waterflood projects on its
Permian Basin properties and has approximately $2.4 million in capital
expenditures planned in this area during the next two years.

In the second half of 1995, the Company participated in a leasing program
which was undertaken in South Texas around the Company's existing Hostetter
Field for a planned 3-D seismic program. The 3-D seismic survey is currently
being conducted and processing of data from this seismic program commenced in
May 1996 and drilling could begin in the fourth quarter of 1996. In furtherance
of this effort and as part of the Company's strategy of aligning itself with
partners that have technological expertise, the Company has entered into an
agreement with South Coast Exploration to jointly explore the Hostetter Field.
South Coast Exploration in turn has provided the Company with a similar
opportunity to jointly explore a prospect area in Terrebonne Parish, Louisiana.
The Company and South Coast Exploration have also agreed to jointly participate
in a 3-D seismic/exploration project in Reeves County, Texas, the first phase of
which is currently being conducted. The Reeves County project area of mutual
interest covers approximately 160,000 acres and will entail shooting 3-D seismic
data over approximately 200 square miles with the first exploratory test well
planned for the first quarter of 1997. The Company and South Coast Exploration
have also jointly formed the GeoTeam to assist them in the evaluation of these
3-D projects.

Based on current plans, the Company expects to make capital expenditures
with respect to its exploratory prospects of approximately $14.3 million during
the next 18 months, of which approximately $3.2 million is expected to be spent
during the second half of 1996, and approximately $11.1 million is expected to
be spent during 1997. Of the estimated capital expenditures in 1996,
approximately $1.3 million is expected to be made for seismic surveys, of which
$720,000 will be made in South Texas, $330,000 will be made in West Texas and
$235,000 will be made in South Louisiana; approximately $1.4 million is expected
to be made for leasehold acquisitions, of which $640,000 will be made in South
Texas, $480,000 will be made in West Texas and $240,000 will be made in South
Louisiana; and approximately $570,000 is expected to be made for exploration
drilling in South Texas. Of the estimated capital expenditures in 1997,
approximately $8.9 million is expected to be made to drill approximately 18
exploration and development wells in South Texas; approximately $900,000 is
expected to be made to drill four exploration and development wells in West
Texas and approximately $1.3 million is expected to be made to drill four
exploration and development wells in South Louisiana.

While the Company has had losses in each of the past five years and the
first quarter of 1996, the Company has taken steps to address its continuing
losses. The most notable of which include increasing the development of its
undeveloped properties, including the Bakersfield Properties, to increase
production of oil and gas and cash flow from operations and using a portion of
the proceeds from the Offering to redeem part of its outstanding Senior Notes
and reduce the Company's interest expense. The reduced interest expense should
permit further development of the Company's properties and expansion of its
reserve base. In addition, the

31
<PAGE> 32

Company has continued to maintain relatively low general and administrative
expenses by continuing to operate through a management team that is few in
number.

Despite its lack of profits, the Company expects that its available cash,
expected cash flows from operating activities, credit availability under its
Credit Facility and the proceeds from the Offering will be sufficient to meet
its financial obligations and fund its planned developmental drilling and
exploration activities through the end of 1997, provided, that (i) there are no
significant decreases in oil and gas prices beyond current levels or anticipated
seasonal lows, (ii) there are no significant declines in oil and gas production
from existing properties other than declines in production currently anticipated
based on engineering estimates of the decline curves associated with such
properties, (iii) drilling costs for development wells with respect to the San
Joaquin Basin properties do not increase significantly from the drilling costs
recently experienced by the operator in such areas with respect to similar wells
and (iv) the operator continues its development program with respect to the San
Joaquin Basin properties on the schedule currently contemplated.

In the event the cash flows from the Company's operating activities, credit
available under its Credit Facility and the proceeds from the Offering are not
sufficient to fund development costs, or results from developmental drilling are
not as successful as anticipated, then the Company will either (i) curtail its
developmental drilling and/or exploration activities or (ii) seek additional
financing to assist in its developmental drilling activities.

The Company intends to continue efforts to acquire additional interests in
selected producing oil and gas properties if and when these opportunities become
available. Any such acquisitions could require borrowings under the Credit
Facility or additional debt or equity financing.

UNCERTAINTIES INVOLVING FORWARD-LOOKING DISCLOSURE

Certain of the statements set forth above under "Liquidity and Capital
Resources -- Capital Expenditures and Future Outlook" and elsewhere in this
Prospectus, such as the statements regarding planned capital expenditures,
increases in oil and gas production, the number of anticipated wells to be
drilled in 1996 and thereafter and the planned 3-D seismic program, are
forward-looking and are based upon the Company's current belief as to the
outcome and timing of such future events. There are numerous uncertainties
inherent in estimating quantities of proved oil and gas reserves and in
projecting future rates of production and timing of development expenditures,
including many factors beyond the control of the Company. Reserve engineering is
a subjective process of estimating underground accumulations of oil and gas that
cannot be measured in an exact way, and the accuracy of any reserve estimate is
a function of the quality of available data and of engineering and geological
interpretation and judgment. As a result, estimates made by different engineers
often vary from one another. In addition, results of drilling, testing and
production subsequent to the date of an estimate may justify revisions of such
estimate and such revisions, if significant, would change the schedule of any
further production and development drilling. Accordingly, reserve estimates are
generally different from the quantities of oil and gas that are ultimately
recovered. Furthermore, the estimated numbers of wells to be drilled in 1996 and
1997 are based upon product prices and costs as of December 31, 1995 (except for
gas sold under contract, in which case the contract prices were used), which
will probably be different from the actual prices recognized and costs incurred
in 1996 and 1997. Additional factors which could materially affect the Company's
oil and gas production and development drilling program in the future are
general economic conditions; the impact of the activities of OPEC and other
competitors; the impact of possible geopolitical occurrences world-wide; the
results of financing efforts, risks under contract and swap agreements; changes
in laws and regulations; capacity, deliverability and supply constraints or
difficulties, unforeseen engineering and mechanical or technological
difficulties in drilling or working over wells; and other risks set forth in
"Risk Factors," appearing elsewhere in this Prospectus. Because of the foregoing
matters, the Company's actual results for 1996 and beyond could differ
materially from those expressed in the forward-looking statements.

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<PAGE> 33

EFFECTS OF INFLATION AND CHANGES IN PRICE

The Company's results of operations and cash flows are affected by changing
oil and gas prices. If the price of oil and gas increases, there could be a
corresponding increase in the cost to the Company for drilling and related
services, as well as an increase in revenues. Inflation has had a minimal effect
on the Company.

OTHER

In September 1995, the Company adopted the provisions of SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." SFAS 121 requires the Company to review its oil and gas
properties whenever events or changes in circumstances indicate that the
carrying amount of such assets may not be recoverable, and recognize a loss if
such recoverable amounts are less than the carrying amount. The adoption of SFAS
121 resulted in an impairment loss of $876,000 which was included in depletion,
depreciation, amortization and impairment in 1995. The Company uses the
successful efforts method of accounting for its oil and gas properties. See Note
1 of Notes to Consolidated Financial Statements included herein for a summary of
significant accounting policies.

33
<PAGE> 34

BUSINESS AND PROPERTIES
THE COMPANY

BUSINESS STRATEGY

The Company's business objective is to increase its hydrocarbon reserves as
economically as possible by:

- Continuing to develop its San Joaquin Basin, South Texas and Permian
Basin properties through additional drilling and secondary recovery
activities;

- Acquiring onshore oil and gas properties with significant development
potential; and

- Continuing to maintain relatively low production costs through geographic
concentration and tight control over operating and general and
administrative expenses.

DEVELOPMENT ACTIVITIES

San Joaquin Basin. Approximately 20.8 MMBOE, or 69.4%, of the Company's
total proved reserves as of January 1, 1996 were classified as proved
undeveloped by Ryder Scott. Substantially all of the Company's undeveloped
reserves are located in the Lost Hills Field in the San Joaquin Basin.
Bakersfield Energy, a company with extensive experience in the San Joaquin
Basin, is the operator of substantially all of HarCor's oil and gas properties
in the San Joaquin Basin. As of March 31, 1996, the Company had identified 173
new gross wells which it intends to drill during the next five years to fully
develop the proved reserves on the properties, of which 48 are expected to be
drilled in 1996. The Company also plans to commence a secondary recovery
waterflood project in the fourth quarter of 1996 with respect to a portion of
its properties in the Lost Hills Field. In addition, the Company has completed a
horizontal well in the Lost Hills Field to test a possible extension of the
current proved area of the field and to evaluate the use of horizontal wells to
eliminate the

34
<PAGE> 35

need to drill certain infill vertical wells. The Company has identified 60
potential locations for future development of probable and possible reserves
located on the San Joaquin Basin properties.

The San Joaquin Basin properties produce a light (approximately 40()
gravity), low sulfur crude oil that commands a substantial price premium to the
heavier crude oils typically produced in California. The associated natural gas
produced with the crude oil has a high Btu content (approximately 1,240 Btu)
which yields in excess of 2 gallons of NGLs per Mcf of natural gas when
processed in the Company's gas processing plant located in the San Joaquin
Basin. Since acquiring the properties in June 1994, the Company has drilled 76
gross development wells on the San Joaquin Basin properties through March 31,
1996. As a result of such drilling activity, the Company's average daily
production has increased from 546 Bbls of oil and 7,195 Mcf of gas for the month
ended June 30, 1994 to 1,336 Bbls of oil and 13,895 Mcf of gas for the quarter
ended March 31, 1996. Since acquiring the San Joaquin Basin properties, the net
proved reserves attributable to such properties have increased from 14.1 MMBOE
as of June 30, 1994, to 22.7 MMBOE as of January 1, 1996, at an average
replacement cost of $1.65 per BOE. The Pre-tax SEC 10 Value of the Company's San
Joaquin Basin properties as of January 1, 1996 was $105.2 million as estimated
by Ryder Scott.

In addition to the extensive development drilling program in the Lost Hills
Field, the Company also plans to undertake a secondary oil recovery program to
further increase reserves and production from the field. Using primary
production techniques, it is estimated by Ryder Scott, as of January 1, 1996,
that the Ellis Lease located in the Lost Hills Field has proved reserves net to
the Company of approximately 9.0 MMBbls of crude oil. In addition to primary
development, the Company intends to increase recovery rates by implementing a
secondary recovery waterflood project in the Diatomite Zone on the Ellis Lease,
which is similar to waterflood projects currently used by other oil and gas
companies operating in the Lost Hills Field. The first phase of the Ellis Lease
waterflood project is planned to be initiated in the fourth quarter of 1996,
with expansion planned in 1997 and 1998 to cover the entire area currently
estimated to cover proved reserves. Ryder Scott estimates that the Company's
Ellis Lease will yield an additional 3.7 MMBbls of proved undeveloped secondary
recovery crude oil reserves utilizing the waterflood recovery method. In
addition, the Company will commence a feasibility study for waterflooding the
Reef Ridge Shale and Antelope Shale formations on its San Joaquin Basin
properties. During 1995, the Company and Bakersfield Energy completed a 3-D
reservoir model of the Diatomite Zone on the Ellis Lease, the results of which
are being used to examine various means of further optimizing its planned Ellis
Lease waterflood, including the use of horizontal drilling on the property, as
well as to assist the Company with additional computer simulation modeling of
hot water, steam and CO(2) recovery techniques.

In the fourth quarter of 1995, the Company undertook studies to evaluate
the use of horizontal drilling technology on its San Joaquin Basin properties.
As a result of these studies, the first of two horizontal wells planned for 1996
has been drilled and completed on the Ellis Lease in the Diatomite Zone at a
vertical depth of approximately 3,450 feet with an approximate 2,000 foot
lateral drilled outside of the Diatomite Zone's previous development to test a
possible extension of the current proved area of the field and to evaluate the
use of horizontal wells to eliminate the drilling of certain infill vertical
wells on the Ellis Lease. During the five days of production tests, the well
flowed at an average rate of 418 BOE per day. The second horizontal well is
planned to evaluate its applicability to producing the deeper MacDonald Shale
formation at a depth of approximately 5,200 feet on the Ellis Lease. If these
wells are successful, potential additional horizontal locations may be
identified for future drilling on the Ellis Lease as well as in areas currently
outside the proved areas of the Company's Truman and Tisdale Leases.

Gas Plant. The South Belridge Gas Plant is a modern refrigerated liquids
extraction facility located in the South Belridge Field in Kern County,
California, approximately 10 miles southwest of the Lost Hills Field. The gas
plant was originally acquired from Exxon Corporation and has a rated inlet
capacity of 23 MMcf of

35
<PAGE> 36

gas per day and a rated liquid fractionation capacity of 100,000 gallons of NGLs
per day at a rate of two gallons of NGLs per every Mcf of natural gas
throughput. The plant is located on a 12-acre site and has NGL storage capacity
of 407,000 gallons. The plant removes the NGLs from the wet gas inlet stream
then delivers the residue natural gas directly into the pipeline system of
Southern California Gas Company ("SoCal") or directly to their customers. The
NGLs extracted at the plant are propane, iso-butane, normal butane and natural
gasoline and are sold on the spot market. The plant produced 62,266 barrels of
NGLs during the quarter ended March 31, 1996 as compared to 37,613 during the
first quarter that the plant was acquired by the Company.

In addition to its capacity to strip high volumes of liquids from the Lost
Hills property's wet gas stream, the gas plant is integral in the Company's
ability to market the residue dry gas produced from that property.

The plant's gathering lines transport wet gas from the Exxon Corporation
and San Joaquin Basin properties gathering systems and can deliver dry, residue
gas into the SoCal, Chevron U.S.A., Inc., Mobil Oil Corporation and Texaco Inc.
pipeline systems. It is these pipeline connections that allow the Company to
market the dry gas to various customers and realize favorable pricing. More
importantly, it has allowed the Company to enter into contract and marketing
arrangements that are not tied to the sometimes unfavorable and volatile
California spot market.

During the fourth quarter of 1995, the Company realized a gain of $610,000
from the monetization of certain index-based gas contracts that the Company had
been able to enter into as a result of the gas plant's pipeline connections.
Additionally, in the first quarter of 1996 the Company entered into a contract
for 6,000 mcf/day fixing the price for those volumes at $0.3675 less than the
NYMEX gas future price for two years.

South Texas. In October 1992, the Company acquired an interest in nine gas
fields located in South Texas for a total purchase price of approximately $5.3
million. Subsequent development activities have resulted in average daily
production on the South Texas properties of 36 Bbls of crude oil and 4,068 Mcf
of natural gas for the quarter ended March 31, 1996 and net proved reserves as
estimated by Ryder Scott of 1.7 MMBOE at January 1, 1996. Approximately 51% of
the Company's reserves in the South Texas properties is attributable to its
interests in the Hostetter Field. The Company owns interests in 17 gross (four
net) wells and owns approximately 2,525 gross (956 net) acres in the Hostetter
Field. These wells are operated by Texaco and Cabot. The Company currently
believes that there are opportunities for additional development and
recompletion work in this field.

EXPLORATION ACTIVITIES

Consistent with its core objective of increasing its reserves as
economically as possible, the Company has commenced a program of identifying and
developing exploratory prospects in areas where the Company or its partners have
expertise. HarCor intends to manage its exploration and economic risks by (i)
generating prospects with the assistance of strategic industry partners that are
experienced in 3-D seismic and CAEX technology, (ii) identifying and pursuing
prospects with multiple potential productive zones, (iii) funding its
exploration activities with proceeds from the Offering and internally generated
cash flow and (iv) limiting its cash exposure to approximately $500,000 for each
well. In addition, the Company intends to further manage the drilling risks
associated with the exploration projects in South Texas and South Louisiana by
drilling multipay prospects that combine shallower lower risk zones that have
previously proven productive in the area with deeper potential target zones. In
furtherance of this strategy, the Company has recently entered into an agreement
with South Coast Exploration, a company that has extensive experience utilizing
3-D seismic and CAEX techniques, to jointly pursue exploration projects on
developed and undeveloped properties in South

36
<PAGE> 37

Texas, the Permian Basin of West Texas and South Louisiana. The Company and
South Coast Exploration have jointly formed the GeoTeam to work exclusively to
pursue these joint projects.

The Company believes the use of 3-D seismic and CAEX technology is
particularly beneficial to developing prospects with multiple pay zones such as
those found in the geographic areas encompassing the Company's prospects.
Specifically, the Company and its partners plan to use the detailed 3-D seismic
data acquired in the prospect areas to select well locations that are positioned
to provide that well bores drilled to test the deeper high potential plays will
also penetrate the shallow lower risk reservoirs at geologically favorable
locations and provide shallow zone completion potential in the event the deeper
zones are not productive. The Company believes that the potential reserves from
the prospects currently targeted by this program should be comprised largely of
natural gas, which should complement the Company's current mix of estimated
proved reserves, which as of January 1, 1996 consisted of 51% of crude oil and
NGLs and 49% of natural gas.

<TABLE>
<CAPTION>
GROSS ACREAGE PROSPECTIVE
OWNED OR SQUARE MILES PROSPECTIVE ESTIMATED COST TO COMPANY(3)
UNDER OF 3-D GROSS -------------------------------------
PROSPECT AREA OPTION(1) SEISMIC DATA WELLS(2) SEISMIC LAND DRILLING TOTAL
- -------------------------------------------------------- ------------- ----------- ------- ------ -------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
South Texas (Upper Wilcox Trend)........... 23,000 83 18 $ 720 $ 640 $ 8,900 $10,260
West Texas (Permian Basin)................. 80,320 210 4 330 480 900 1,710
South Louisiana (Terrebonne Parish)........ 5,529 46 4 235 240 1,300 1,775
--
------- --- ------ ------ ------- -------
Total.............................. 108,849 339 26 $1,285 $1,360 $11,100 $13,745
======= === == ====== ====== ======= =======
</TABLE>

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

(1) Includes acreage in which the Company currently has leases, options to
acquire leases, contingent lease rights or fee interests.

(2) Includes 10 exploratory wells and 16 development wells.

The following sets forth a brief summary of each exploration prospect that
the Company has in progress. This discussion only includes prospects on which
the Company has acquired substantial leasehold interests, options to acquire
leasehold interest or other contingent lease rights and has performed or is in
the process of arranging related 3-D seismic surveys. See "Risk Factors -- Risk
of Exploratory Drilling Activities" for a discussion of the risks associated
with these exploration prospects.

37
<PAGE> 38

and the Bonne Terre Field, is estimated to be approximately 450 Bcf of natural
gas equivalent. On May 29, 1996, HarCor assigned to South Coast Exploration and
one of its affiliates 40% of its rights in its agreement with Cabot in exchange
for the interest it received in the South Louisiana prospect described below.

West Texas (Permian Basin). In May 1996, the Company entered into an
agreement to participate in a 210 square mile 3-D seismic survey in Reeves
County, Texas with Penwell which, along with its investment partner MCN Energy,
has extensive recent experience in the Permian Basin. Penwell Energy initially
derived its rights to about half of the area in the Penwell survey (74,880 fee
mineral acres held by Texaco) from an agreement dated September 1995 among
Texaco, Penwell and Meridian Oil Inc. Production in the field within or
adjoining gross acreage in which Penwell presently owns or has contingent lease
rights is estimated to be 455 Bcf of natural gas equivalents, most of which has
been produced from the Silurian/Devonian Fusselman formation at depths between
10,000 feet and 17,000 feet, where the Company intends to focus.

South Louisiana (Terrebonne Parish). South Coast Exploration and its
affiliates have acquired an interest in a 46 square mile 3-D seismic survey to
be conducted in south Terrebonne Parish, Louisiana. To date, the Lapeyrouse
Field, which is located in the survey area, has produced approximately 350 Bcf
of natural gas equivalents. Based upon 2-D seismic surveys and reports from
independent engineers, South Coast Exploration's joint venture preliminarily has
identified potential exploration sites in the area to drill an estimated four
test wells in the next 18 months. Two of these potential exploration sites have
been identified in the Bourg Sands between 14,500 feet and 15,500 feet and the
remaining two potential exploration sites have been identified in traps
associated with faulting in a series of Upper Middle Miocene Sands between
15,000 feet and 17,000 feet. South Coast Exploration and its affiliate have each
assigned to HarCor a portion of their interest in this survey. The effectiveness
of the assignment is subject to receipt by HarCor of the other party's consents
to HarCor's participation in the survey.

SOUTH COAST EXCHANGE AGREEMENT

In May 1996, the Company and South Coast Exploration entered into an
exchange agreement (the "South Coast Exchange Agreement") under which the
Company and South Coast Exploration have agreed to use good faith efforts on a
non-exclusive basis to identify and mutually agree upon the exchange of a
portion of their interests in comparable 3-D seismic surveys and related joint
operating agreements and other agreements on or before December 31, 1996. The
interests to be exchanged must be comparable in terms of capital exposure and
reserve potential. Once one set of such interests are identified, the Company
and South Coast Exploration may, but are not obligated to, mutually identify and
agree upon the exchange of additional comparable interests. Pursuant to the
South Coast Exchange Agreement, HarCor assigned to South Coast Exploration and
its affiliate 40% of its rights in its agreement with Cabot in South Texas in
exchange for a 12% interest in the South Louisiana prospect described below.

SOUTH TEXAS AGREEMENTS

In January 1996, the Company entered into a participation agreement with
Cabot (the "Cabot Agreement") providing for the shooting of a 3-D seismic survey
over an area covering approximately 83 square miles in the Hostetter Field in
McMullen and Duval Counties in South Texas. Pursuant to the Cabot Agreement, the
Company is participating with an initial undivided 37.875% ownership interest in
all leases, options, and seismic lease options previously acquired by either
Cabot or the Company, and the Company is obligated to pay 37.875% of the total
3-D survey costs in the prospect area, subject to certain limitations. The Cabot
Agreement also establishes an area of mutual interest (the "Cabot AMI") to be
established over the prospect area which gives the Company the right to
initially acquire 37.875% of any leasehold interest, option or other property
right subsequently acquired by Cabot within the Cabot AMI through January 1,
1999. Conversely, Cabot has the right to acquire its proportionate share of any
leasehold interest, option or other property right subsequently acquired by the
Company within the Cabot AMI.

As of April 1, 1996, Cabot entered into an Exploration Agreement with
Texaco under which Texaco committed 7,800 net acres located within the Cabot AMI
(the "Texaco Agreement") to Cabot's survey and exploration program. Under the
Texaco Agreement, Cabot, among other things, grants to Texaco a non-

38
<PAGE> 39

transferable license to the 3-D survey over a portion of area included in the
Cabot survey. In return, Cabot has the right to propose to Texaco drilling
prospects on the Texaco lands. If Texaco elects to participate in a drilling
prospect on Texaco lands, Cabot will receive a 50% working interest in the
Texaco lands included in a drilling prospect. If Texaco elects not to
participate, Texaco would retain an overriding royalty interest in the Texaco
lands convertible to a working interest at well payout.

On May 2, 1996, Cabot entered into an agreement with Vastar Resources, Inc.
("Vastar") whereby Vastar agreed to contribute 50% of the cost of the 3-D survey
over approximately one-quarter of the acreage of the Cabot AMI which is expected
to reduce the total cost of the 3-D survey.

On May 29, 1996, the Company entered into an agreement with South Coast
Exploration pursuant to which the Company assigned 40% of its rights and
interests under the Cabot Agreement to South Coast Exploration and its
affiliate, which reduced the Company's interest in the rights created under the
Cabot agreements to 22.73%. The effectiveness of the assignments to South Coast
Exploration and its affiliate, however, are contingent on the Company receiving
Cabot's consent to such assignments.

WEST TEXAS AGREEMENTS

In May 1996, the Company entered into an agreement with Penwell (the
"Penwell Agreement") to participate in a multiphase 3-D geophysical survey and
oil and gas exploration program pertaining to an area of mutual interest
covering approximately 210 square miles in Reeves County, Texas (the "Penwell
AMI"). Penwell, as operator of the prospect, has commenced an initial survey
which covers 145 square miles and plans to perform a second survey covering an
additional approximately 65 square miles beginning on or about July 1, 1996.
South Coast Exploration also has entered into an agreement with Penwell with
substantially the same terms as the Penwell Agreement.

Under the Penwell Agreement, the Company paid $372,380 to purchase a 7.5%
participation interest in the 3-D seismic survey and exploration program to be
conducted by Penwell. Additionally, HarCor paid Penwell $231,000 for its
estimated share of phase one survey costs and $99,750 to be applied against
projected phase two survey costs. HarCor also agreed to pay its proportionate
share of all lease acquisition costs.

Penwell derives its oil and gas exploration rights with respect to a
substantial portion of the Penwell AMI from an agreement (the "TMP Exploration
Agreement") executed on September 15, 1995, between Texaco, Meridian Oil Inc.
("Meridian") and Penwell. Under the TMP Exploration Agreement, Texaco
contributed its mineral rights underlying all or part of 117 square miles in
Reeves County, Texas. In addition, Penwell has obtained control of approximately
5,529 acres to date through either leasehold or seismic options within the
Penwell AMI.

Under the TMP Exploration Agreement, Texaco and Meridian granted Penwell
the exclusive right for three years to conduct a 3-D survey and exploration
program within the area of mutual interest established by the TMP Exploration
Agreement (the "Texaco AMI").

Under the TMP Exploration Agreement, Penwell is obliged to conduct a 3-D
survey over a 50 square mile block in the first year and over one additional 50
square mile block during the subsequent two years of the Agreement term. By
conducting a 3-D survey over Texaco's mineral fee lands, Penwell earns the right
to receive an oil and gas lease covering 100% of the working interest in all
depths above approximately 7,500 feet under all lands surveyed by Penwell.

After identifying prospects at depths below 7,500 feet within the Texaco
AMI, Penwell has the right to drill exploratory wells to such depths. If an
exploratory well is successful, Penwell earns 100% of the working interest to
all depths below approximately 7,500 feet in the proration unit for such well
until well payout and a 65% working interest in such well after payout and in
the surrounding lands. At well payout, Texaco and Meridian have the right to
reacquire a 35% working interest in the proration unit for such exploratory
well. Penwell holds a 65% working interest in any development wells drilled on
the Texaco mineral fee lands as a result of a successful exploratory well.

39
<PAGE> 40

SOUTH LOUISIANA AGREEMENTS

In February 1996, South Coast Exploration and its affiliate entered into an
exploration agreement dated February 19, 1996 (the "Louisiana Exploration
Agreement") with Polaris Exploration Corporation ("Polaris"), Frontier Natural
Gas Corporation ("Frontier"), Matagorda Production Company ("Matagorda"). The
Louisiana Exploration Agreement established an area of mutual interest (the
"Louisiana AMI") covering approximately 46 square miles in Terrebonne Parish,
Louisiana for the purpose of conducting 3-D seismic surveys, securing additional
leases and initiating drilling activities on oil and gas prospects. Pursuant to
the Louisiana Exploration Agreement, South Coast Exploration and its affiliate
have a 40% participation interest in oil and gas leases and seismic option
support agreements initially covering approximately 5,529 acres. From its
interest in the Louisiana Exploration Agreement, South Coast Exploration and its
affiliate assigned to the Company a 12% interest in the Louisiana Exploration
Agreement. This assignment, however, is subject to the approval of Polaris,
Frontier and Matagorda and the waiver of certain preferential purchase rights.
If the assignment is approved and all preferential purchase rights are waived,
the Company will be entitled to a 12% participation in all leasehold interests
acquired, all earning agreements entered into, and all geological and
geophysical information generated by, Polaris and Frontier (as designated
prospect generators) pursuant to the Louisiana Exploration Agreement. The
Company will be obligated to pay 12% of all costs and liabilities related to
such operations.

The Louisiana Exploration Agreement terminates three years from the date
when the last of the 3-D data taken from the prospect area has been processed
and delivered to the parties to the agreement.

SELECTIVE OPPORTUNISTIC ACQUISITIONS

PRODUCTION BY GEOGRAPHIC REGION

The following table shows, for the periods indicated, the net production,
measured in Bbls of oil, Mcf of gas and BOEs, attributable to the Company's oil
and gas interests by geographic region:

<TABLE>
<CAPTION>
1993 1994 1995
------------------------------- ------------------------------- ---------------------------------
BBLS MCF BOE BBLS MCF BOE BBLS MCF BOE
------- --------- ------- ------- --------- ------- ------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
San Joaquin Basin(1)..... -- -- -- 131,368 1,315,321 350,588 304,193 3,216,841 840,333
Permian Basin............ 86,006 204,907 120,157 91,404 161,187 118,269 95,966 152,386 121,364
South Texas.............. 26,481 1,272,867 238,626 28,630 1,446,404 269,697 14,098 1,411,708 249,382
Other.................... 66,748 507,029 151,253 60,429 402,729 127,551 48,276 356,144 107,633
------- --------- ------- ------- --------- ------- ------- --------- ---------
Total............ 179,235 1,984,803 510,036 311,831 3,325,641 866,105 462,533 5,137,079 1,318,712
======= ========= ======= ======= ========= ======= ======= ========= =========
</TABLE>

<TABLE>
<CAPTION>
FIRST QUARTER 1995 FIRST QUARTER 1996
----------------------------------- -----------------------------------
BBLS MCF BOE BBLS MCF BOE
------- --------- ------- ------- --------- -------
<S> <C> <C> <C> <C> <C> <C>
San Joaquin Basin(1)........................ 71,653 727,665 192,930 120,239 1,250,535 328,661
Permian Basin............................... 24,411 35,423 30,315 24,170 37,450 30,411
South Texas................................. 2,854 315,878 55,500 3,229 366,114 64,248
Other....................................... 12,601 78,435 25,674 10,554 77,517 23,474
------- --------- ------- ------- --------- -------
Total..................................... 111,519 1,157,401 304,419 158,192 1,731,616 446,794
======= ========= ======= ======= ========= =======
</TABLE>

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

(1) Excludes NGLs.

40
<PAGE> 41

The following table summarizes the Company's producing and shut-in wells
and producing acreage as of March 31, 1996:

<TABLE>
<CAPTION>
GROSS UNDEVELOPED
WELLS(1) NET WELLS(2) PRODUCING ACREAGE ACREAGE
- ------------- ------------- ------------------ ------------------
OIL GAS OIL GAS GROSS NET GROSS NET
- --- --- --- --- ------ ----- ------ -----
<S> <C> <C> <C> <C> <C> <C> <C>
352 79 168 19 30,852 7,626 19,618 7,217
=== == === === ====== ===== ====== =====
</TABLE>

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

(1) The number of gross wells and acreage shown equals the total number of wells
or acres in which a working interest is owned.

(2) The number of net wells or acres shown equals the sum of the fractional
working interests owned in gross wells or acres, expressed as whole numbers.

PRODUCTION, REVENUES AND LIFTING COSTS

The following table shows, for the periods indicated, the average net daily
production, measured in Bbls of oil and Mcf of gas, attributable to the
Company's oil and gas interests, the annual revenues derived by the Company from
the sale of such production, the weighted average selling price per unit and the
weighted average cost to the Company per unit produced:

<TABLE>
<CAPTION>
THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
---------------------------- ------------------
1993 1994 1995 1995 1996
------ ------- ------- ------- -------
(DOLLAR AMOUNTS IN THOUSANDS,
EXCEPT PER UNIT DATA)
<S> <C> <C> <C> <C> <C>
Average Net Daily Production:
Crude oil and condensate (Bbls)............. 505 867 1,267 1,239 1,758
Natural gas (Mcf)........................... 5,514 9,239 14,074 12,860 19,240
Plant NGLS.................................. -- 261 567 412 692
Revenues:
Crude oil and condensate.................... $2,951 $ 4,925 $ 7,625 $ 1,801 $ 2,741
Natural gas................................. 3,518 6,045 8,405 1,883 3,215
Gas plant................................... -- 1,978 6,362 1,785 1,624
Other....................................... 38 12 -- 15 17
------ ------- ------- ------- -------
Total revenues................................ $6,507 $12,960 $22,392 $ 5,484 $ 7,597
====== ======= ======= ======= =======
Costs:
Production costs............................ $2,249 $ 3,610 $ 5,263 $ 1,263 $ 1,437
Gas plant operating expenses................ -- 1,708 3,704 1,410 956
------ ------- ------- ------- -------
Total costs................................... $2,249 $ 5,318 $ 8,967 $ 2,673 $ 2,393
====== ======= ======= ======= =======
Weighted average selling price:
Crude oil and condensate (per Bbl).......... $16.46 $ 15.79 $ 16.49 $ 16.15 $ 17.33
Natural gas liquids (per Bbl)............... $ -- $ 13.95 $ 16.06 $ 16.73 $ 18.16
Natural gas (per Mcf)....................... $ 1.77 $ 1.82 $ 1.64 $ 1.62 $ 1.86
Production costs per BOE (1).................. $ 4.41 $ 4.13 $ 3.99 $ 4.14 $ 3.22
</TABLE>

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

(1) Includes severance and ad valorem taxes and excludes gas plant costs.

Calculation of average selling price per barrel of crude oil and condensate
excludes certain revenues attributable to hydrocarbon liquids and product sales
in 1993 and 1994. All average price data consider the effects of the Company's
fixed-price sales and hedging contracts. See Note 10 of Notes to Consolidated
Financial Statements.

41
<PAGE> 42

DRILLING ACTIVITIES

The following table shows the gross and net number of exploratory and
development wells drilled in the years indicated and the Company's interests
therein:

<TABLE>
<CAPTION>
1993 1994 1995
-------------- --------------- ---------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Exploratory:
Oil................................. -- -- -- -- -- --
Gas................................. -- -- -- -- -- --
Dry................................. -- -- -- -- -- --
Development:
Oil................................. 10 0.74 14 10.50 44 33.00
Gas................................. 4 1.37 2 .60 1 .28
Dry................................. -- -- -- -- -- --
----- ---- ----- ----- ----- -----
Total....................... 14 2.11 16 11.10 45 33.28
==== ==== ==== ===== ==== =====
</TABLE>

RESERVES

The Company's net proved reserves and the standardized measure of
discounted future net cash flows from such proved reserve quantities are shown
in the table below.

<TABLE>
<CAPTION>
TOTAL PROVED RESERVES AS OF
DECEMBER 31,
--------------------------------
1993 1994 1995
------- ------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Estimated proved reserves:
Liquids (MBbl)..................................... -- 2,908 2,979
Crude oil (MBbl)................................... 1,724 10,581 12,358
Natural gas (MMcf)................................. 17,169 69,802 87,637
Crude oil equivalents (MBOE)....................... 4,586 25,123 29,943
Pre-tax SEC 10 Value................................. $20,780 $86,680 $124,498
Percent Proved Undeveloped Reserves (BOE)............ 39.8% 67.4% 69.4%
</TABLE>

The majority of the Company's oil and gas interests is held through mineral
leases which are maintained in effect by current production and will continue to
remain in effect so long as there is production of oil and gas in commercial
quantities from such interests.

PRINCIPAL CUSTOMERS

The following purchasers accounted for more than 10% of the Company's oil
and gas revenues in at least one of the years as indicated:

<TABLE>
<CAPTION>
CUSTOMER 1993 1994 1995
---------------------------------------------------------------- ---- ---- ----
<S> <C> <C> <C>
Cabot Oil and Gas Marketing..................................... 36% 21% --
Kern Oil and Refining........................................... -- 17% 10%
Mock Resources, Inc............................................. -- -- 24%
Valero Gas Marketing, L.P....................................... -- -- 10%
</TABLE>

The Company considers its relationships with the other principal purchasers
to be satisfactory. The Company believes that the loss of any present customer
would not have a material adverse effect on the Company's consolidated business.

42
<PAGE> 43

SALES, MARKETS AND MARKET CONDITIONS

With the exception of the gas produced from the San Joaquin Basin
properties, all of HarCor's production is generally sold at the wellhead or from
on-site storage facilities to oil and gas purchasing companies in the areas
where it is produced. Crude oil and condensate are typically sold at prices
which are based upon posted field prices. The natural gas produced from the San
Joaquin Basin properties is processed at the gas processing plant in which the
Company has a 75% interest. The NGLs which are extracted are sold in the spot
market. Including the natural gas remaining after extraction of the NGLs,
approximately 76% of HarCor's 1995 natural gas production was subject to
fixed-price contracts. The remainder of the Company's natural gas was sold at
spot market prices. The term "spot market" as used herein refers to contracts
with a term of six months or less or contracts which call for a redetermination
of sales prices every six months or earlier.

For much of the past decade, the markets for oil and natural gas have been
volatile. The Company anticipates that such markets will continue to be volatile
over the next year. As an independent oil and gas company, the Company's
revenue, profitability and future rate of growth are substantially dependent
upon prevailing prices for oil and gas, which are in turn dependent upon
numerous factors beyond the Company's control, such as economic, political and
regulatory developments and competition from other sources of energy. A
substantial or extended decline in oil and gas prices could have a material
adverse effect on the Company's financial position, results of operations,
quantities of oil and gas reserves that may be economically produced and access
to capital.

Price fluctuations in the oil market have a significant impact on the
Company's business because all of the Company's oil production is sold at prices
based upon posted field prices which vary monthly. In order to minimize the
price volatility to which the Company is subject, the Company entered into
hedging contracts with third parties covering significant portions of its oil
production in 1995. Additionally, price fluctuations in the gas market also have
a significant impact on the Company's business because approximately 24% of the
Company's 1995 natural gas production was sold at spot market prices and the
Company currently anticipates that approximately 36% of HarCor's estimated
natural gas production for 1996 will be sold at spot market prices based on
contracted volumes at December 31, 1995. The remainder of the Company's gas
production is subject to certain fixed-price contracts. For further information
concerning the Company's fixed-price sales and hedging contracts, see Note 9 of
Notes to Consolidated Financial Statements.

The Company's business is typically seasonal in nature. The demand for the
Company's oil and gas production generally increases during the winter months.
Gas prices in particular have been sensitive to weather patterns in recent
years. Weather conditions at certain times of the year can also affect the
operations of the Company's oil and gas properties and its ability to produce
hydrocarbons in commercially marketable quantities.

COMPETITION

The acquisition, exploration and development of oil and gas properties is a
highly competitive business. Many companies and individuals are engaged in the
business of acquiring interests in and developing onshore oil and gas properties
in the United States. The industry is not dominated by any single competitor or
a small number of competitors. Many entities with which the Company competes
have significantly greater financial resources, staff and experience. The
Company competes with major and independent oil and gas companies for the
acquisition of desirable oil and gas properties, as well as for the equipment
and labor required to operate and develop such properties. Many of these
competitors have financial and other resources substantially in excess of those
available to the Company. Such competitive disadvantages could adversely affect
the Company's ability to acquire desirable prospects or develop existing
prospects.

REGULATION

General. The Company's business is affected by governmental laws and
regulations, including price control, energy, environmental, conservation, tax
and other laws and regulations relating to the petroleum industry. For example,
state and federal agencies have issued rules and regulations that require
permits for the

43
<PAGE> 44

drilling of wells, regulate the spacing of wells, prevent the waste of natural
gas and crude oil reserves through proration, and regulate environmental and
safety matters including restrictions on the types, quantities and concentration
of various substances that can be released into the environment in connection
with drilling and production activities, limits or prohibitions on drilling
activities on certain lands lying within wetlands and other protected areas, and
remedial measures to prevent pollution from current and former operations.
Changes in any of these laws, rules and regulations could have a material
adverse effect on the Company's business. In view of the many uncertainties with
respect to current laws and regulations, including their applicability to the
Company, the Company cannot predict the overall effect of such laws and
regulations on future operations.

The Company believes that its operations comply in all material respects
with all applicable laws and regulations and that the existence of such laws and
regulations have no more restrictive effect on the Company's method of
operations than on other similar companies in the industry.

The following discussion contains summaries of certain laws and regulations
and is qualified in its entirety by reference thereto.

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

Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, and 636-B
("Order No. 636"), which require interstate pipelines to provide open-access
transportation on a basis that is equal for all gas shippers. Although Order No.
636 does not directly regulate the Company's activities, the FERC has stated
that it intends for Order No. 636 to foster increased competition within all
phases of the natural gas industry. It is unclear what impact, if any, increased
competition within the natural gas industry under Order No. 636 will have on the
Company's activities. Although, Order No. 636, assuming it is upheld in its
entirety, could provide the Company with additional market access and more
fairly applied transportation service rates, Order No. 636 could also subject
the Company to more restrictive pipeline imbalance tolerances and greater
penalties for violation of those tolerances. The FERC has issued final orders in
virtually all Order No. 636 pipeline restructuring proceedings. Appeals of Order
No. 636, as well as orders in the individual pipeline restructuring proceedings,
are currently pending and the Company cannot predict the ultimate outcome of
court review. This review may result in the reversal, in whole or in part, of
Order No. 636.

The FERC has clarified that it does not have jurisdiction over natural gas
gathering facilities and services and that such facilities and services are
properly regulated by state authorities. As a result, natural gas gathering may
receive greater regulatory scrutiny by state agencies. The Company's gathering
operations could be adversely affected should they be subject in the future to
state regulation of rates and services, although the Company does not believe
that it would be affected by such regulation any differently than other natural
gas producers or gatherers. In addition, the FERC has approved several transfers
by interstate pipelines of gathering facilities to unregulated gathering
companies, including pipeline affiliates. This could allow such companies to
compete more effectively with independent gatherers, such as the Company.

The Company's natural gas gathering operations are generally subject to
safety and operational regulations relating to the design, installation,
testing, construction, operation, replacement and management of facilities.
Pipeline safety issues have recently become the subject of increasing focus in
various political and administrative arenas at both the state and federal
levels. For example, federal legislation addressing pipeline safety issues has
recently been introduced before Congress. Among other things, the legislation
includes a

44
<PAGE> 45

requirement that states adopt "one-call" notification systems. The Company
cannot predict what effect, if any, the adoption of such legislation might have
on its operations.

The FERC has announced its intention to reexamine certain of its
transportation-related policies, including the manner in which interstate
pipeline shippers may release interstate pipeline capacity under Order No. 636
for resale in the secondary market. While any resulting FERC action would affect
the Company only indirectly, the FERC's current rules and policies may have the
effect of enhancing competition in natural gas markets by, among other things,
encouraging non-producer natural gas marketers to engage in certain purchase and
sale transactions. The Company cannot predict what action the FERC will take on
these matters, nor can it accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which the Company's
natural gas is sold. However, the Company does not believe that it will be
affected by any action taken materially differently than other natural gas
producers and marketers with which it competes.

The FERC has issued a policy statement on how interstate natural gas
pipelines can recover the costs of new pipeline facilities. While this policy
statement affects the Company only indirectly, in its present form, the new
policy should enhance competition in natural gas markets and facilitate
construction of gas supply laterals. However, requests for rehearing of this
policy statement are currently pending. The Company cannot predict what action
the FERC will take on these requests.

Sales of crude oil, condensate and gas liquids by the Company are not
regulated and are made at market prices. The price the Company receives from the
sale of these products is affected by the cost of transporting the products to
market. Effective as of January 1, 1995, the FERC implemented regulations
establishing an indexing system for transportation rates for oil pipelines,
which would generally index such rates to inflation, subject to certain
conditions and limitations. These regulations could increase the cost of
transporting crude oil, liquids and condensates by pipeline. These regulations
are subject to pending petitions for judicial review. The Company is not able to
predict with certainty what effect, if any, these regulations will have on it,
but other factors being equal, the regulations may tend to increase
transportation costs or reduce wellhead prices for such conditions.

Additional proposals and proceedings that might affect the oil and gas
industry are pending before Congress, the FERC and the courts. The Company
cannot predict when or whether any such proposals may become effective. In the
past, the natural gas industry historically has been very heavily regulated.
There is no assurance that the current regulatory approach pursued by the FERC
will continue indefinitely into the future. Notwithstanding the foregoing, it is
not anticipated that compliance with existing federal, state and local laws,
rules and regulations will have a material or significantly adverse effect upon
the capital expenditures, earnings or competitive position of the Company.

Taxation. The operations of the Company, as is the case in the petroleum
industry generally, are significantly affected by federal tax laws, including
the Tax Reform Act of 1986. Certain transactions which were entered into in
connection with the Company's 1987 recapitalization have, under the Tax Reform
Act of 1986, significantly limited the Company's ability to utilize its net
operating losses arising prior to the recapitalization. In addition, certain
1992 equity transactions resulted in additional restrictions on the utilization
of net operating losses arising since 1987. For further information on the
limitations of the Company's net operating loss carryforwards, see Note 10 of
Notes to Consolidated Financial Statements contained herein.

In addition to the foregoing, federal, as well as state tax laws have many
provisions applicable to corporations in general which could affect the
potential tax liability of the Company.

Operating Hazards and Environmental Matters. The oil and gas business
involves a variety of operating risks, including the risk of fire, explosions,
blow-outs, pipe failure, casing collapse, abnormally pressured formations and
environmental hazards such as oil spills, gas leaks, ruptures and discharges of
toxic gases or naturally occurring radioactive materials, the occurrence of any
of which could result in substantial losses to the Company due to injury or loss
of life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, clean-up responsibilities,
regulatory investigation and

45
<PAGE> 46

penalties and suspension of operations. Such hazards may hinder or delay
drilling, development and on-line production operations.

Extensive federal, state and local laws and regulations govern oil and
natural gas operations regulating the discharge of materials into the
environment, restoration of surface locations, plugging and abandonment of wells
or otherwise relating to the protection of the environment. Numerous
governmental departments issue rules and regulations to implement and enforce
such laws which are often difficult and costly to comply with and which carry
substantial penalties for failure to comply. Some laws, rules and regulations
relating to protection of the environment may, in certain circumstances, impose
"strict liability" for environmental contamination, rendering a person liable
for environmental damages and response costs without regard to negligence or
fault on the part of such person. For example, the federal Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended, also
known as the "Superfund" law, imposes strict liability of an owner and operator
of a facility or site where a release of hazardous substances into the
environment has occurred and companies that disposed or arranged for the
disposal of the hazardous substances released at the facility or site. Other
laws, rules and regulations may restrict the rate of oil and natural gas
production below the rate that would otherwise exist. The regulatory burden on
the oil and natural gas industry increases its cost of doing business and
consequently affects its profitability. These laws, rules and regulations affect
the operations and costs of the Company. While compliance with environmental
requirements generally could have a material adverse effect upon the capital
expenditures, earnings or competitive position of the Company, the Company
believes that other independent energy companies in the oil and gas industry
likely would be similarly affected. The Company believes that it is in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse impact on the Company.

Although the Company maintains insurance against some, but not all, of the
risks described above, including insuring the costs of clean-up operations,
public liability and physical damage, there is no assurance that such insurance
will be adequate to cover all such costs or that such insurance will continue to
be available in the future or that such insurance will be available at premium
levels that justify its purchase. The occurrence of a significant event not
fully insured or indemnified against could have a material adverse effect on the
Company's financial condition and operations.

EMPLOYEES

At March 31, 1996, the Company had 11 full-time employees. The Company
believes its relationship with its employees is satisfactory. The Company also
employs technical consultants from time to time. HarCor is not materially
dependent on any of such consultants.

LEGAL PROCEEDINGS

No material lawsuits are pending or, to the best of the Company's
knowledge, have been threatened against it. Due to the nature of its business,
however, the Company, from time to time, may be a party to certain legal or
administrative proceedings arising in the ordinary course of its business.

OFFICE FACILITIES

The Company's corporate headquarters are located at Five Post Oak Park,
Suite 2220, Houston, Texas in rented office space.

46
<PAGE> 47

MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

The names and ages of the Company's executive officers and directors, the
principal occupation or employment of each of them during the past five years
and at present, the name and principal business of the corporation or other
organization, if any, in which such occupation or employment is or was carried
on, directorships of other public companies or investment companies held by
them, and the period during which the directors have served in that capacity
with the Company are set forth below.

<TABLE>
<CAPTION>
PRESENT POSITION DIRECTOR TERM AS DIRECTOR
NAME AGE WITH THE COMPANY SINCE EXPIRES
- ------------------------------ --- ---------------------------------- -------- ----------------
<S> <C> <C> <C> <C>
Mark G. Harrington............ 43 Chairman of the Board and Chief 1987 1998
Executive Officer
Francis H. Roth............... 58 President, Chief Operating Officer 1989 1998
and Director
Gary S. Peck.................. 43 Vice President -- Finance, Chief -- --
Financial Officer and Secretary
Albert J. McMullin............ 39 Vice President -- Land, Contracts -- --
and Acquisitions
Robert J. Cresci.............. 52 Director 1994 1999
Vinod K. Dar.................. 45 Director 1992 1997
David E. K. Frischkorn, Jr.... 45 Director 1992 1997
Ambrose K. Monell............. 41 Director 1987 1999
Herbert L. Oakes.............. 49 Director 1992 1998
Robert A. Shore............... 49 Director 1994 1997
</TABLE>

Mr. Harrington has been Chairman of the Board of Directors and Chief
Executive Officer of the Company since May 1987. He also is President and
controlling shareholder of Harrington and Company International Incorporated
("Harrington and Company"), an investment company which he founded in 1986.
Harrington and Company is the general partner, managing partner or limited
partner of several limited partnerships which in the aggregate own approximately
7.9% of the outstanding Common Stock. In 1977, he joined Carl H. Pforzheimer and
Co., an investment banking firm, where he became a partner in 1980 and remained
as a partner until December 1985. During his eight years with Carl H.
Pforzheimer and Co., he worked in the firm's research and corporate finance
departments. In 1984, Mr. Harrington helped organize Chipco Energy Corporation,
the holding company for the firm's oil and gas assets. He is a director of HCO
Energy Ltd. and Jefferson Gas Systems, Inc. Mr. Harrington holds a Bachelor of
Business Administration degree and a Master of Business Administration degree,
both in finance, from the University of Texas.

Mr. Roth has been President and Chief Operating Officer of the Company
since March 1989. Prior to that time, he served as Vice President -- Production
of the Company since July 1988. He has been employed in various engineering
positions with both Amoco and Chevron in several geographic locations. Prior to
joining the Company, he had been employed for 16 years by MCO Resources, Inc.,
an oil and gas company, in various positions, including General Manager of
Operations and Engineering. He also served as Vice President of Drilling and
Production and Engineering for MCOR Oil and Gas Corporation, a subsidiary of MCO
Resources, Inc. Mr. Roth holds a Bachelor of Science degree in petroleum
engineering from the University of Kansas, a Master of Science degree in
petroleum engineering from the University of Oklahoma and a Master of Business
Administration degree from the University of California.

Mr. Peck joined the Company as Vice President -- Finance and Chief
Financial Officer in October 1989 and became Secretary in November 1989. Prior
to joining the Company, Mr. Peck acted as a financial consultant to the Company.
Mr. Peck was Director of Finance for Herbert L. Farkas Company (a multi-location
furniture and business equipment concern) from 1987 to 1989 and was Vice
President -- Finance and

47
<PAGE> 48

Chief Financial Officer of RAWA, Inc. (a franchising and car rental company)
from 1985 to 1987. Prior to that, Mr. Peck had approximately seven years'
experience in oil and gas accounting management with Minoco Southern Corporation
and MCO Resources, Inc. He graduated from California State University at Long
Beach in 1977 with a Bachelor of Science degree in accounting and finance.

Mr. McMullin joined the Company as Vice President -- Land, Contracts and
Acquisitions in August 1992. Prior to joining the Company, Mr. McMullin was a
gas supply manager for Mitchel Marketing Company since 1991 and for Delhi Gas
Pipeline Corporation during 1990. Mr. McMullin also worked as an Accounts
Manager for United Gas Pipeline from 1987 to 1989. From 1980 to 1985, Mr.
McMullin worked for Atlantic Richfield Company as a landman. He holds a Bachelor
of Arts degree in petroleum land management from the University of Texas and
earned a Masters in Business Administration from the University of St. Thomas.

Mr. Cresci has served as a Managing Director of Pecks Management Partners
Ltd., an investment management firm, since September 1990. From 1985 to 1990 Mr.
Cresci was Vice President of Alliance Capital Management L.P. Mr. Cresci
currently serves as a director of Serv-Tech, Inc., EIS International, Inc.,
Sepracor, Inc., Vestro Natural Foods, Inc., Olympic Financial, Ltd., GeoWaste,
Inc., Hitox, Inc., Natures Elements, Inc., Garnet Resources Corporation, Meris
Laboratories, Inc. and several private companies.

Mr. Dar has been President and Chairman of Jefferson Gas Systems, Inc. (a
natural gas and electric power co-investment concern) since May 1991, and the
Managing Director of Dar & Company (a consulting firm to energy companies and
financial institutions) since August 1990. Currently, he is Senior Advisor of
RCG/Hagler, Bailly & Company, an international management consulting firm he
helped found in 1980. He was also the Chairman of Sunrise Energy Services, Inc.
between 1992 and 1994. Since 1980, Mr. Dar has held a variety of executive
positions in the natural gas industry and with management consulting firms. He
has been the Senior Vice President of American Exploration Company, an oil and
gas firm, and Executive Vice President and Director of Hadson Corporation, a
diversified public company. He was the founder and Chief Executive Officer of
four major Hadson subsidiaries, Hadson Gas Systems, Hadson New Mexico, Hadson
Liquid Fuels and Hadson Electric. He has a Bachelor of Science degree in
engineering and a Master's degree in management and finance from MIT, where he
also received his doctoral training in economics. See "Transactions with Related
Parties."

Mr. Frischkorn is a financial consultant to the oil and gas industry. From
January 1993 through March 1996, he was Senior Vice President and Managing
Director of the Energy Corporate Finance Department of Rauscher Pierce Refsnes,
Inc., an investment banking firm. From 1988 to 1992, he was President of
Frischkorn & Co., a Houston, Texas-based merchant banking firm specializing in
oil and gas corporate finance services. Prior to that he served as Vice
President, Energy Group of Kidder, Peabody & Co. in Houston, Texas and Senior
Vice President, Corporate Finance of Rotan Mosle, Inc. in Houston. He holds a
Bachelor of Arts degree in economics and German from Tufts University and a
Masters of Business Administration from Columbia.

Mr. Monell has been Vice President and a director of Harrington and Company
since 1986. He has been active in the oil and gas industry since 1976. In 1976,
he co-founded Alexander & Ambrose Oil Corporation, a privately-held Denver-based
exploration company. He graduated from the University of Virginia in 1976 with a
Bachelor of Science degree in foreign affairs.

Mr. Oakes is Managing Director and a principal of Oakes, Fitzwilliams & Co.
Limited, a member of the London Stock Exchange, which he founded in 1987. In
1973, he joined Dillon, Read & Co. Inc., an investment banking firm, in London.
In 1982, he formed H. L. Oakes & Co. Limited specializing in arranging venture
and development capital for U.S. and U.K. corporations. He is a director of
Shared Technologies, Inc., The New World Power Corporation and a number of
private corporations in the U.S. and the U.K.

48
<PAGE> 49

Mr. Shore was founder and has been Chief Executive Officer of Bakersfield
Energy Resources, Inc. since 1990. He is responsible for evaluating and
negotiating acquisitions, and planning the development of oil and gas properties
for Bakersfield Energy Resources, Inc. For 20 years prior to founding
Bakersfield Energy Resources, Inc., Mr. Shore held various engineering,
supervisory and management positions with Mission Resources, Texaco Inc. and
Getty Oil Company in California. Mr. Shore holds a Bachelor of Science degree in
petroleum engineering from Stanford University. He is a member of the American
Petroleum Institute, the Society of Petroleum Engineers and the California
Independent Petroleum Association. Mr. Shore also serves as a Director of the
Stanford University Petroleum Investment Fund.

COMMITTEES AND MEETINGS OF THE BOARD OF DIRECTORS

The Board of Directors has established an Audit Committee and a Stock
Option and Compensation Committee. An Executive Committee was terminated
subsequent to the 1995 Annual Meeting. The Company does not have a nominating
committee.

The current members of the Audit Committee are David E. K. Frischkorn, Jr.
and Herbert L. Oakes, Jr. The responsibilities of the Audit Committee include
reviewing the scope and results of audits by the Company's independent auditors,
the Company's compliance with all accounting and financial reporting
requirements, the Company's internal accounting controls, the scope of other
services performed by independent auditors, and the cost of all accounting and
financial services, and to make recommendations to the Board of Directors as to
the appointment of the Company's independent auditors. The Audit Committee held
one meeting during 1995.

The current members of the Stock Option and Compensation Committee are
Vinod K. Dar and Herbert L. Oakes. The functions of the Stock Option and
Compensation Committee are to monitor the Company's executive compensation
plans, practices and policies, including all salaries, bonus and stock option
awards and fringe benefits, and to make recommendations to the Board of
Directors as to changes in existing executive compensation plans and the
formulation and adoption of new executive compensation plans. The Stock Option
and Compensation Committee held two meetings during 1995.

During the year ended December 31, 1995, the Board of Directors held five
meetings. In 1995, each incumbent director attended at least 75% of the
aggregate of the total number of meetings of the Board of Directors and the
total number of meetings held by all committees on which he served (in each case
held during the periods that he served).

COMPENSATION OF DIRECTORS

During 1995, nonemployee members of the Board of Directors received annual
compensation of $10,000 plus $1,000 for each meeting of the Board of Directors
attended in person ($250 per telephonic meeting) and reimbursement for their
reasonable expenses incurred in connection with their duties and functions as
directors. Directors of the Company who are also employees do not receive any
compensation for their services as directors.

On October 14, 1992, the Board of Directors adopted the Company's 1992
Nonemployee Directors' Stock Option Plan (the "Directors' Option Plan"). Under
the Directors' Option Plan, upon the later of the effective date of the
Directors' Option Plan or the date of their initial election or appointment to
the Board of
Directors, directors who are not employees of the Company were granted options
to purchase 20,000 shares of Common Stock at an exercise price equal to the fair
market value of the Common Stock on the date of grant. Thereafter, and so long
as the Directors' Option Plan is in effect, upon the completion of each full
year of service on the Board of Directors, each nonemployee director continuing
to serve as a director will automatically be granted an additional option to
purchase 5,000 shares of Common Stock at an exercise price equal to 110% of the
fair market value of the Common Stock on the date of grant. All options granted
under the Directors' Option Plan vest in equal parts over two years.

Upon the first anniversary of their election to the Board of Directors
effective (July 6, 1995), Messrs. Cresci and Shore were each automatically
granted options to purchase 5,000 shares of common stock

49
<PAGE> 50

at an exercise price of $3.7125 per share which was equal to 110% of the fair
market value of the common stock on such date. Upon completion of each of their
third full year of service after the effective date of the Directors' Option
Plan (October 14, 1995), Messrs. Dar, Frischkorn and Monell were each
automatically granted options to purchase 5,000 shares of Common Stock at an
exercise price equal to $3.1625 per share, 110% of the fair market value of the
Common Stock on such date. Upon the third anniversary of his initial election to
the Board of Directors (November 17, 1995), Mr. Oakes was automatically granted
options to purchase 5,000 shares of Common Stock at an exercise price equal to
$2.6125 per share, 110% of the fair market value of the Common Stock on such
date.

EXECUTIVE COMPENSATION

The following table sets forth certain information regarding compensation
earned during 1995 by the Company's Chief Executive Officer and each of the
Company's two other most highly compensated executive officers (collectively,
the "Named Executive Officers") based on salary and bonus earned in 1995:

SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
LONG-TERM
AWARDS
ANNUAL COMPENSATION ----------
-------------------------------------- SECURITIES ALL OTHER
NAME AND OTHER ANNUAL UNDERLYING COMPENSATION
PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION(1) OPTIONS(2) (3)
- --------------------------- ---- -------- ------- --------------- ---------- ------------
<S> <C> <C> <C> <C> <C> <C>
Mark G. Harrington......... 1995 $190,000 $70,417 $ -- 50,000 $3,699
Chairman of the Board 1994 190,000 62,500 -- 148,750 3,699
and Chief Executive 1993 190,000 17,917 -- 40,000 3,455
Officer

Francis H. Roth............ 1995 125,000 70,208 -- 18,000 5,113
President and Chief 1994 125,000 -- -- 75,625 5,113
Operating Officer 1993 125,000 30,209 -- 25,000 4,779

Gary S. Peck............... 1995 100,000 39,167 -- 16,000 2,306
VicePresident -- Finance, 1994 100,000 -- -- 42,500 2,306
Chief Financial Officer 1993 100,000 24,167 -- 17,500 2,156
and Secretary

Albert J. McMullin......... 1995 73,770 8,026 -- 10,000 --
Vice President -- Land, 1994 67,000 5,025 -- 33,500 --
Contracts and Acquisitions
</TABLE>

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

(1) Does not include perquisites and other personal benefits because the value
of these items did not exceed the lesser of $50,000 or 10% of reported
salary and bonus of any of the Named Executive Officers.

(2) No stock appreciation rights ("SARs") were granted to any of the Named
Executive Officers during any of the years presented.

(3) Such amounts were premiums paid by the Company for annual disability
insurance for each such officer.

50
<PAGE> 51

STOCK OPTION GRANTS DURING 1995

The following table provides details regarding stock options granted to the
Named Executive Officers in 1995. The Company does not have any outstanding
SARs.

OPTION GRANTS IN 1995

<TABLE>
<CAPTION>
% OF POTENTIAL
TOTAL REALIZABLE VALUE AT
NUMBER OPTIONS ASSUMED ANNUAL
OF GRANTED EXERCISE RATES OF STOCK
SECURITIES TO OR PRICE APPRECIATION
UNDERLYING EMPLOYEES BASE FOR OPTION TERM
OPTIONS IN PRICE -------------------
NAME GRANTED(#)(1) 1995 ($/SH)(2) EXPIRATION DATE 5%($) 10%($)
- ---------------------- ------ ----- ----- ------------------ ------- -------
<S> <C> <C> <C> <C> <C> <C>
Mark G. Harrington.... 50,000 41.7% $2.89 September 26, 2000 $23,820 $67,215
Francis H. Roth....... 18,000 15.0% $2.63 September 26, 2000 $13,255 $28,877
Gary S. Peck.......... 16,000 13.3% $2.63 September 26, 2000 $11,782 $25,669
Albert J. McMullin.... 10,000 8.3% $2.63 September 26, 2000 $ 7,364 $16,043
</TABLE>

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

(1) Fifty percent of the options become exercisable on September 26, 1996 (the
first anniversary of the date of grant), and the remaining 50% become
exercisable on September 26, 1997. If the Company recapitalizes or
otherwise changes its capital structure, thereafter upon any exercise of an
option the optionee will be entitled to purchase, in lieu of the number and
class of shares of Common Stock then covered by such option, the number and
class of shares of stock and securities to which the optionee would have
been entitled pursuant to the terms of the recapitalization if, immediately
prior to such recapitalization, the optionee had been the holder of record
of the number of shares of Common Stock then covered by such option. If
there is a Corporate Change, as defined in the 1994 Stock Option Plan, then
the Stock Option and Compensation Committee, acting in its sole discretion,
has the following alternatives, which may vary among individual optionees:
(1) accelerate the time at which options then outstanding may be exercised,
(2) require the surrender to the Company by selected optionees of some or
all of the outstanding options held by such optionees, in which event the
Committee will thereupon cancel such options and pay to each optionee a
certain amount of cash or (3) make such adjustments to the options then
outstanding as the Committee deems appropriate to reflect such Corporate
Change. Any adjustment provided for pursuant to this paragraph will be
subject to any required stockholder action.

(2) The exercise price per share with respect to the stock options granted to
Messrs. Roth and Peck in 1995 is equal to the closing bid price of the
Common Stock on the date of grant thereof, as quoted by the National
Association of Securities Dealers, Inc. Automated Quotation System
("NASDAQ"). Pursuant to the terms of the 1994 Stock Option Plan, because
Mr. Harrington is deemed to own more than 10% of the Common Stock, the
exercise price per share of all options granted to him in 1995 was 110% of
the closing bid price of the Common Stock on the date of grant thereof, as
quoted by NASDAQ.

51
<PAGE> 52

1995 OPTION EXERCISES AND OUTSTANDING STOCK OPTION VALUES AS OF DECEMBER 31,
1995

The following table shows the number of shares acquired by the Named
Executive Officers upon their exercise of stock options during 1995, the value
realized by such Named Executive Officers upon such exercises, the number of
shares of Common Stock covered by both exercisable and non-exercisable stock
options as of December 31, 1995 and their values at such date.

<TABLE>
<CAPTION>
NUMBER OF SECURITIES
UNDERLYING UNEXERCISED VALUE OF UNEXERCISED
OPTIONS AT IN-THE-MONEY OPTIONS AT
SHARES DECEMBER 31, 1995 (#) DECEMBER 31, 1995 ($)(1)
ACQUIRED ON VALUE --------------------------- ---------------------------
EXERCISE (#) REALIZED ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
------------ ------------ ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Mark G. Harrington........... -- -- 204,500 112,500 12,750 --
Francis H. Roth.............. -- -- 102,500 48,000 12,750 --
Gary S. Peck................. -- -- 101,500 31,000 23,375 --
Albert J. McMullin........... -- -- 22,500 17,500 -- --
</TABLE>

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

(1) The closing bid price of the Common Stock as quoted by NASDAQ on December
31, 1995, the date of exercise of such options, was $2.625. The value
realized is calculated on the basis of the difference between the exercise
price of such options and $2.625, multiplied by the number of shares of
Common Stock issued upon exercise. The option price for exercisable options
granted to Mr. Harrington, Mr. Roth and Mr. Peck covering 30,000, 30,000 and
55,000 shares, respectively, is $2.20 per share. The option prices for the
remaining exercisable options and all of the unexercisable options are
higher than $2.625 and therefore no value is ascribed to such options in the
above table.

RESTRICTED SHARE VALUES AS OF DECEMBER 31, 1995

The following table shows the value of restricted shares of common stock
granted to the Named Executive Officers as of December 31, 1995:

<TABLE>
<CAPTION>
NUMBER AND VALUE OF
RESTRICTED SHARES AT
DECEMBER 31, 1995
----------------------------
NAME SHARES(#)(1) VALUE($)(2)
----------------------------------------------------------- ------------ -----------
<S> <C> <C>
Mark G. Harrington......................................... 23,750 62,344
Francis H. Roth............................................ 15,625 41,016
Gary S. Peck............................................... 12,500 32,816
Albert J. McMullin......................................... 8,500 22,312
</TABLE>

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

(1) The Restricted Shares may not be sold, tendered, assigned, transferred,
pledged or otherwise encumbered prior to the earliest of April 28, 1997
(lapse date), the date of a grantee's death or disability, or the date of a
"Change of Control" of the Company, as defined in the Restricted Stock
Agreement. In the event that a grantee terminates employment with the
Company prior to the lapse date, the Restricted Shares shall revert back to
the Company; provided, however, in the event a grantee is involuntarily
terminated for any reason other than cause, the Compensation Committee of
the Board of Directors of the Company administering this Agreement may, at
its sole discretion, determine to release a prorated number of Restricted
Shares, based on the number of months of active employment service during
the restriction period, as a percentage of the total months of the
restriction period.

(2) The value of Restricted Shares at December 31, 1995 is calculated by
multiplying the number of Restricted Shares by the December 31, 1995 closing
bid price of the common stock as quoted by NASDAQ, which was $2.625 per
share.

DIRECTOR AND OFFICER LIABILITY; INDEMNIFICATION

The Company's Certificate of Incorporation (the "Certificate") states that
directors of the Company shall not be personally liable to the Company or its
stockholders for monetary damages for breach of fiduciary

52
<PAGE> 53

duty as a director, provided, however, that the Certificate does not eliminate
or limit the liability of a director (i) for any breach of his duty of loyalty
to the Company or its stockholders, (ii) for acts or omissions not in good faith
or which involve intentional misconduct or a knowing violation of the law, (iii)
under Section 174 of the General Corporation Law of the State of Delaware
("Delaware GCL"), or (iv) for any transaction from which the director derived an
improper personal benefit. In addition, these provisions do not eliminate the
liability of a director for violations of federal securities laws, nor do they
limit the rights of the Company or its stockholders, in appropriate
circumstances, to seek equitable remedies such as injunctive or other forms of
non-monetary relief. Such remedies may not be available in all cases.

The Company's By-laws (the "By-laws") further provide that each person who
was or is made a party or is threatened to be made a party to or is involved in
a proceeding, whether civil, criminal, administrative or investigative, by
reason of the fact that he, or a person of whom he is the legal representative,
is or was a director or officer of the Company or is or was serving at the
request of the Company as a director or officer of another corporation, or of a
partnership, joint venture, trust or other enterprise, shall be indemnified and
held harmless by the Company to the fullest extent authorized by the Delaware
GCL; provided, however, that, except as provided below the Company shall
indemnify any person seeking indemnity in connection with an action, suit or
proceeding (or part thereof) initiated by such person only if such action, suit
or proceeding (or part thereof) was authorized by the Board of Directors of the
Company.

Under the Delaware GCL, directors and officers may be indemnified against
expenses (including attorneys' fees), judgments, fines and amounts paid in
settlement in connection with specified actions, suits or proceedings, whether
civil, criminal, administrative or investigative if they acted in good faith and
in a manner they reasonably believed to be in or not opposed to the best
interests of the corporation, and, with respect to any criminal action or
proceedings, had no reasonable cause to believe their conduct was unlawful.

The Company has entered into indemnification agreements (the "Agreement")
with its directors which provide that in the event a director was, is or becomes
a party to or witness or other participant in, or is threatened to be made a
party to or witness or other participant in, any threatened, pending or
completed action, suit or proceeding, or any inquiry or investigation, whether
instituted by or in the name of the Company or any other party, that such
director in good faith believes might lead to the institution of any such
action, suit or proceeding, whether civil, criminal, administrative,
investigative or other (a "Claim") by reason of (or arising in part out of) any
event or occurrence related to the fact that such director is or was a director
or, officer of the Company, or is or was serving at the request of the Company
as a director or officer, of another corporation, partnership, joint venture,
employee benefit plan, trust or other enterprise, or occurring by reason of
anything done or not done by such director in any such capacity (an
"Indemnifiable Event"), the Company will indemnify such director to the full
extent authorized or permitted by law as soon as practicable against any and all
expenses (including, without limitation, attorneys' fees and all other costs,
expenses and obligations reasonably paid or incurred in connection with
investigating, defending, being a witness in or participating in (including on
appeal), or preparing to defend, be a witness in or participate in any Claim
relating to any Indemnifiable Event) ("Expenses"), judgments, fines, penalties,
taxes and any and all amounts paid in settlement (including all interest,
assessments and other charges paid or payable in connection with or in respect
of such Expenses, judgments, fines, penalties, taxes or amounts paid in
settlement) of such Claim. The Company also has a Directors and Officers
Insurance and Company Reimbursement Policy which protects directors and officers
of the Company.

Notwithstanding the other provision of the Agreements, to the extent that
any director has served as a witness on behalf of the Company or has been
successful, on the merits or otherwise, in defense of any or all Claims relating
in whole or in part to any Indemnifiable Event, or in defense of any issue or
matter therein, including, without limitation, dismissal without prejudice, such
director will be indemnified against Expenses reasonably paid or incurred by him
or on his behalf in connection therewith.

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<PAGE> 54

PRINCIPAL AND SELLING STOCKHOLDERS

The following table sets forth information as to the number and percentage
of shares of Common Stock owned beneficially as of March 26, 1996 and as
adjusted to reflect the sale of Common Stock offered hereby by (i) each person
known to the Company to be the beneficial owner of more than 5% of the Common
Stock, (ii) each director and each executive officer, (iii) each of the Selling
Stockholders (including warrantholders selling warrants to the Underwriters in
connection with this Offering) and (iv) all directors and officers of the
Company as a group. Unless otherwise indicated in the footnotes following the
table, the named beneficial owner had sole voting and investment power over the
shares of Common Stock shown as beneficially owned by them.

<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP BENEFICIAL OWNERSHIP
PRIOR TO OFFERING AFTER OFFERING
--------------------- ---------------------
NUMBER OF NUMBER OF SHARES NUMBER OF
SHARES PERCENT BEING OFFERED SHARES PERCENT
--------- ------- ---------------- --------- -------
<S> <C> <C> <C> <C> <C>
Harrington and Company International
Incorporated(3).................... 690,768 7.9 -- 690,768 5.0
Robert J. Cresci(4)(5)............... 1,110,000 12.7 1,100,000 10,000 *
Vinod K. Dar(4)...................... 32,500 * -- 32,500 *
David E. K. Frischkorn, Jr.(4)....... 27,500 * -- 27,500 *
Mark G. Harrington(4)(6)............. 919,018 10.2 -- 919,018 6.5
Ambrose K. Monell(4)................. 31,421 * -- 31,421 *
Herbert L. Oakes(4).................. 32,500 * -- 32,500 *
Gary S. Peck(4)...................... 131,500 1.5 -- 131,500 *
Francis H. Roth(4)................... 160,625 1.8 -- 160,625 1.2
Robert A. Shore(4) (7)............... 1,111,084 11.6 240,941 867,143 5.9
FMR Corp.(8)......................... 550,000 5.9 -- 550,000 3.8
Bakersfield Energy Resources,
Inc.(7)(9)......................... 1,098,084 11.5 240,941 857,143 5.9
Granite Capital L.P.(10)............. 612,092 6.8 -- 612,092 4.4
Pecks Management Partners Ltd.(11)... 1,100,000 12.6 1,100,000 -- --
Trust Company of the West(12)........ 1,730,710 19.3 -- 1,730,710 12.4
Wellington Management Company(13).... 666,700 7.7 -- 666,700 4.8
All Directors and Officers as a group
(10 persons)(5)(6)(7)(14).......... 3,584,148 35.2 1,340,941 2,243,207 14.7
</TABLE>

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

* Less than 1%

(1) Information with respect to beneficial ownership is based on information
publicly available or furnished to the Company by each person included in
this table.

(2) Includes, in each case, shares deemed beneficially owned by such persons or
entities pursuant to Rule 13d-3 promulgated under the Securities Exchange
Act of 1934, as amended, because such persons or entities have the right to
acquire such shares within 60 days upon the exercise of stock options or
similar rights or because such persons or entities have or share investment
or voting power with respect to such shares.

(3) The business address of Harrington and Company International Incorporated
is 4400 Post Oak Parkway, Suite 2220, Houston, Texas 77027. Such amount
includes (i) 372,305 shares held by Harrington and Company EV Fund I, Ltd.,
and (ii) 309,868 shares held by Harrington and Company EV Fund II, Ltd.
(71,429 shares of which are issuable within 60 days upon conversion of
Series A Preferred Stock held by Harrington and Company EV Fund II, Ltd.),
of which limited partnerships Harrington and Company International
Incorporated is the general or managing partner. The shares held by each
such limited partnership are also deemed to be beneficially owned by such
limited partnership. Harrington and Company International Incorporated
disclaims beneficial ownership of such shares.

54
<PAGE> 55

(4) Includes 10,000, 27,500, 27,500, 204,500, 27,500, 27,500, 101,500, 27,500,
102,500 and 10,000 shares for Messrs. Cresci, Dar, Frischkorn, Harrington,
Monell, Oakes, Peck, Roth and Shore, respectively, purchasable within 60
days upon the exercise of stock options.

(5) Includes 1,100,000 shares deemed to be beneficially owned by Pecks
Management Partners Ltd., of which Mr. Cresci is a managing director (See
footnote 12). As a result, Mr. Cresci may be deemed to share voting and
investment power with respect to such shares. Mr. Cresci disclaims
beneficial ownership of such shares.

(6) Mr. Harrington is the Chief Executive Officer and Chairman of the Board of
Directors of the Company. The number of shares indicated includes 690,768
shares deemed to be beneficially owned by Harrington and Company
International Incorporated (see footnote 3 above) of which Mr. Harrington
is the majority stockholder, the President and a director. As a result,
voting and investment power over such shares may be deemed to be shared
between Mr. Harrington and Harrington and Company International
Incorporated. Mr. Harrington disclaims beneficial ownership of such shares.

(7) Includes 1,098,084 shares deemed to be beneficially owned by Bakersfield
Energy Resources, Inc., of which Mr. Shore is the Chief Executive Officer
and a director (see footnote 10). As a result, Mr. Shore may be deemed to
share voting and investment power with respect to such shares. Mr. Shore
disclaims beneficial ownership of such shares. Also includes 3,000 shares
purchased for the benefit of Mr. Shore's daughter. Mr. Shore disclaims
beneficial ownership of such shares.

(8) The principal business address for FMR Corp. is 82 Devonshire Street,
Boston, Massachusetts 02109. Consists of 550,000 shares issuable upon
exercise of a warrant granted to Fidelity Management & Research Company
("Fidelity"), a wholly-owned subsidiary of FMR Corp., as a result of
Fidelity's acting as investment advisor to various investment companies
registered under the Investment Company Act of 1940. FMR Corp. disclaims
sole power to vote or direct the voting of the shares owned directly by the
Fidelity Funds, which power resides with the Funds' Boards of Trustees.
Fidelity carries out the voting of the shares under written guidelines
established by the Funds' Boards of Trustees. FMR Corp., through its
control of Fidelity, and the Funds each has sole power to dispose of the
550,000 shares owned by the Funds.

(9) The principal business address for Bakersfield Energy Resources, Inc. is
2131 Mars Court, Bakersfield, California 93308. Includes 857,143 shares of
common stock issuable to Bakersfield Gas, L.P. upon its conversion of
30,000 shares of Series E Preferred Stock, of which limited partnership
Bakersfield Energy Resources, Inc. is the general or managing partner. The
shares held by such limited partnership are also deemed to be beneficially
owned by such limited partnership.

(10) The principal business address for Granite Capital L.P. is 126 East 56th
Street, New York, New York 10022. Includes 256,400 shares of common stock
issuable within 60 days upon conversion of 10,000 shares of the Series C
Preferred Stock. Also includes 45,000 shares beneficially owned by an
affiliate of Granite Capital L.P. and 3,000 shares beneficially owned by
certain managed accounts for which Granite Capital is the investment
manager and shares voting and investment power. Granite Capital L.P.
disclaims beneficial ownership of such 3,000 shares. Messrs. Walter F.
Harrison III and Lewis Eisenberg may be deemed to share voting and
investment power with respect to the shares owned by Granite Capital L.P.
Messrs. Harrison III and Eisenberg disclaim beneficial ownership of such
shares.

(11) The principal business address for Pecks Management Partners Ltd. is One
Rockefeller Plaza, New York, New York 10020. All such shares are
beneficially owned by three investment advisory clients of Pecks Management
Partners Ltd. As investment manager for such clients, Pecks Management
Partners Ltd. may be deemed to share voting and investment power with
respect to such shares.

(12) The business address of Trust Company of the West ("TCW") is 865 South
Figueroa, Suite 1800, Los Angeles, CA 90017. Includes 1,474,359 shares
beneficially owned by a General Mills pension fund, which shares TCW
controls voting and investment power as Investment Manager and Custodian.
TCW disclaims beneficial ownership of the 1,474,359 shares. Mr. Arthur R.
Carlson may be deemed to have voting and investment power with respect to
the shares owned by TCW. Mr. Carlson disclaims beneficial ownership of such
shares.

55
<PAGE> 56

(13) The principal business address for Wellington Management Company is 75
State Street, Boston, Massachusetts 02109. Such shares are also deemed
beneficially owned by Wellington Trust Co., N.A., a subsidiary of
Wellington Management Company. Mr. Binkley Shorts may be deemed to have
voting and investment power with respect to such shares. Mr. Shorts
disclaims beneficial ownership of such shares.

(14) Includes 1,514,572 shares purchasable within 60 days upon the exercise of
stock options or warrants held or deemed to be owned by all officers and
directors.

Holders of the Company's Series B, C and E Preferred Stock have certain
voting rights, including the right to vote together with the holders of the
common stock on all matters voted upon by the holders of the common stock. In
all such matters, holders of the Series B, C and E Preferred Stock have the
number of votes per share of such preferred stock equal to the whole number of
shares of common stock into which each share of such preferred stock is
convertible. The outstanding shares of Series B Preferred Stock are held by (i)
Citibank, N.A., as Trustee for the United Technologies Corporation Master
Retirement Trust, United Technologies Building, Hartford, Connecticut 06101
(25%), (ii) Bankers Trust Company, as Trustee of the Hughes Aircraft Company
Retirement Plan, 7200 Hughes Terrace, Los Angeles, California 90045-0066 (25%),
and (iii) Bankers Trust Company, as Trustee of the GTE Service Corporation Plan
for Employees' Pensions, One Stamford Place, Stamford, Connecticut 06904 (50%).
All of the outstanding shares of the Series C Preferred Stock are held by
Granite Capital Partners, L.P., 666 Fifth Avenue, 33rd Floor, New York, New York
10103. All outstanding shares of the Series E Preferred Stock are held by
Bakersfield Gas, L.P., 2131 Mars Court, Bakersfield, California 93308.

TRANSACTIONS WITH RELATED PARTIES

The Company completed an agreement with Bakersfield Gas, L.P. in June 1995
for the exchange of a warrant to purchase 1,000,000 shares of Common Stock for
182,500 shares of Common Stock of the Company. This warrant had an exercise
price of $5.00 per share and would have expired on June 30, 2001. Robert A.
Shore, one of the Company's directors, is the Chief Executive Officer of
Bakersfield Energy Resources, Inc., the general partner of Bakersfield Gas, L.P.

The Company completed an agreement in June 1995 with the former holders of
its Series D Preferred Stock, concurrently with the completion of the sale of
the Senior Notes, for the exchange of warrants to purchase 3,424,666 shares of
Common Stock for 1,100,000 shares of Common Stock of the Company. These warrants
had an exercise price of $3.67 per share and would have expired two years
following the date of redemption of the Series D Preferred Stock. Robert J.
Cresci, one of the Company's directors, is a managing director of Pecks
Management Partners Ltd., the investment advisor to the former holders of its
Series D Preferred Stock.

Vinod K. Dar, one of the Company's directors, was the Chairman of the Board
of Directors and Chief Executive Officer of Sunrise Energy Services, Inc.
("Sunrise Energy") from October 1992 to October 1994. As part of the Company's
acquisition of the San Joaquin Basin properties, the Company was assigned an
interest in a previously existing gas marketing contract with Sunrise Energy
Marketing Company ("Sunrise Marketing"), a subsidiary of Sunrise Energy, whereby
Sunrise Marketing agreed to pay $1.97 per one million British thermal units
("MMBtu") for the delivery of 2,250 MMBtu of gas per day from the San Joaquin
Basin properties during June, July and August of 1994. As of December 20, 1994,
Sunrise Marketing owed the Company approximately $92,000 for gas delivered by
the Company during the term of such contract. On November 15, 1994, Sunrise
Marketing filed a voluntary petition for protection under Chapter 11, Title 11
of the United States Bankruptcy Code. The $92,000 amount owed to the Company by
Sunrise Marketing is an unsecured claim and, as such, the Company is unable to
determine whether such amount will be paid and if such amount is paid in full or
in part, when such amount will be paid.

56
<PAGE> 57

DESCRIPTION OF CAPITAL STOCK AND OTHER SECURITIES

COMMON STOCK

The Company's total authorized capital stock consists of 25,000,000 shares
of $.10 par value Common Stock and 1,500,000 shares of $.01 par value preferred
stock. All of the outstanding Common Stock is fully paid and nonassessable. Each
share of Common Stock is entitled to one vote at stockholders' meetings and will
be equal to each other share of Common Stock with respect to voting rights,
liquidation rights and dividend rights. A majority of the outstanding capital
stock eligible to vote at a meeting constitutes a quorum for voting purposes.
Stockholders do not have preemptive rights to purchase additional shares of
Common Stock. The Common Stock has no subscription, conversion or redemption
rights. Each holder of Common Stock on liquidation is entitled to receive a
pro-rata share of the Company's assets available for distribution to such
stockholders after the required liquidation payment is made on any outstanding
shares of preferred stock. As of May 30, 1996, there were 8,696,207 shares of
Common Stock outstanding and held of record by approximately 1,746 persons and
7,124,231 shares reserved for issuance upon exercise of outstanding warrants,
options and convertible securities.

The Company has never paid dividends on its Common Stock and, pursuant to
the terms of the Senior Notes and the Credit Facility, the Company is restricted
from the payment of dividends on its Common Stock. Additionally, pursuant to the
terms of the Company's preferred stock, the Company is restricted from the
payment of dividends on the Common Stock (except dividends paid in shares of
capital stock) unless the Company is current in its payment of dividends on such
preferred stock. Management intends to retain any future earnings for future
acquisitions and the operations of the Company and does not anticipate paying
any cash dividends in the foreseeable future.

The Company currently has outstanding options to purchase 898,500 shares of
Common Stock. Such options have an aggregate average exercise price of $3.34 and
expire between December 31, 1995 and November 17, 2000. The Company also
currently has outstanding warrants to purchase 2,289,791 shares of Common Stock.
Such warrants have an aggregate average exercise price of $3.83 and expire
between November 23, 1996 and July 25, 2000.

In addition, the Company currently intends to grant incentive compensation
in the form of warrants to purchase up to 60,000 shares of Common Stock to
certain key geologists of the GeoTeam and to South Coast Exploration. The
purpose of these grants is to align the interests of the GeoTeam and South Coast
Exploration with those of the shareholders of the Company. Accordingly, the
vesting of these warrants will depend upon the aggregate replacement and finding
costs to the Company of replacing its current reserves in the South Texas, West
Texas and Terrebonne Parish projects.

PREFERRED STOCK

As of May 30, 1996, 5,000 shares of Series A 8% Cumulative Convertible
Preferred Stock (the "Series A Preferred Stock") were outstanding. The Series A
Preferred Stock (i) is convertible into Common Stock at a conversion price of
$3.50 per share of Common Stock, subject to certain anti-dilution provisions;
(ii) is redeemable at the Company's option under certain circumstances; (iii)
receives a cumulative annual dividend of 8% payable quarterly; and (iv) has a
liquidation preference equal to the initial purchase price of $50 per share plus
accrued but unpaid dividends thereon. The Series A Preferred Stock does not have
voting rights except to the extent otherwise provided by Delaware law. The
complete terms of the Series A Preferred Stock are set forth in the Certificate
of Designations, Powers, Preferences and Rights of the Series A Preferred Stock.

As of May 30, 1996, 20,000 and 10,000 shares of Series B Convertible
Preferred Stock (the "Series B Preferred Stock") and Series C Convertible
Preferred Stock (the "Series C Preferred Stock"), respectively, were
outstanding. The Company's Series B and C Preferred Stock is convertible at the
option of the holder into Common Stock at a conversion price of $3.90 per share
of Common Stock, subject to certain anti-dilution adjustments, and will be
automatically converted at the same conversion price (i) on the first date after
December 31, 1996 until December 31, 1998 that the closing price per share of
Common Stock has been at

57
<PAGE> 58

least $5.85 for 20 of 30 consecutive trading days; or (ii) on December 31, 1998.
If the Company merges with or consolidates into another entity (after which the
stockholders of the Company own less than 50% of the voting power in the
election of directors of the other corporation or entity) or is acquired or
sells or otherwise conveys substantially all of its assets, or if a person or
entity (other than Mark G. Harrington or an affiliate or associate thereof)
acquires beneficial ownership of more than 50% of the outstanding Common Stock,
the conversion price shall be adjusted to the current market price of the Common
Stock if the current market price is less than the conversion price. The Company
may at its option elect to redeem the Series B and C Preferred Stock at $150 per
share at any time after December 31, 1994, if the market price for the Common
Stock exceeds $5.85 for 20 of 30 consecutive trading days.

The holders of the Series B and C Preferred Stock are entitled to receive
cumulative cash dividends at the rate of $8 per share per annum. In addition,
each share of Series B and C Preferred Stock entitles the holder thereof to such
number of votes per share as equals the whole number of shares of Common Stock
into which each share of Series B and C Preferred Stock is then convertible, and
holders of Series B and C Preferred Stock are entitled to vote on all matters as
to which holders of Common Stock are to vote, in the same manner and with the
same effect as such holders of Common Stock, voting together with such holders
of Common Stock as one class, except for certain matters in which the Series B
and C have class voting rights. If at any time the Company fails to declare and
pay in cash the full amount of dividends payable on any two dividend payment
dates, the holders of the Series B Preferred Stock, voting separately as a
class, shall be entitled to elect two directors until such time as the dividends
in default have been paid in full. Furthermore, at any time while a minimum of
50% of the shares of Series B or C Preferred Stock remain outstanding, the
Company may not take any action to alter or repeal its Certificate of
Incorporation or Bylaws which would adversely affect the rights, privileges or
powers of the Series B or C Preferred Stock (other than the issuance of
additional series of stock or increases in the authorized amount of existing
series of stock) without the consent or approval of, with respect to the Series
B Preferred Stock, at least a majority of the voting power of the Series B
Preferred Stock or, with respect to the Series C Preferred Stock, at least a
majority of the voting power of the Series C Preferred Stock. The complete terms
of the Series B and C Preferred Stock are set forth in the Certificates of
Designations, Powers, Preferences and Rights for the Series B Preferred Stock
and the Series C Preferred Stock.

On June 30, 1994, the Company issued 30,000 shares of Series E Junior
Convertible Preferred Stock (the "Series E Preferred Stock") to Bakersfield Gas,
L.P. The purchase price of the Series E Preferred Stock was $100 per share. The
Series E Preferred Stock is convertible at the option of the holder into Common
Stock at a conversion price of $3.50 per share, subject to adjustment for
certain stock dividends, subdivisions, reclassification or combinations with
respect to the Common Stock and for certain other distributions or events of
consolidation, merger or sale, lease or conveyance of all or substantially all
of the assets of the Company. Bakersfield Gas, L.P. has agreed not to exercise
its option to convert the shares of Series E Preferred Stock prior to the
closing of the Company's first underwritten public offering of equity securities
after the issuance of the Series E Preferred Stock. The Series E Preferred Stock
receives a cash dividend, cumulative from the date of issuance of the Series E
Preferred Stock and payable quarterly in arrears commencing on September 30,
1994, at the rate of $4 per share per annum until June 30, 1995, and thereafter
at the rate of $9 per share per annum. The Company has the option of paying
dividends on the Series E Preferred Stock either in cash or in shares of Common
Stock. The Series E Preferred Stock is redeemable in cash at any time, in whole
or in part, at the option of the Company, at a price of $110 per share, plus
accrued and unpaid dividends. The Company must redeem all of the Series E
Preferred Stock in cash, at a price of $110 per share plus accrued and unpaid
dividends, upon completion by the Company of its first underwritten public
offering of securities following the issuance of the Series E Preferred Stock in
which the net proceeds received by the Company equal or exceed $20.8 million. If
the proceeds from the Company's first underwritten public offering of securities
following the issuance of the Series E Preferred Stock is between $17.5 million
and $20.5 million, the Company must use all proceeds in excess of $17.5 million
to redeem shares of the Series E Preferred Stock.

Each share of Series E Preferred Stock entitles the holder thereof to such
number of votes per share as equals the whole number of shares of Common Stock
into which each share of Series E Preferred Stock is

58
<PAGE> 59

then convertible, and each share of Series E Preferred Stock is entitled to vote
on all matters as to which holders of Common Stock are to vote, in the same
manner and with the same effect as such holders of Common Stock, voting together
with the holders of Common Stock as one class, except for certain matters in
which holders of the Series E Preferred Stock have class voting rights. At any
time while a minimum of 50% of the shares of Series E Preferred Stock remain
outstanding, the Company shall not take any action to alter or repeal its
Certificate of Incorporation or Bylaws which would adversely affect the rights,
privileges or powers of the Series E Preferred Stock (other than the issuance of
additional series of stock or increases in the authorized amount of existing
series of stock) without the consent or approval of at least a majority of the
voting power of the Series E Preferred Stock. The complete terms of the Series E
Preferred Stock are set forth in the Certificates of Designations, Powers,
Preferences and Rights for the Series E Preferred Stock.

In the event of any voluntary or involuntary liquidation, dissolution or
other winding up of the affairs of the Company, before any distribution or
payment will be made to the holders of the Common Stock or Series E Preferred
Stock, the holders of the Series B and C Preferred Stock are entitled to be paid
$100 per share for each share of outstanding Series B and C Preferred Stock,
plus any accrued but unpaid dividends. If the net assets of the Company
distributable among the holders of all outstanding shares of the Series A, B and
C Preferred Stock is insufficient to permit the payment in full to such holders
of the preferential amounts to which they are entitled, then the entire net
assets of the Company will be distributed among the holders of the Series A, B
and C Preferred Stock ratably in proportion to the full amounts to which they
would otherwise be respectively entitled. Subject to the prior rights of the
holders of Series A, B and C Preferred Stock, the Series E Preferred Stock has a
liquidation preference of $100 per share plus accrued and unpaid dividends.

The Board of Directors may, without further action by the stockholders (but
subject to the rights of holders of the Company's preferred stock), issue
additional shares of preferred stock, and, with respect to such additional
shares, fix or alter dividend rights, dividend rates, conversion rights, voting
rights, rights and terms of redemption (including sinking fund provisions),
redemption price or prices and liquidation preferences of a wholly unissued
series of preferred stock, with the designation of any such series and the
number of shares to constitute any such unissued series. The Board of Directors
of the Company has not created any series of preferred stock, which has not been
fully redeemed, other than the Series A, B, C, E and F Preferred Stock.

ANTI-TAKEOVER PROVISIONS OF THE COMPANY'S CERTIFICATE OF INCORPORATION AND
BYLAWS

The Company's Certificate of Incorporation and Bylaws contain provisions
which could discourage certain transactions which involve an actual or
threatened change in control of the Company. Such provisions are summarized
below.

Article XI of the Company's Certificate of Incorporation ("Article XI")
establishes an advance notice procedure for the nomination, other than by or at
the direction of the Board of Directors or a committee thereof, of candidates
for election of directors. Notice of director nominations must be given in
writing to the Secretary of the Company not less than 30 days nor more than 90
days prior to any meeting of the stockholders at which directors are to be
elected; provided, however, that if fewer than 31 days notice of the meeting is
given to stockholders, notice of director nominations must be given not later
than the close of business on the tenth day following the day on which notice of
the meeting was mailed to stockholders.

Notice to the Company from a stockholder who intends to nominate a person
for election as a director at a meeting must contain certain information about
the proposed nominee. The director nomination for which notice was properly
given may be made only in a meeting of the stockholders called for the election
of directors at which the nominating stockholder is present in person or by
proxy. If the presiding officer of the meeting determines that stockholder's
nomination is not made in accordance with the procedures set forth in the
Company's Certificate of Incorporation, such nomination, at the direction of
such presiding officer, may be disregarded. Article XI requires the affirmative
vote of the holders of at least 66 2/3% of the voting power of the outstanding
shares of the Company to alter, amend or adopt any provision inconsistent with
the advance notice procedures set forth above.

Article XII of the Company's Certificate of Incorporation ("Article XII")
requires the affirmative vote of the holders of not less than 66 2/3% of the
Company's outstanding voting stock for the approval or

59
<PAGE> 60

authorization of any (i) merger or consolidation of the Company with or into any
other corporation, or (ii) sale, lease, exchange or other disposition of all or
substantially all of the assets of the Company to or with any corporation,
person or other entity; provided, however, that such 66 2/3% of the voting
requirement is not applicable if (a) a majority of the outstanding shares of all
classes of stock entitled to vote generally in the election of directors,
considered for such purpose to be one class, of such other corporation, person
or entity is owned of record or beneficially by the Company and its subsidiaries
or (b) a majority of the Board of Directors of the Company has approved such
transaction. Article XII further requires the vote or consent of at least
66 2/3% of the outstanding stock of the Company to amend, alter, change or
repeal any of the provisions of such article.

The Company's Certificate of Incorporation contains no provision expressly
electing not to be governed by Section 203 of the Delaware General Corporation
Law. In general, Section 203 prevents an "interested stockholder" (defined
generally as any person owning, or who is an affiliate or associate of the
corporation and has owned in the preceding three years, 15% or more of a
corporation's outstanding voting stock and affiliates and associates of such
person) from engaging in a "business combination" (as defined) with a Delaware
corporation for three years following the date such person became an interested
stockholder unless (i) before such person became an interested stockholder, the
board of directors of the corporation approved either the business combination
or the transaction in which the interested stockholder became an interested
stockholder, (ii) upon consummation of the transaction that resulted in the
stockholder becoming an interested stockholder, the interested stockholder owned
at least 85% of the voting stock of the corporation outstanding at the time the
transaction commenced (excluding stock held by directors who are also officers
of the corporation and by employee stock plans that do not provide employees
with the rights to determine confidentially whether shares held subject to the
plan will be tendered in a tender or exchange offer); or (iii) on or subsequent
to the date such person became an interested stockholder, the business
combination is approved by the board of directors of the corporation and
authorized at a meeting of stockholders by the affirmative vote of the holders
of two-thirds of the outstanding voting stock of the corporation not owned by
the interested stockholder. Under Section 203, the restrictions described above
also do not apply to certain business combinations proposed by an interested
stockholder following the announcement or notification of one of certain
extraordinary transactions involving the corporation and a person who had not
been an interested stockholder during the previous three years or who became an
interested stockholder with the approval of a majority of the corporation's
directors.

Article III, Section 2 of the Company's Bylaws provides that the Board of
Directors shall be divided into three classes as nearly equal in number as
possible, with terms of office expiring at different times in annual succession.
The Bylaws require the affirmative vote of the holders of 66 2/3% or more of the
outstanding shares of the Company's capital stock entitled to vote generally in
the election of directors to amend, alter, repeal or change Article III, Section
2 of the Company's Bylaws.

Additionally, the Company's Bylaws provide that, unless otherwise provided
in the Company's Certificate of Incorporation, special meetings of stockholders
can only be called by the President, Secretary or by a majority of the Board of
Directors or the Executive Committee thereof, if any.

SHARES ELIGIBLE FOR FUTURE SALE

As of May 1, 1996 the Company had outstanding 8,696,207 shares of Common
Stock and securities (including warrants, options and convertible preferred
stock) convertible into 4,886,063 shares of Common Stock. An aggregate of
1,550,000 shares of Common Stock have been reserved for issuance under the
Company's 1992 Stock Option Plan, the Company's 1992 Nonemployee Directors'
Stock Option Plan and the Company's 1994 Stock Option Plan (the "Plans"), and
options to purchase 898,500 of such shares have been granted. Following the
consummation of the Offering, the Company will have 5,722,581 shares of Common
Stock available for issuance at such times and upon such terms as may be
approved by the Company's Board of Directors. No prediction can be made as to
the effect, if any, that future sales or the availability of shares for sale
will have on the market price of the Common Stock prevailing from time to time.
Nevertheless, sales of substantial amounts of Common Stock of the Company in the
public market could adversely affect the

60
<PAGE> 61

prevailing market price of the Common Stock and could impair the Company's
ability to raise capital through sales of its equity securities.

After giving effect to the Offering, 2,484,148 shares of Common Stock
(including shares issuable upon exercise of outstanding options and warrants and
conversion of convertible securities) will be held by executive officers and
directors of the Company and affiliates of the Company and may be sold pursuant
to an effective registration statement covering such shares or pursuant to Rule
144 of the Securities Act, subject to the contractual restrictions described
below.

In general, under Rule 144, as currently in effect, a person (or persons
whose shares are aggregated), including an affiliate, who has beneficially owned
Restricted Shares for at least two years, is entitled to sell within any
three-month period, a number of shares that does not exceed the greater of (i)
1% of the then outstanding shares of the Company's Common Stock or (ii) an
amount equal to the average weekly reported volume of trading in such shares
during the four calendar weeks preceding the date on which notice of such sale
is filed with the Securities and Exchange Commission (the "Commission"). Sales
under Rule 144 are also subject to certain manner of sale limitations, notice
requirements and the availability of current public information about the
Company. Restricted Shares properly sold in reliance on Rule 144 are thereafter
freely tradeable without restrictions or registration under the Securities Act,
unless thereafter held by an affiliate of the Company. In addition, affiliates
of the Company must comply with the restrictions and requirements of Rule 144,
other than the two-year holding period requirement, in order to sell shares of
Common Stock which are not Restricted Shares (such as shares of Common Stock
acquired by affiliates of the Company in this Offering). As defined in Rule 144,
an "affiliate" of an issuer is a person that directly, or indirectly through one
or more intermediaries, controls or is controlled by, or is under common control
with, such issuer. If three years have elapsed since the later of the date of
any acquisition of Restricted Shares from the Company or from any affiliate of
the Company, and the acquiror or subsequent holder thereof is deemed not to have
been an affiliate of the Company at any time during the 90 days preceding a
sale, such person would be entitled to sell such shares in the public market
pursuant to Rule 144(k) without regard to volume limitations, manner of sale
restrictions, or public information or notice requirements.

TCW has the right to demand three registrations under the Securities Act of
up to 1,730,710 shares of the Company's Common Stock, of which 256,351 shares
are issuable upon exercise of its warrant. ING Capital has the right to demand
two registrations under the Securities Act of up to 30,000 shares of the
Company's Common Stock. Bakersfield Energy has the right to demand two
registrations under the Securities Act of up to 1,098,084 shares of the
Company's Common Stock, of which 857,143 shares are issuable upon conversion of
30,000 shares of Series E Preferred Stock. Also, First Union has the right to
demand two registrations under the Securities Act of up to 100,000 shares
issuable upon exercise of their warrants dated June 30, 1994. The Series D
Holders have the right to demand two registrations under the Securities Act of
up to 1,100,000 shares of the Company's Common Stock. The holders of Senior Note
Warrants, BT Securities and ING, also have the right to demand two registrations
under the Securities Act of up to 1,780,000 shares of the Company's Common
Stock. Upon any such demand, the Company, at its expense, must register the
applicable shares or a portion thereof for sale. Additionally, in the event the
Company registers any shares of its Common Stock (of its own accord or pursuant
to the request of one of its stockholders), it must give TCW, ING Capital,
Bakersfield Energy, First Union, the Series D Holders and the Senior Note
Warrant Holders an opportunity to include in such registration the shares of
Common Stock issued to them or issuable to them upon exercise of their warrants
or preferred stock, as applicable. The Company has given such notice to each of
these parties, and only Bakersfield Energy has elected to participate in the
Offering to the extent of 240,941 shares of Common Stock. There can be no
assurance that the holders of such rights will not exercise these registration
rights in a manner and at a time which may adversely impact the market price of
the Common Stock or business plans of the Company or may adversely affect the
Company's efforts to seek additional capital.

TRANSFER AGENT AND REGISTRAR

The Transfer Agent and Registrar for the Common Stock is Chemical/Mellon
Shareholders Services.

61
<PAGE> 62

UNDERWRITING

The Underwriters named below, have severally agreed, subject to the terms
and conditions of the Underwriting Agreement, to purchase from the Company and
the Selling Stockholders an aggregate of 6,400,000 shares of Common Stock. The
number of shares of Common Stock that each Underwriter has agreed to purchase is
set forth opposite their respective names below.

<TABLE>
<CAPTION>
NUMBER OF SHARES
UNDERWRITERS TO BE PURCHASED
------------ - ----------------
<S> <C>
Rauscher Pierce Refsnes, Inc......................... 2,560,000
Petrie Parkman & Co., Inc............................ 2,560,000
Southcoast Capital Corporation....................... 1,280,000
---------
Total...................................... 6,400,000
=========
</TABLE>

The Underwriting Agreement provides that the Underwriters' obligation to
pay for and accept delivery of the shares of Common Stock offered hereby is
subject to certain conditions precedent and that the Underwriters will be
obligated to purchase all such shares, excluding shares covered by the
over-allotment option, if any are purchased.

The Company has been advised by the Underwriters that they propose
initially to offer the Common Stock to the public at the public offering price
set forth on the cover page of this Prospectus and to certain dealers at such
price, less a concession not in excess of $0.18 per share. The Underwriters may
allow and such dealers may reallow a concession not in excess of $0.10 per share
to certain other brokers and dealers. After the Offering, the public offering
price, the concession and reallowances to dealers and other selling terms may be
changed by the Underwriters.

The Company has granted to the Underwriters an option exercisable for 30
days after the date of this Prospectus to purchase up to an aggregate of 960,000
additional shares of Common Stock to cover over-allotments, if any, at the same
price per share to be paid by the Underwriters for the other shares of Common
stock offered hereby. If the Underwriters purchase any such additional shares
pursuant to the over-allotment option, each Underwriter will be committed,
subject to certain conditions, to purchase a number of the additional shares of
Common Stock proportionate to such Underwriter's initial commitment.

The Company, its directors and executive officers, and certain stockholders
who will beneficially own an aggregate of 3,942,917 shares of the Common Stock
outstanding after the Offering have agreed with the Underwriters, for a period
of 180 days (120 days, in the case of Mr. Cresci and Pecks Management Partners
Ltd.) after the date of this Prospectus, not to issue, sell, offer to sell,
grant any options for the sale of, or otherwise dispose of any shares of Common
Stock or any rights to purchase shares of Common Stock (other than with respect
to the Company stock issued or options granted pursuant to the Company's stock
incentive plans), without the prior written consent of the Rauscher Pierce
Refsnes, Inc. See "Shares Eligible for Future Sale."

The Company and the Selling Stockholders have severally agreed to indemnify
the Underwriters against certain liabilities that may be incurred in connection
with the sale of the Common Stock, including liabilities arising under the
Securities Act, and to contribute to payments that the Underwriters may be
required to make with respect thereto.

62
<PAGE> 63

LEGAL MATTERS

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

ACCOUNTANTS

The audited financial statements included in this prospectus and elsewhere
in the registration statement have been audited by Arthur Andersen LLP,
independent public accountants, as indicated in their report with respect
thereto, and are included herein in reliance upon the authority of said firm as
experts in giving said report.

ENGINEERS

Information set forth in this Prospectus relating to the Company's
estimated proved oil and gas reserves at December 31, 1995, the related
calculations of future net production revenues and the net present value thereof
have been derived from independent petroleum engineering reports prepared by
Ryder Scott Company and Huddleston & Co., independent petroleum engineers.

63
<PAGE> 64

GLOSSARY OF OIL AND GAS TERMS

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

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

Bcf. Billion cubic feet.

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

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

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

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

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

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

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

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

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

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

MBOE. One thousand barrels of oil equivalent.

MBtu. One thousand Btus.

Mcf. One thousand cubic feet.

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

MMBOE. One million barrels of oil equivalent.

MMBtu. One million Btus.

MMcf. One million cubic feet.

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

NGLs. Natural gas liquids such as ethane, propane, iso-butane, normal
butane and natural gasoline that have been extracted from natural gas.

Overriding royalty interest. An interest in an oil and gas property
entitling the owner to a share of oil and gas production free of costs of
production.

PDP. Proved developed producing.

Pre-tax SEC 10 Value or Present value of estimated future net revenues or
pretax present value at constant prices of estimated future net revenues.
Estimated future net revenues discounted by a factor of ten percent per annum,
before income taxes and with no price or cost escalation or de-escalation, in
accordance with guidelines promulgated by the Securities and Exchange
Commission.

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

64
<PAGE> 65

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

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

Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

Proved undeveloped location. A site on which a development well can be
drilled consistent with local spacing rules for the purpose of recovering proved
reserves.

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

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

Reserve life is calculated by dividing year-end reserves by total
production in that year.

Reserve replacement costs. Total costs incurred for exploration and
development, divided by reserves added from all sources, including reserve
discoveries, extensions and improved recovery additions, net revisions to
reserve estimates and purchases of reserves-in-place. This calculation is often
used as a measure of the efficiency of an oil and gas company's exploration and
development expenditures.

Reserve replacement ratio is calculated by dividing the net total reserves
added in a specific year through drilling, acquisitions, and revisions by total
production in that year.

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

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

65
<PAGE> 66

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
Interim Unaudited Consolidated Financial Statements:
Consolidated Balance Sheets at March 31, 1996 (unaudited).......................... F-2
Consolidated Statements of Operations for the three months ended March 31, 1996 and
1995 (unaudited)................................................................ F-3
Consolidated Statements of Stockholders' Equity for the three months ended March
31, 1996........................................................................ F-4
Consolidated Statements of Cash Flows for the three months ended March 31, 1996 and
1995 (unaudited)................................................................ F-5
Notes to Condensed Consolidated Financial Statements (unaudited)................... F-7
Audited Consolidated Financial Statements:
Report of Independent Public Accountants........................................... F-11
Consolidated Balance Sheets at December 31, 1995 and 1994.......................... F-12
Consolidated Statements of Operations for the years ended December 31, 1995, 1994
and 1993........................................................................ F-13
Consolidated Statements of Stockholders' Equity for the years ended December 31,
1995, 1994 and 1993............................................................. F-14
Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994
and 1993........................................................................ F-15
Notes to Consolidated Financial Statements......................................... F-18
</TABLE>

F-1
<PAGE> 67

HARCOR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS
AS OF MARCH 31, 1996 (UNAUDITED)

<TABLE>
<CAPTION>
MARCH 31,
1996
-----------
<S> <C>
ASSETS
CURRENT ASSETS:
Cash and cash investments..................................................... $ 3,976,750
Accounts receivable........................................................... 3,699,634
Prepaids and other............................................................ 398,385
-----------
Total current assets.................................................. 8,074,769
-----------
PROPERTY AND EQUIPMENT, at cost, successful efforts method:
Unproved oil and gas properties............................................... 5,211,556
Proved oil and gas properties:
Leasehold costs............................................................ 55,670,301
Plant, lease and well equipment............................................ 18,120,654
Intangible development costs............................................... 19,371,617
Furniture and equipment....................................................... 262,740
-----------
98,636,868
Less -- accumulated depletion, depreciation and amortization.................. (24,354,217)
-----------
Net property, plant and equipment............................................. 74,282,651
-----------
OTHER ASSETS.................................................................... 4,413,029
-----------
$86,770,449
===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt............................................................... $ 595,876
Accounts payable and accrued liabilities...................................... 5,689,828
-----------
Total current liabilities............................................. 6,285,704
-----------
LONG-TERM BANK DEBT............................................................. 7,500,000
-----------
OTHER LIABILITIES............................................................... 240,169
-----------
14 7/8% SENIOR SECURED NOTES.................................................... 63,180,433
-----------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY:
Preferred stock, $.01 par value -- 1,500,000 shares authorized; 65,000 shares
outstanding................................................................ 650
Common stock, $.10 par value -- 25,000,000 shares authorized; 8,696,207 and
8,631,207 shares outstanding at March 31, 1996 and December 31, 1995,
respectively............................................................... 869,621
Additional paid-in capital.................................................... 28,734,380
Accumulated deficit........................................................... (20,040,508)
-----------
Total stockholders' equity............................................ 9,564,143
-----------
$86,770,449
===========
</TABLE>

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

F-2
<PAGE> 68

HARCOR ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE THREE MONTHS ENDED MARCH 31, 1996 AND 1995
(UNAUDITED)

<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
-------------------------
1996 1995
---------- ----------
<S> <C> <C>
REVENUES:
Oil and gas revenues.............................................. $5,956,058 $3,683,309
Gas plant operating and marketing revenues........................ 1,623,785 1,785,306
Interest income................................................... 10,310 6,833
Other............................................................. 6,413 8,282
---------- ----------
7,596,566 5,483,730
---------- ----------
COSTS AND EXPENSES:
Production costs.................................................. 1,436,729 1,263,087
Gas plant operating and marketing costs........................... 956,190 1,410,349
Engineering and geological costs.................................. 101,007 88,665
Depletion, depreciation and amortization.......................... 1,706,560 1,346,247
General and administrative expenses............................... 720,795 665,900
Interest expense.................................................. 2,642,541 1,129,996
Other............................................................. 260,703 --
---------- ----------
7,824,525 5,904,244
---------- ----------
Loss before provision for income tax.............................. (227,959) (420,514)
Provision for income taxes.......................................... -- --
---------- ----------
Net operating loss................................................ (227,959) (420,514)
Dividends on preferred stock........................................ (132,500) (335,242)
Accretion on redeemable preferred stock............................. -- (80,986)
---------- ----------
NET LOSS APPLICABLE TO COMMON STOCKHOLDERS.......................... $ (360,459) $ (836,742)
========= =========
NET LOSS PER COMMON SHARE........................................... $ (0.04) $ (0.12)
========= =========
</TABLE>

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

F-3
<PAGE> 69

HARCOR ENERGY, INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE THREE MONTHS ENDED MARCH 31, 1996
(UNAUDITED)

<TABLE>
<CAPTION>
PREFERRED STOCK COMMON STOCK ADDITIONAL
--------------- -------------------- PAID-IN ACCUMULATED
SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT
------ ------ --------- -------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995..... 65,000 $650 8,631,207 $863,121 $29,163,670 $(19,812,549)
Issuance of common stock
pursuant to warrant
exchange..................... -- -- 65,000 6,500 (6,500) --
Cancellation of warrants....... -- -- -- -- (290,290) --
Preferred stock dividends...... -- -- -- -- (132,500) --
Net loss for the three months
ended March 31, 1996......... -- -- -- -- -- (227,959)
------ ------ --------- -------- ----------- ------------
Balance, March 31, 1996........ 65,000 $650 8,696,207 $869,621 $28,734,380 $(20,040,508)
====== ====== ======== ======== ========== ===========
</TABLE>

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

F-4
<PAGE> 70

HARCOR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31, 1996 AND 1995
(UNAUDITED)

<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------------
1996 1995
------------ ----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss........................................................ $ (227,959) $ (420,514)
Adjustments to reconcile net loss to net cash provided by
operating activities:
Depletion, depreciation and amortization..................... 1,706,560 1,346,247
Amortization of deferred charges............................. 239,574 117,441
Engineering and geological costs................................ 101,007 88,665
Other........................................................... 260,703 --
------------ ----------
2,079,885 1,131,839
Changes in working capital, net of effects of non-cash
transactions................................................. (2,167,741) (187,421)
------------ ----------
Net cash provided by (used in) operating activities............. (87,856) 944,418
------------ ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Engineering and geological costs................................ (101,007) (88,665)
Additions to property and equipment............................. (9,635,408) (18,341)
------------ ----------
Net cash used in investing activities........................... (9,736,415) (107,006)
------------ ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from increase in debt.................................. 1,900,000 --
Dividends on preferred stock.................................... (132,500) (70,000)
Other........................................................... (170,939) (13,313)
------------ ----------
Net cash used in financing activities........................... 1,596,561 (83,313)
------------ ----------
Net increase (decrease) in cash................................. (8,227,710) 754,099
Cash at beginning of period..................................... 12,204,460 899,198
------------ ----------
Cash at end of period........................................... $ 3,976,750 $1,653,297
============ ==========
</TABLE>

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

F-5
<PAGE> 71

HARCOR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE THREE MONTHS ENDED MARCH 31, 1996 AND 1995
(UNAUDITED)

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (ALL DOLLAR AMOUNTS HAVE BEEN
ROUNDED TO THE NEAREST THOUSAND)

HarCor Energy, Inc. (the "Company") made interest payments of $4,668,000
and $969,000 during the three months ended March 31, 1996 and 1995,
respectively.

SUPPLEMENTAL INFORMATION REGARDING NON-CASH INVESTING AND FINANCING
ACTIVITIES -- THREE MONTHS ENDED MARCH 31, 1996

During the current period the Company entered into agreements resulting in
the issuance of 65,000 unregistered shares of its common stock in exchange for
the cancellation of options and warrants to purchase an aggregate of 376,000 of
its common shares. Additionally, a warrant to purchase 350,000 shares of the
Company's common stock, which was issued in connection with a prior financing,
was returned to the Company and canceled in exchange for the issuance of 99,750
new warrants. These activities are not reflected in financing activities (see
Note 5).

Included in investing activities in the current period are payments of
$8,188,000 relating to drilling costs which were accrued but unpaid at December
31, 1995. At March 31, 1996, the Company had accrued capital costs and a
capitalized lease aggregating $1,649,000 which are not reflected in investing
activities.

SUPPLEMENTAL INFORMATION REGARDING NON-CASH INVESTING AND FINANCING
ACTIVITIES -- THREE MONTHS ENDED MARCH 31, 1995

During the three months ended March 31, 1995, the Company paid "in-kind"
dividends on its Series D Redeemable Preferred Stock consisting of $235,000 in
newly-issued Series D Preferred Stock and issued detachable warrants to purchase
shares of common stock which were valued at $45,000. The Company also paid
dividends on its Convertible Series E Preferred Stock consisting of $30,000 in
newly-issued unregistered shares of the Company's common stock. In addition, the
Company incurred an accretion charge of $81,000 on its Series D Preferred Stock
during the period.

Pursuant to the terms of its bridge loan facility, the Company issued to
its secured lender 50,000 shares of its common stock which was valued at
$156,000 and recorded to deferred financing costs.

F-6
<PAGE> 72

HARCOR ENERGY, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 1996

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The accompanying consolidated financial statements for the three months
ended March 31, 1995 include the accounts and results of HarCor Energy, Inc.
("HarCor") and its wholly-owned subsidiaries, Warrior, Inc. ("Warrior") and HTAC
Investments, Inc.(collectively, the "Company" or "HarCor" unless the context
specifies otherwise). The accompanying consolidated financial statements for the
three months ended March 31, 1996 include the accounts and results of HarCor,
and Warrior and HTAC until those subsidiaries' merger into HarCor (see below).

Principally all of the assets, equity, revenue and earnings of the Company
as described herein are within HarCor Energy, Inc. Separate financial statements
of Warrior and HTACI, HarCor's only direct or indirect subsidiaries, have not
been included herein because they are wholly owned and not material. In March
1996, Warrior and HTACI were merged into HarCor, and all of their assets became
the property, and all of their liabilities and guarantees became the
obligations, of HarCor.

All significant intercompany accounts and transactions have been eliminated
in consolidation.

The consolidated financial statements included herein have been prepared by
the Company, without audit, pursuant to the rules and regulations of the
Securities and Exchange Commission. Certain information and footnote disclosures
normally included in financial statements prepared in accordance with generally
accepted accounting principles have been condensed or omitted pursuant to such
rules and regulations. The Company believes, however, that it has made adequate
disclosures so that the information presented herein is not misleading.

A summary of the Company's significant accounting policies is included in
the consolidated financial statements and notes thereto, contained in its Annual
Report on Form 10-K for the year ended December 31, 1995 (the "10-K"). The
unaudited consolidated financial data presented herein should be read in
conjunction with the 10-K.

In the opinion of the Company, the unaudited consolidated financial
statements contained herein include all adjustments (consisting of normal
recurring accruals and the elimination of intercompany transactions) necessary
to present fairly the Company's consolidated results of operations, cash flows
and changes in stockholders' equity for the three-month periods ended March 31,
1996 and 1995.

The results of operations for an interim period are not necessarily
indicative of the results to be expected for a full year.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at March 31, 1996 and 1995
comprised the following (amounts in thousands):

<TABLE>
<CAPTION>
1996 1995
------ ------
<S> <C> <C>
Accrued development costs.......................................... $1,553 $ 365
Accrued interest payable........................................... 2,124 931
Trade accounts payable and other................................... 2,013 2,969
------ ------
$5,690 $4,265
====== ======
</TABLE>

F-7
<PAGE> 73

HARCOR ENERGY, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Capitalized Interest Costs

Interest costs of $172,000 for the three months ended March 31, 1996 have
been capitalized as part of the historical costs of unproved oil and gas
properties.

New Accounting Standard: Impairment of Long-Lived Assets

In September 30, 1995, the Company adopted the provisions of Statement of
Financial Accounting Standards No. 121 ("SFAS 121"), "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."
SFAS 121 requires the Company to review its oil and gas properties whenever
events or changes in circumstances indicate that the carrying amount of such
assets may not be recoverable. If the carrying amount of any of the Company's
oil and gas properties (determined on a field-by-field basis) is greater than
its projected undiscounted future cash flow, an impairment loss is recognized
down to the properties' fair values. There were no write-downs pursuant to SFAS
121 in the current period.

Use of Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the reported
periods. Actual results could differ from those estimates. Significant estimates
with regard to these financial statements include the estimate of proved oil and
gas reserve volumes and the related present value of estimated future net
revenues therefrom.

Net Loss Per Common Share

Net loss per common share was calculated by dividing the appropriate net
loss, after considering preferred stock dividends, by the weighted average
number of common shares outstanding during each period. Outstanding stock
options, warrants and convertible preferred shares were not included in the
calculations, since their effect was antidilutive. The weighted average number
of outstanding common shares utilized in the calculations was 8,685,000 and
7,226,000 for the three-month periods ended March 31, 1996 and 1995,
respectively.

(2) LONG-TERM DEBT

Availability under the Company's credit agreement with ING Capital is
limited to a "borrowing base" amount which is determined semi-annually by ING,
at its sole discretion, and may be established at an amount up to $15 million.
The borrowing base is currently $10 million, and ING Capital has no obligation
to increase the borrowing base above this amount. Availability under the credit
agreement, which was amended in March 1996, will terminate on June 30, 1997, at
which time amounts outstanding will convert to a term loan on September 30,
1997, with a set amortization schedule of a percentage of the outstanding
principal balance continuing through December 31, 2000. There was $7.5 million
outstanding under this facility at March 31, 1996. The effective interest rate
on the balance outstanding was 8.125% at that date. Amounts advanced under this
facility bear interest at an adjusted Eurodollar rate plus 2.50%.

See Notes to Consolidated Financial Statements included in Item 8. of Part
II of the Company's December 31, 1995 Report on Form 10-K for a complete
description of the Company's New Credit Agreement.

(3) SENIOR SECURED NOTES

F-8
<PAGE> 74

HARCOR ENERGY, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(the "Notes") and warrants to purchase 1,430,000 shares of common stock at $3.85
per share. Each Unit consists of a $1,000 principal amount Note and 22 warrants
to purchase an equal number of shares of common stock.

The Company used the net proceeds of approximately $61 million from the
sale of the Units (after discounts and offering expenses) to retire all
outstanding debt, redeem the Series D Preferred Stock outstanding, acquire
interests in certain oil and gas wells associated with the Bakersfield
Properties, and finance a portion of the development of the Bakersfield
Properties during the remainder of 1995.

The differing amount between the $65 million face value of the Notes and
the balance sheet amount recorded herein is the result of an allocation to
paid-in capital of the value ascribed to the warrants at the time of their
issuance. This amount will amortize through interest expense over the life of
the Notes.

The Notes bear interest at the rate of 14 7/8% per annum. Interest accrues
from the date of issue and will be payable semi-annually on January 15 and July
15 of each year, commencing on January 15, 1996. The Notes are redeemable, in
whole or in part, at the option of the Company at any time on or after July 15,
1999, at the following redemption prices (expressed as percentages of the
principal amount) if redeemed during the twelve-month period commencing on July
15 of the year set forth below plus, in each case, accrued interest thereon to
the date of redemption:

<TABLE>
<CAPTION>
YEAR PERCENTAGE
---------------------------------------------------------- ----------
<S> <C>
1999...................................................... 110%
2000...................................................... 107%
2001 and thereafter....................................... 100%
</TABLE>

The Notes were issued pursuant to an indenture between the Company and
Texas Commerce Bank National Association, as Trustee (the "Indenture"). All of
the obligations of the Company under the Notes and the Indenture are secured by
a second priority lien on substantially all of the assets of the Company and its
subsidiaries securing its bank debt.

See Notes to Consolidated Financial Statements included in Item 8. of Part
II of the Company's December 31, 1995 Report on Form 10-K for a complete
description of the Company's Senior Secured Notes.

(4) COMMITMENTS AND CONTINGENCIES

Risk Management and Hedging Activities

The Company utilizes financial instruments as a hedging strategy to protect
against the effects of volatility in crude oil and natural gas commodity prices.
Upon consummation of an acquisition, the Company will usually enter into
commodity derivative contracts (hedges) such as futures, swaps or collars or
forward contracts which cover a substantial portion of the existing production
of the acquired property. Over time, as production increases, the Company may
continue to utilize hedging techniques to ensure that a portion of its
production remains appropriately hedged. Gains or losses under the hedging
agreements are recognized in oil and gas production revenues in periods in which
the hedged production occurs and such agreements are settled on a monthly basis.

As of March 31, 1996, the Company was a party to various gas contracts
covering volumes of approximately 1.8 Bcf and 1.2 Bcf for 1996 and 1997,
respectively, at prices ranging from $1.68/MMBtu to $2.07/MMBtu; a gas contract
covering 2.2 Bcf for 1996 and 2.2 Bcf for 1997 which fixes volumes to be sold at
$0.3675 less than the NYMEX gas future price for each month; and oil hedges
covering notional volumes of approximately 243 MBOE, 98 MBOE and 29 MBOE for
1996, 1997 and 1998, respectively, at prices ranging from $15.80/Bbl to
$18.75/Bbl.

F-9
<PAGE> 75

HARCOR ENERGY, INC.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(5) STOCKHOLDERS' EQUITY

Warrant Exchanges

During the current quarter the Company completed exchange agreements
whereby certain holders of options and warrants to purchase the Company's common
stock exchanged all or a portion of their options and warrants outstanding for
unregistered shares of common stock of the Company. Pursuant to these exchange
agreements, an option to purchase 150,000 common shares at $4.875 per share, and
warrants to purchase an aggregate of 226,000 common shares at prices ranging
from $4.75 to $5.50 per share, were exchanged and canceled for 65,000
unregistered shares of common stock of the Company. Additionally, in March 1996,
a warrant to purchase 350,000 shares of the Company's common stock at $3.85 per
share, which was issued in connection with the Note Offering, was returned to
the Company and canceled in exchange for the issuance of 99,750 new warrants
with the same exercise price.

Preferred Stock Dividends

The Company has paid dividends on preferred stocks for the three months
ended March 31, 1996 and 1995 as follows:

<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------
1996 1995
-------- --------
<S> <C> <C>
8% Convertible (Series A, B, C)................................ $ 65,000 $ 70,000
9% Redeemable (Series D)....................................... -- 235,242
4%/9% Convertible (Series E)................................... 67,500 30,000
-------- --------
$132,500 $335,242
======== ========
</TABLE>

Dividends on 8% Series A, Series B and Series C Preferred Stock were paid
in cash for both periods presented. Dividends on 9% Series D in first quarter
1995 were paid, at the option of the Company, in additional shares of Series D
Redeemable Preferred Stock. Dividends on the Series E Preferred Stock for first
quarter 1995 were paid, at the option of the Company, in shares of common stock
of the Company in lieu of cash. Dividends on the Series E Preferred were paid in
cash for the current quarter. The coupon rate on the Series E increased from 4%
per annum to 9% per annum effective July 1, 1995.

F-10
<PAGE> 76

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors of HarCor Energy, Inc.:

We have audited the accompanying consolidated balance sheets of HarCor
Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 1995
and 1994, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1995. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.

We conducted our audits in accordance with 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
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of HarCor
Energy, Inc. and subsidiaries as of December 31, 1995 and 1994, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1995, in conformity with generally accepted accounting
principles.

As discussed in Note 1 to the consolidated financial statements, effective
September 30, 1995, the Company adopted the Provisions of Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed Of."

ARTHUR ANDERSEN LLP

Houston, Texas
March 22, 1996

F-11
<PAGE> 77

HARCOR ENERGY, INC.

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1995 AND 1994

ASSETS

<TABLE>
<CAPTION>
1995 1994
------------ ------------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash investments..................................... $ 12,204,460 $ 899,198
Accounts receivable........................................... 3,829,548 3,707,433
Prepaids and other............................................ 282,833 307,241
------------ ------------
Total current assets.................................. 16,316,841 4,913,872
------------ ------------
PROPERTY, PLANT AND EQUIPMENT, at cost,
successful efforts method:
Unproved oil and gas properties............................... 5,039,553 7,414,113
Proved oil and gas properties:
Leasehold costs............................................ 54,793,930 52,158,281
Lease and well equipment................................... 16,858,402 12,900,913
Intangible development costs............................... 18,547,293 4,745,579
Furniture and equipment....................................... 256,211 231,354
------------ ------------
95,495,389 77,450,240
Less -- accumulated depletion, depreciation, amortization and
impairment................................................. (22,647,657) (16,674,540)
------------ ------------
Net property, plant and equipment............................. 72,847,732 60,775,700
------------ ------------
OTHER ASSETS.................................................... 5,066,904 2,883,277
------------ ------------
$ 94,231,477 $ 68,572,849
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term debt............................................... $ 378,695 $ --
Current portion of long-term debt............................. -- 2,511,200
Subordinated Bridge Loan...................................... -- 5,000,000
Accounts payable and accrued liabilities...................... 14,612,813 5,345,967
Total current liabilities..................................... 14,991,508 12,857,167
------------ ------------
LONG-TERM DEBT, net of current portion................ 5,600,000 31,888,800
------------ ------------
OTHER LIABILITIES............................................... 316,469 71,055
------------ ------------
14 7/8% SENIOR SECURED NOTES.................................... 63,108,608 --
------------ ------------
COMMITMENTS AND CONTINGENCIES (Note 9)
REDEEMABLE SERIES D PREFERRED STOCK............................. -- 8,402,430
STOCKHOLDERS' EQUITY:
Preferred stock, $.01 par value -- 1,500,000 shares
authorized; 65,000 and 67,500 shares outstanding at
December 31, 1995 and 1994, respectively................... 650 675
Common stock, $.10 par value -- 25,000,000 shares authorized;
8,631,207 and 7,192,837 shares outstanding at December 31,
1995 and 1994, respectively................................ 863,121 719,284
Additional paid-in capital.................................... 29,163,670 29,827,989
Accumulated deficit........................................... (19,812,549) (15,194,551)
------------ ------------
Total stockholders' equity............................ 10,214,892 15,353,397
------------ ------------
$ 94,231,477 $ 68,572,849
============ ============
</TABLE>

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

F-12
<PAGE> 78

HARCOR ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
REVENUES:
Oil and gas revenues.............................. $16,030,043 $10,981,651 $ 6,507,468
Gas plant operating and marketing revenues........ 6,361,665 1,978,317 --
Interest income................................... 164,193 16,269 20,593
Other............................................. 39,368 236,814 197,022
----------- ----------- -----------
22,595,269 13,213,051 6,725,083
----------- ----------- -----------
COSTS AND EXPENSES:
Production costs.................................. 5,262,887 3,609,831 2,248,877
Gas plant operating and marketing costs........... 3,704,397 1,707,551 --
Dry hole and abandonment costs.................... 4,013 74,797 41,165
Engineering and geological costs.................. 307,102 254,418 187,862
Depletion, depreciation, amortization and
impairment..................................... 5,973,117 3,897,133 2,641,079
General and administrative expenses............... 2,744,239 2,014,232 2,104,857
Interest expense.................................. 6,846,471 2,268,558 542,098
Other............................................. 482,608 203,000 --
----------- ----------- -----------
25,324,834 14,029,520 7,765,938
----------- ----------- -----------
Loss before provision for income taxes and
extraordinary item............................. (2,729,565) (816,469) (1,040,855)
Provision for income taxes........................ -- -- --
----------- ----------- -----------
Loss before extraordinary item.................... (2,729,565) (816,469) (1,040,855)
EXTRAORDINARY ITEM:
Loss on early extinguishment of debt.............. (1,888,433) (122,193) --
----------- ----------- -----------
Net loss.......................................... (4,617,998) (938,662) (1,040,855)
Dividends on preferred stock........................ (1,000,161) (795,065) (246,468)
Accretion on Redeemable Preferred Stock............. (2,146,812) (156,152) --
----------- ----------- -----------
NET LOSS APPLICABLE TO COMMON STOCKHOLDERS.......... $(7,764,971) $(1,889,879) $(1,287,323)
========== ========== ==========
NET LOSS PER COMMON SHARE BEFORE EXTRAORDINARY
ITEM.............................................. $ (.74) $ (.27) $ (.23)
EXTRAORDINARY ITEM.................................. (.24) (.02) --
----------- ----------- -----------
NET LOSS PER COMMON SHARE AFTER EXTRAORDINARY
ITEM.............................................. $ (.98) $ (.29) $ (.23)
========== ========== ==========
</TABLE>

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

F-13
<PAGE> 79

HARCOR ENERGY, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

<TABLE>
<CAPTION>
PREFERRED STOCK COMMON STOCK ADDITIONAL
------------------ ---------------------- PAID-IN ACCUMULATED
SHARES AMOUNT SHARES AMOUNT CAPITAL DEFICIT
------- ------ --------- -------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1992................. 8,000 $ 80 5,399,877 $539,988 $17,320,228 $(13,215,034)
Issuance of 8% Series B Convertible
Preferred Stock.......................... 30,000 300 -- -- 2,999,700 --
Issuance of 8% Series C Convertible
Preferred Stock.......................... 10,000 100 -- -- 930,926 --
Conversion of Convertible Preferred
Stock.................................... (10,500) (105) 235,157 23,516 (23,411) --
Issuance of common stock pursuant to
exercise of stock options................ -- -- 101,850 10,185 236,745 --
Preferred stock dividends.................. -- -- -- -- (246,468) --
Net loss................................... -- -- -- -- -- (1,040,855)
------- ------ --------- -------- ----------- ------------
BALANCE, DECEMBER 31, 1993................. 37,500 375 5,736,884 573,689 21,217,720 (14,255,889)
Issuances in connection with Bakersfield
Property acquisition:
4% Series E Convertible Preferred
Stock.................................. 30,000 300 -- -- 2,982,443 --
Common stock............................. -- -- 1,363,907 136,391 2,965,148 --
Warrants................................. -- -- -- -- 3,200,842 --
Issuances of common stock pursuant to
Restricted Stock grant and exercise of
stock options............................ -- -- 75,375 7,537 266,776 --
Issuances of common stock and warrants
pursuant to preferred stock dividends.... -- -- 16,671 1,667 146,277 --
Preferred stock dividends.................. -- -- -- -- (795,065) --
Accretion on 9% Redeemable Series D
Preferred Stock.......................... -- -- -- -- (156,152) --
Net loss................................... -- -- -- -- -- (938,662)
------- ------ --------- -------- ----------- ------------
BALANCE, DECEMBER 31, 1994................. 67,500 675 7,192,837 719,284 29,827,989 (15,194,551)
Conversion of Convertible Preferred
Stock.................................... (2,500) (25) 64,100 6,410 (6,385) --
Issuance of common stock................... -- -- 75,000 7,500 226,125 --
Issuance of common stock pursuant to
warrant exchange......................... -- -- 1,282,500 128,250 (128,250) --
Issuance of common stock and warrants
pursuant to preferred stock dividends.... -- -- 16,770 1,677 153,164 --
Issuance of warrants pursuant to 14 7/8%
Senior Secured Notes..................... -- -- -- -- 2,238,000 --
Preferred stock dividends.................. -- -- -- -- (1,000,161) --
Accretion on Series D Preferred Stock...... -- -- -- -- (2,146,812) --
Net loss................................... -- -- -- -- -- (4,617,998)
------- ------ --------- -------- ----------- ------------
BALANCE, DECEMBER 31, 1995................. 65,000 $ 650 8,631,207 $863,121 $29,163,670 $(19,812,549)
======= ====== ======== ======== ========== ===========
</TABLE>

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

F-14
<PAGE> 80

HARCOR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

<TABLE>
<CAPTION>
1995 1994 1993
------------ ------------ -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Loss........................................ $ (4,617,998) $ (938,662) $(1,040,855)
Adjustments to reconcile net loss to net cash
provided by operating activities:
Depletion, depreciation, amortization and
impairment................................. 5,973,117 3,897,133 2,641,079
Amortization of deferred financing costs..... 708,932 254,372 67,177
Dry hole and abandonment costs............... 4,013 74,797 41,165
Engineering and geological costs............. 307,102 254,418 187,862
(Gain) loss on sale of assets................ 131,702 (230,993) (166,021)
Loss on early extinguishment of debt......... 1,888,433 122,193 --
Other........................................ 350,908 203,000 --
------------ ------------ -----------
4,746,209 3,636,258 1,730,407
Changes in current assets and liabilities:
Decrease (increase) in receivables........... (212,319) (2,520,726) 11,987
Decrease (increase) in other current
assets..................................... 24,408 (147,002) 68,786
Increase in accounts payable and accrued
liabilities................................ 457,233 1,772,930 560,074
------------ ------------ -----------
Net cash provided by operating activities....... 5,015,531 2,741,460 2,371,254
------------ ------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Engineering and geological costs................ (307,102) (254,418) (187,862)
Proceeds from sale of assets.................... 13,650 455,754 363,332
Additions to oil and gas properties............. (8,953,427) (45,607,532) (4,283,066)
Dry hole and abandonment costs.................. (4,013) (74,797) (41,165)
Sale of Canadian securities..................... -- -- 1,287,356
Other........................................... -- -- 58,683
------------ ------------ -----------
Net cash used in investing activities........... (9,250,892) (45,480,993) (2,802,722)
------------ ------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt.................. 5,600,000 34,436,875 2,603,528
Repayment of debt............................... (39,400,000) (3,577,873) (1,949,189)
Proceeds from issuance of preferred stock....... -- -- 931,026
Proceeds from issuance of Redeemable Preferred
Stock........................................ -- 10,000,000 --
Proceeds from 14 7/8% Senior Secured Notes...... 64,647,700 -- --
Proceeds from issuance of common stock.......... -- 3,053,101 246,930
Redemption of Redeemable Preferred Stock........ (10,931,200) -- --
Dividends on preferred stock.................... (464,161) (356,413) (170,055)
Increase in other assets........................ (3,856,119) (1,772,621) (47,655)
Other........................................... (55,597) (305,850) 49,888
------------ ------------ -----------
Net cash provided by financing activities....... 15,540,623 41,477,219 1,664,473
------------ ------------ -----------
Net increase (decrease) in cash................... 11,305,262 (1,262,314) 1,233,005
Cash and cash investments at beginning of
period.......................................... 899,198 2,161,512 928,507
------------ ------------ -----------
Cash and cash investments at end of period........ $ 12,204,460 $ 899,198 $ 2,161,512
=========== =========== ==========
</TABLE>

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

F-15
<PAGE> 81

HARCOR ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION (ALL DOLLAR AMOUNTS HAVE BEEN
ROUNDED TO THE NEAREST THOUSAND)

The Company made cash interest payments of $2,329,000, $2,030,000 and
$453,000 in 1995, 1994 and 1993, respectively.

SUPPLEMENTAL INFORMATION REGARDING NON-CASH INVESTING AND FINANCING
ACTIVITIES -- YEAR ENDED DECEMBER 31, 1995

The Company had accrued capital expenditure costs of $8,266,000 at December
31, 1995 which are not reflected in investing activities.

Pursuant to the terms of its bridge loan facility, the Company issued to
its secured lender 75,000 shares of its common stock to which a value of
$253,000 was ascribed. These additions to deferred financing costs and equity
are not reflected in financing activities.

The Company incurred $379,000 in short-term debt and $282,000 in other
liabilities in connection with the financing of an annual insurance policy and
the financing of equipment which is not reflected in financing activities.

In connection with the refinancing of its long-term debt, the Company
incurred a non-cash charge of $1,888,000 in writing off all of the deferred
financing costs associated with the extinguished debt. Also in connection with
this refinancing, the Company issued warrants to which a value of $580,000 was
ascribed. These charges to deferred financing costs and equity are not reflected
in financing activities.

Included in the payment of dividends on its Series D Preferred Stock were
"in-kind" dividends consisting of $476,000 in newly-issued Series D Preferred
Stock. Included in the payment of dividends on the Convertible Series E
Preferred Stock was $60,000 of newly-issued unregistered shares of the Company's
common stock. These dividend payments as described are not reflected in
financing activities.

The Company incurred aggregate non-cash accretion charges of $2,147,000 on
its Series D Preferred Stock which are not reflected in financing activities.

SUPPLEMENTAL INFORMATION REGARDING NON-CASH INVESTING AND FINANCING
ACTIVITIES -- YEAR ENDED DECEMBER 31, 1994

In connection with the dissolution of the South Texas Limited Partnership
and related property conveyance, the Company wrote off $203,000 of its cost
basis of the partnership, and expensed $122,000 reflecting a write-off of
deferred financing costs resulting from the early extinguishment of debt. These
non-cash charges for the dissolution and debt extinguishment are not reflected
in investing and financing activities.

At December 31, 1994, the Company had accrued acquisition and developmental
drilling costs aggregating $1,823,000 and accrued prepaid and deferred financing
costs aggregating $342,000. The additions to property, plant and equipment and
financing costs resulting from these and the above described transactions are
not reflected in investing and financing activities.

In connection with the Company's acquisition of certain oil and gas assets,
the Company issued to the sellers, as a portion of the consideration, 30,000
shares of its Series E Preferred Stock with a face value of $3,000,000, 25,000
shares of unregistered common stock with a value of $81,000 and a warrant to
purchase 1,000,000 shares of the Company's common stock at $5.00 per share to
which the Company ascribed a value of $850,000. The acquisition value of the
assets acquired and corresponding additions to equity resulting from these
transactions are not reflected in investing and financing activities.

F-16
<PAGE> 82

In connection with the amendment of the Company's credit agreement, the
Company issued warrants to purchase 250,000 shares of the Company's common stock
to which the Company ascribed a value of $230,000. The deferred financing cost
and addition to equity resulting from this transaction are not reflected in
financing activities.

During 1994, the Company issued an aggregate of 60,375 restricted shares of
common stock to officers which was valued as deferred compensation of $242,000
and was not reflected in financing activities.

During 1994, the Company paid "in-kind" dividends on its Series D
Redeemable Preferred Stock consisting of $455,000 in newly-issued Series D
Preferred Stock and detachable warrants to purchase shares of common stock which
were valued at $88,000. The Company also paid dividends on its Convertible
Series E Preferred Stock consisting of $60,000 in newly-issued unregistered
shares of the Company's common stock. These dividend payments and issuance of
common stock and warrants are not reflected in financing activities.

SUPPLEMENTAL INFORMATION REGARDING NON-CASH INVESTING AND FINANCING
ACTIVITIES -- YEAR ENDED DECEMBER 31, 1993

In March 1993, the Company acquired oil and gas royalty and net profit
interests in exchange for 30,000 shares of the Company's 8% Series B Convertible
Preferred Stock at $100.00 per share for an aggregate of $3,000,000. The
acquisition value of the assets acquired and corresponding addition to equity
are not reflected in investing or financing activities.

In connection with the Company's May 1993 acquisition of assets for
$1,095,000, the Company assumed $787,000 of an outstanding production note
payable. The additions to properties and production note are not reflected in
investing and financing activities.

The Company declared dividends totaling $76,000 in the fourth quarter on
its Series A, B and C Convertible Preferred Stock, which were accrued and unpaid
and not reflected in financing activities at December 31, 1993.

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

F-17
<PAGE> 83

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The accompanying consolidated financial statements for the year ended
December 31, 1993 include the accounts and results of operations of HarCor
Energy, Inc. ("HarCor") and its wholly-owned subsidiaries, Warrior, Inc.
("Warrior") and HTAC Investments, Inc. ("HTACI"); HarCor's general partner share
of the assets, liabilities, revenues and costs and expenses of South Texas
Limited Partnership ("STLP"); and HarCor's share of assets, revenues and costs
and expenses of oil and gas interests acquired from the TCW Commingled Debt and
Royalty Fund I ("Royalty Interests") for the period of March 1993 through
December 1993.

The accompanying consolidated financial statements for the years ended
December 31, 1994 and 1995 include the accounts and results of HarCor, Warrior
and HTACI; HarCor's share of the assets, liabilities, revenues and costs and
expenses of STLP or, after STLP's dissolution in March 1994, HarCor's direct
working interests in the STLP properties ("South Texas Properties"); HarCor's
share of the Royalty Interests; and HarCor's interest in certain oil and gas
assets located in Kern County, California acquired on June 30, 1994 (the
"Bakersfield Properties"); (collectively, the "Company" or "HarCor" unless the
context specifies otherwise).

Principally all of the assets, equity, revenue and earnings of the Company
as described herein are within HarCor Energy, Inc. Separate financial statements
of Warrior and HTACI, HarCor's only direct or indirect subsidiaries, have not
been included herein because they are wholly owned and not material. Subsequent
to December 31, 1995, Warrior and HTACI were merged into HarCor, and all of
their assets became the property, and all of their liabilities and guarantees
became the obligations, of HarCor.

All significant intercompany accounts and transactions have been eliminated
in consolidation.

Business and Organization

HarCor, a Delaware corporation, was incorporated in 1976 and is engaged in
the business of acquiring interests in and developing onshore oil and gas
properties in the United States.

Cash Flows

For purposes of reporting cash flows, cash and cash investments include
cash on hand and temporary short-term cash investments, with original maturities
of three months or less.

Property, Plant and Equipment

The Company utilizes the successful efforts method of accounting for its
oil and gas properties. Under this method, exploratory costs, except costs of
drilling exploratory wells, are charged to expense when incurred; exploratory
well costs (including leasehold costs) are initially capitalized, but are
charged to expense if the well is determined to be unsuccessful. Upon discovery
of reserves on an oil and gas property in commercially producible quantities,
all costs of developing that property, including costs of drilling unsuccessful
development wells, are capitalized. Capitalized leasehold acquisition costs are
depleted on a unit-of-production method, based on proved oil and gas reserves.
Exploration, development and equipment costs are depreciated or amortized on a
unit-of-production method, based on proved developed oil and gas reserves. The
carrying amount of all unproved properties is evaluated periodically and reduced
if such properties have been impaired.

The gas plant is stated at cost and is depreciated utilizing the
straight-line method over 14 years.

F-18
<PAGE> 84

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Furniture and equipment are stated at cost and are depreciated utilizing
the straight-line method over three to five years.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at December 31, 1995 and 1994
comprised the following (amounts in thousands):

<TABLE>
<CAPTION>
1995 1994
------- ------
<S> <C> <C>
Accrued development costs......................................... $ 8,188 $1,823
Accrued interest payable.......................................... 4,217 814
Trade accounts payable............................................ 1,889 2,434
Other accrued liabilities......................................... 319 275
------- ------
$14,613 $5,346
======= ======
</TABLE>

Capitalized Interest Costs

Certain interest costs of approximately $452,000 have been capitalized as
part of the historical costs of unproved oil and gas properties effective with
the refinancing and subsequent active development thereof in July 1995 and
through December 31, 1995.

Net Loss per Common Share

Net loss per common share was calculated by dividing the net loss, after
consideration of preferred stock dividends paid or accrued and related
accretion, by the weighted average number of common shares outstanding during
each period. Outstanding stock options, warrants and convertible preferred
shares were not included in the calculations, since their effect was
antidilutive in all periods. The weighted average number of outstanding common
shares utilized in the calculation was 7,904,000 shares in 1995, 6,447,000
shares in 1994 and 5,492,000 shares in 1993.

New Accounting Standard: Impairment of Long-Lived Assets

Accordingly, the estimated fair values of its oil and gas properties at
December 31, 1995 were evaluated and compared to the carrying values of such
assets at that date. The resulting impairment loss of $876,000 was included in
depletion, depreciation, amortization and impairment in 1995.

Use of Estimates

F-19
<PAGE> 85

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

and gas reserve volumes and the related present value of estimated future net
revenues therefrom (see Note 16, "Oil and Gas Producing Activities").

Prior Year Reclassifications

Certain prior year amounts have been reclassified to conform with the
current year presentation.

(2) SOUTH TEXAS LIMITED PARTNERSHIP

In October 1992, the Company formed STLP, a Texas limited partnership, with
two industry partners. The Company became a general partner of STLP with an
initial 25.25% interest in the partnership. In May 1993, the Company purchased
an additional 12.625% of STLP for $1,095,000 in cash and assumed an incremental
12.625% of STLP's production note with a bank ($787,000 at the acquisition
date).

In March 1994, the Company and the remaining partner of STLP agreed to
dissolve and terminate the partnership. Pursuant to the terms of a dissolution
agreement, 37.875% of the assets and liabilities of STLP (reflecting its
proportionate interest in STLP) were distributed to the Company. The principal
asset distributed to the Company was its 37.875% direct working interest in the
South Texas Properties. Concurrent with STLP's dissolution, the Company repaid
its respective share of all amounts owed pursuant to STLP's production note
outstanding ($3.1 million). The dissolution of STLP resulted in a write-off of
$122,000 by the Company of deferred financing costs in connection with the early
extinguishment of debt and the write-off of $203,000 in oil and gas properties
resulting from a conveyance of 6% of the South Texas Properties pursuant to the
dissolution agreement.

(3) ROYALTY EXCHANGE AND ISSUANCE OF PREFERRED STOCK

In March 1993, the Company entered into a transaction in which six
institutional participants in the TCW Commingled Debt and Royalty Fund I ("the
Fund") exchanged their proportionate share of the gross royalty and net profit
interests in certain oil and gas properties (the "Royalty Interests") for an
aggregate of 30,000 shares of the Company's 8% Series B Convertible Preferred
Stock priced at $100 per share. Trust Company of the West ("TCW") is the manager
and trustee of the Fund. As of December 31, 1995, TCW, acting on behalf of
certain pension funds, was a holder of approximately 17% of the outstanding
common stock of the Company.

The Royalty Interests acquired by the Company consisted of gross overriding
royalty interests and net profit interests, which were estimated to have total
proved net reserves of 124,000 barrels of oil and 2.64 Bcf of natural gas with
an ascribed acquisition cost of $3,073,000.

(4) ACQUISITION OF BAKERSFIELD PROPERTIES

On June 30, 1994, the Company acquired a 75% interest in substantially all
of the oil and gas properties, a 23 MMcf per day natural gas processing plant
and gathering lines owned by Bakersfield Energy Resources, Inc. and its
affiliates ("BER"). The oil and gas reserves acquired were principally natural
gas (1,240 Btu) and light (35-40() gravity), low sulfur, crude oil located in
Kern County, California. BER has retained its remaining 25% working interest in
these assets and continues to operate all of the properties and facilities
acquired by the Company. Additionally, the Company and BER entered into a
three-year joint acquisition agreement which gives each the right to participate
in acquisitions of oil and gas interests located within the state of California
by the other.

The purchase price for such interests was approximately $46 million,
consisting of $42 million in cash plus 25,000 shares of the Company's common
stock, 30,000 shares of the Company's Series E Junior Convertible Preferred
Stock at $100 per share and a seven-year callable warrant to purchase 1,000,000
shares of common stock at an exercise price of $5.00 per share to which the
Company had ascribed a value of

F-20
<PAGE> 86

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

$850,000. This warrant was subsequently canceled in May 1995 pursuant to a
warrant exchange agreement. (See Note 11.)

To finance the acquisition, the Company amended its credit facility with a
group of lenders led by Internationale Nederlanden (U.S.) Capital Corporation
("ING Capital") to increase the total commitment under such facility to $34.4
million. The Company financed the cash portion of the purchase price with (i)
$25 million of incremental borrowings under a credit agreement; (ii) $5 million
of borrowings under a bridge loan facility with ING Capital; (iii) $10 million
gross proceeds from the private placement of 100,000 shares of the Company's
Series D Preferred Stock and (iv) a portion of the $3.5 million of gross
proceeds from the private placement of 1,071,538 shares of common stock. The
assets acquired in this transaction were accounted for by the purchase method of
accounting.

The following table presents the unaudited pro forma condensed consolidated
statement of operations for the year ended December 31, 1994, assuming the
acquisition of the Bakersfield Properties and the related financings had
occurred at January 1, 1994 (amounts are in thousands except per share data):

<TABLE>
<S> <C>
Total revenues............................................................. $19,304
=======
Net loss attributable to common stockholders............................... $(1,587)
=======
Net loss per common share.................................................. $ (0.22)
=======
</TABLE>

Pro forma net loss for the year ended December 31, 1994 includes losses of
approximately $600,000 attributable to gas plant operating losses incurred
during its start-up phase prior to acquisition by the Company.

(5) SUBORDINATED BRIDGE LOAN

In connection with the acquisition of the Bakersfield Properties in June
1994, the Company entered into a $5 million bridge loan facility (the "Bridge
Loan") with ING Capital. Outstanding advances under the Bridge Loan bore
interest at a floating rate of, at the Company's option, prime plus 2% or LIBOR
plus 4% per annum until September 30, 1994 and escalating by (i) .75% per annum
from October 1, 1994 through January 31, 1995 and (ii) 1.5% per annum at all
times after January 31, 1995.

In July 1995, the Company refinanced the Bridge Loan with proceeds from a
long-term refinancing of its debt. (See Note 6.)

(6) LONG-TERM DEBT

Effective upon the closing of the acquisition of the Bakersfield Properties
in June 1994, the Company amended its facility with ING Capital (the "Amended
Credit Agreement") to provide for a total commitment of $34.4 million.
Outstanding advances under the Amended Credit Agreement bore interest at a
floating rate of, at the Company's option, prime plus 1% or LIBOR plus 3% per
annum.

The Amended Credit Agreement contained certain covenants and restrictions
with respect to dividends, redemption of preferred stock, general and
administrative expenses, working capital, fixed charge coverage ratios and
hedging activities. The Amended Credit Agreement also made provisions for the
mandatory early repayment of portions of the loan amount outstanding under
certain specified events. The Company issued to the lending institutions
involved with the Amended Credit Agreement and the preceding credit facility
warrants to purchase an aggregate of 326,000 shares of its common stock at
prices ranging from $4.75 to $5.50 per share, of which 226,000 warrants were
canceled pursuant to certain warrant exchange agreements subsequent to December
31, 1995. (See Note 11.)

F-21
<PAGE> 87

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

In July 1995, the Company repaid $34.3 million of the amount outstanding
under the Amended Credit Agreement with proceeds resulting from a long-term
refinancing of its debt and entered into a new credit agreement with ING Capital
(the "New Credit Agreement"). A write-off of deferred financing costs of
approximately $1.9 million was charged to expense as an extraordinary item
resulting from this early extinguishment of debt and concurrent early redemption
of the Series D Preferred Stock. (See Notes 7 and 8.)

The New Credit Agreement provides that the Company initially may borrow up
to $10 million on a revolving credit basis. Availability under the New Credit
Agreement is limited to a "borrowing base" amount. The borrowing base will be
determined semi-annually by ING Capital, at its sole discretion, and may be
established at an amount up to $15 million. The initial borrowing base was set
at and is currently $10 million, and ING Capital will have no obligation to
increase the borrowing base above this amount. Availability under the New Credit
Agreement, as amended in March 1996, will terminate on June 30, 1997, at which
time amounts outstanding under the New Credit Agreement will convert to a term
loan on September 30, 1997, with a set amortization schedule of a percentage of
the outstanding principal balance continuing through December 31, 2000. There
was $5.6 million outstanding under the New Credit Agreement at December 31,
1995. The effective interest rate on the balance outstanding was approximately
9% at that date. Amounts advanced under the New Credit Agreement will bear
interest at an adjusted Eurodollar rate plus 2.50%.

The New Credit Agreement contains restrictive covenants which impose
limitations on the Company and its subsidiaries with respect to, among other
things: (i) the maintenance of current assets equal to at least 100% of current
liabilities, (ii) the maintenance of a minimum tangible net worth, (iii) the
incurrence of indebtedness (with exceptions for the notes and the New Credit
Agreement and certain other limited exceptions), (iv) dividends and similar
payments (except dividends on Series A, B and C Preferred Stock of up to
$530,000), (v) the creation of additional liens on, or the sale of, the
Company's oil and gas properties and other assets, (vi) the Company's ability to
enter into hedging transactions, (vii) mergers or consolidations, (viii)
investments outside the ordinary course of business and (ix) transactions with
affiliates.

All indebtedness of the Company under the New Credit Agreement is secured
by a first lien upon substantially all of the Company's oil and gas properties
as well as by a pledge of all of the capital stock of the Company's subsidiaries
and the accounts receivable, inventory, general intangibles, machinery and
equipment and other assets of the Company. All assets not subject to a lien in
favor of the lender are subject to a negative pledge, with certain exceptions.

(7) SENIOR SECURED NOTE OFFERING

Sale of Units

On July 24, 1995, the Company consummated the sale (the "Note Offering") of
65,000 units (the "Units") consisting of $65 million aggregate principal amount
of its 14 7/8% Senior Notes due July 15, 2002 (the "Notes") and warrants to
purchase 1,430,000 shares of common stock. Each Unit consists of a $1,000
principal amount Note and 22 warrants to purchase an equal number of shares of
common stock. The Notes and warrants became separately transferrable immediately
after July 24, 1995.

Use of Proceeds

The net proceeds to the Company from the offering of Units was
approximately $61 million after deducting discounts and offering expenses. The
Company immediately used a portion of the net proceeds to (i) repay $34.3
million outstanding under its Amended Credit Agreement with ING Capital and
repay $5 million outstanding under the Bridge Loan with ING Capital, (ii) redeem
$10.9 million in outstanding shares of Series D Preferred Stock and (iii)
acquire interests in certain oil and gas wells associated with the Bakersfield
Properties (the "Carried Interests Wells") for $2.3 million. The Company used
the balance of the

F-22
<PAGE> 88

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

proceeds from the Note Offering to finance a portion of the development of the
Bakersfield Properties during the remainder of 1995.

The Notes

The Notes are issued pursuant to an indenture, dated July 24, 1995, between
the Company and Texas Commerce Bank National Association, as Trustee (the
"Indenture"). All of the obligations of the Company under the Notes and the
Indenture are secured by a second priority lien on substantially all of the
assets of the Company and its subsidiaries securing its bank debt. The
subsidiaries of the Company were merged into HarCor subsequent to December 31,
1995 and all of their assets became the property, and all of their liabilities
and guarantees became the obligations, of HarCor.

The Warrants

Each warrant entitles the holder thereof to purchase one share of common
stock at an exercise price of $3.85 per share. The warrants are exercisable at
any time on or after July 24, 1996 and expire at the close of business on July
24, 2000. Holders of the warrants have certain demand and piggy-back rights to
cause the Company to register the shares of common stock issuable thereunder.
Such shares of common stock collectively represent approximately 10% of the
common stock of the Company on a fully diluted basis (after taking into account
the conversion or exercise of all existing options, warrants and other
convertible securities).

Placement of Units

Subject to the terms of the Purchase Agreement dated July 17, 1995 (the
"Purchase Agreement"), the Company sold the Units to BT Securities Corporation
and Internationale Nederlanden (U.S.) Securities Corporation (the "Initial
Purchasers"). As part of the compensation to the Initial Purchasers in
connection with the offering of the Units, the Company issued to the Initial
Purchasers (i) additional warrants to purchase 350,000 shares of common stock at
an initial exercise price of $3.85 per share and (ii) warrants to purchase
150,000 shares of the Company's Series F Preferred Stock at an initial exercise
price of $3.85 per share. Each share of Series F Preferred Stock is convertible
into one share of common stock. The additional warrants issued as such
compensation have substantially the same terms as the warrants described above.
All of the warrants as described herein were ascribed an aggregate value of
approximately $2.2 million and are reflected in either other assets or
additional paid-in capital to be amortized over the life of the Notes.

Equity Proceeds Offer and Redemption

In the event the Company completes an offering for the sale of $5 million
or more of its equity securities on or prior to July 15, 1997 ("Equity
Offering"), then following such Equity Offering, the Company must

F-23
<PAGE> 89

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

make an offer to purchase from all the holders of the Notes ("Holders") (on a
date not later than the 90th day after the date of the consummation of such
Equity Offering) at a purchase price equal to 110% of the aggregate principal
amount of Notes to be repurchased, plus accrued and unpaid interest thereon, an
aggregate principal amount of Notes equal to the lesser of (i) the maximum
principal amount of Notes such that 60% of the aggregate principal amount of
Notes originally issued remains outstanding after completion of the offer or
(ii) the maximum principal amount of the Notes which could be purchased with 50%
of the amount of net proceeds received or receivable by the Company from such
Equity Offering.

Excess Cash Flow Offer

In the event that the Company has excess cash flow (as defined) in excess
of $2 million in any fiscal year, beginning with the fiscal year ending December
31, 1996, the Company will be required to make an offer to purchase Notes from
all Holders in an amount equal to 50% of all such excess cash flow for such
fiscal year (not just the amount in excess of $2 million) at a purchase price
equal to 101% of the principal amount thereof, plus accrued and unpaid interest
thereon ("Excess Cash Flow Offer"). The Company may credit the principal amount
of Notes acquired in the open market and retired prior to the Excess Cash Flow
Offer against such required Excess Cash Flow Offer, provided that each Note may
only be so credited once. Excess cash flow for this purpose is generally defined
as net cash flow provided by operations less capital expenditures and payments
on scheduled indebtedness.

Pro Forma Financial Statements

The following Unaudited Pro Forma Condensed Consolidated Statements of
Operations are derived from the historical financial statements of the Company
set forth herein and are adjusted to reflect (i) the issuance of the Units and
the application of a portion of the net proceeds to repay all indebtedness
outstanding under the Amended Credit Agreement and the Bridge Loan and to redeem
the Series D Preferred Stock and (ii) the acquisition of the Carried Interests
Wells as if such transactions had occurred on January 1, 1995. This unaudited
pro forma financial information should be read in conjunction with the notes
thereto.

The unaudited pro forma financial information does not purport to be
indicative of the results of operations that would actually have occurred if the
transactions described had occurred as presented in such statements 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 crude oil and
natural gas production declines, reductions in prices paid for crude oil and
natural gas, future acquisitions and other factors.

F-24
<PAGE> 90

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 1995

<TABLE>
<CAPTION>
PRO FORMA
----------------------------------------------------
ADJUSTMENTS
------------------------
CARRIED NOTE
HISTORICAL INTERESTS(A) OFFERING ADJUSTED
---------- ------------ -------- --------
<S> <C> <C> <C> <C>
Total revenues.................................. $ 22,595 $ 1,281 $ -- $ 23,876
------- ------ ------- -------
Costs and expenses:
Operating and exploration costs............... 9,278 194 -- 9,472
Depletion, depreciation, amortization and
impairment................................. 5,973 445 -- 6,418
General and administrative expenses........... 2,744 -- -- 2,744
Interest expense.............................. 6,847 -- 3,826(B) 10,673
Other...................................... 483 -- -- 483
------- ------ ------- -------
Total costs and expenses................... 25,325 639 3,826 29,790
------- ------ ------- -------
Loss from continuing operations............... $ (2,730) $ 642 $ (3,826) $ (5,914)
======= ====== ======= =======
Loss applicable to common shareholders........ $ (7,765) $ (8,263)
======= =======
Loss from continuing operations per share
applicable to common shareholders............. $ (0.98) $ (1.05)(C)
======= =======
Weighted average shares outstanding............. 7,904 7,904(C)
======= =======
</TABLE>

All amounts in the tables above are in thousands except per share data.
See accompanying notes to pro forma financial statements.

Pro forma adjustments to the Unaudited Pro Forma Condensed Consolidated
Statements of Operations included herein are as follows (dollar amounts are in
thousands):

(A) Revenues and expenses resulting from the acquisition of the Carried
Interests Wells and adjustments to depletion, depreciation and
amortization for the six months ended June 30, 1995 (the Carried
Interests were acquired effective July 1, 1995).

(B) Changes in interest expense associated with (i) the inclusion of $6,030
in interest, discount amortization and amortization of deferred
financing costs associated with the Notes for the period ended July 24,
1995, the date of the completion of Note Offering, and (ii) the
elimination of $2,204 in interest expense and deferred financing costs
for that period related to the Amended Credit Agreement and the Bridge
Loan.

(C) The pro forma earnings per share data reflect dividends on remaining
preferred stock which increase loss applicable to common shareholders.
The extraordinary write-off of deferred financing costs and the charge
to additional paid-in capital resulting from the early extinguishment of
debt and early redemption of preferred stock have not been reflected in
the earnings per share calculation as their effects are nonrecurring.
Outstanding stock options, warrants and Convertible Preferred shares
were not included in the calculation as their effect was antidilutive.

(8) REDEMPTION OF SERIES D PREFERRED STOCK

In connection with the acquisition of the Bakersfield Properties in June
1994, the Company had issued 100,000 shares of Series D Preferred Stock with
detachable warrants in a private placement at a price of

F-25
<PAGE> 91

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

$100.00 per share for an aggregate value of $10 million. The Series D Preferred
Stockholders ("Series D Holders") received dividends at rates from 9% to 12% per
annum, payable in cash or in shares of the Series D Preferred Stock at the
option of the Company. Pursuant to the Company's election to pay a portion of
dividends in shares and also as a result of accretion, the number of shares
outstanding of the Series D Preferred had increased to 109,312 shares and its
face value had increased to $10.9 million at June 30, 1995.

Upon issuance of the Series D Preferred Stock, the Company issued to the
Series D Holders warrants to purchase 2,305,263 shares of common stock at an
initial exercise price of $4.75 per share. The Company had ascribed a value to
these warrants of $0.92 per warrant, based on certain warrant valuation models,
for an aggregate value of $2.1 million. Pursuant to generally accepted
accounting principles, the Company had allocated the $2.1 million ascribed value
of the warrants to additional paid-in capital and correspondingly reduced the
face amount of the Series D Preferred Stock reflected on its balance sheet to
$7.9 million at the original date of issuance. Pursuant to the issuance of share
dividends and terms of the Series D Preferred Stock, the number of warrants to
purchase common stock issued to the Series D Holders thereof had increased to
3,424,666 at June 30, 1995, and the exercise price had decreased to $3.67 per
share.

In July 1995, the Company redeemed the total 109,312 shares of Series D
Preferred Stock outstanding with proceeds resulting from a long-term refinancing
of its debt. (See Note 7.) Resultant from this early redemption was an
acceleration of accretion resulting in a non-cash charge of $2.1 million to
paid-in capital in 1995.

Also in conjunction with the early redemption of the Series D Preferred
Stock, the Series D Holders exchanged all of their warrants to purchase shares
of common stock for unregistered common stock of the Company. (See Note 11.)

(9) COMMITMENTS AND CONTINGENCIES

Risk Management and Hedging Activities

The Company utilizes financial instruments as a hedging strategy to protect
against the effects of volatility in crude oil and natural gas commodity prices.
Upon consummation of an acquisition, the Company will usually enter into
commodity derivative contracts (hedges) such as futures, swaps or collars or
forward contracts which cover a substantial portion of the existing production
of the acquired property. Over time, as production increases, the Company will
continue to utilize hedging techniques to ensure that a substantial portion of
its production remains appropriately hedged. Gains or losses under the hedging
agreements are recognized in oil and gas production revenues in periods in which
the hedged production occurs and such agreements are settled on a monthly basis.

As of December 31, 1995, the Company was a party to various gas contracts
covering volumes of approximately 4.0 Bcf and 3.4 Bcf for 1996 and 1997,
respectively, at prices ranging from $1.68/MMBtu to $2.07/MMBtu; and oil hedges
covering notional volumes of approximately 243 MBOE, 98 MBOE and 29 MBOE for
1996, 1997 and 1998, respectively, at prices ranging from $15.80/Bbl to
$18.75/Bbl.

The following table summarizes the estimated fair value of financial
instruments and related transactions for non-trading activities at December 31,
1995 (amounts are in thousands):

<TABLE>
<CAPTION>
ESTIMATED
CARRYING FAIR
AMOUNT VALUE(1)
-------- ---------
<S> <C> <C>
Long-Term Debt(2)(4)............................................ $ 5,600 $ 5,600
14 7/8% Senior Secured Notes(3)(4).............................. $ 63,109 $63,109
Financial Instruments........................................... -- $ 710
</TABLE>

F-26
<PAGE> 92

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

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

(1) Estimated fair values have been determined by using available market data
and valuation methodologies. Judgment is necessarily required in
interpreting market data and the use of different market assumptions or
estimation methodologies may affect the estimated fair value amounts.

(2) See Note 6, "Long-Term Debt."

(3) See Note 7, "Senior Secured Note Offering."

(4) The fair value of long-term debt and the Senior Secured Notes are the value
the Company would have to pay to retire the debt or the Notes, including
any premium or discount to the holder for the differential between the
stated interest rate and the year-end market rate. The fair value of the
long-term debt and the Notes is based upon interest rates available to the
Company at year-end.

Lease Obligations

Future net minimum rental payments for office and office equipment lease
commitments as of December 31, 1995 aggregated approximately $180,000 and
$52,000 for 1996 and 1997, respectively.

Rental expense in the aggregate under noncancellable long-term operating
leases was approximately $165,000, $159,000 and $166,000 for 1995, 1994 and
1993, respectively.

(10) INCOME TAXES

The Company files a consolidated United States federal income tax return
for its United States incorporated entities.

The difference between the federal income tax statutory rate of 35% and the
effective tax rate of zero for such years reflected in the accompanying
consolidated statements of operations relates to the uncertainty of utilizing
future benefits from net operating loss carryforwards.

The Company did not pay any United States regular or alternative minimum
federal income taxes during the three-year period ended December 31, 1995 due to
taxable losses in all three years.

At December 31, 1995, the Company had accumulated net operating loss
("NOL") carryforwards for United States federal income tax purposes of
approximately $21,287,000. Certain Company security transactions occurring since
1986 have triggered changes in the stock ownership of the Company aggregating
more than 50% over a three-year period. Accordingly, NOL carryforwards of
approximately $5,455,000 arising prior to 1987 are limited to approximately
$755,000 of future utilization in the aggregate (expiring in the year 2001), and
certain NOLs are subject to limitations on the amounts that may be used to
reduce taxable income in any given year. Accordingly, the total net operating
loss carryforwards available to reduce federal income taxes in the future are
approximately $16,587,000. Such net operating loss carryforwards expire as
follows for the years ending December 31 (amounts in thousands):

F-27
<PAGE> 93

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Under the provisions of SFAS 109, the income tax effects of temporary
differences between financial and income tax reporting and carryforwards that
give rise to deferred income tax assets and liabilities at December 31, 1995 and
1994 are as follows (amounts in thousands):

<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1995 1994
------- -------
<S> <C> <C>
Deferred tax assets:
Net operating loss carryforwards............................... $ 5,805 $ 3,540
Accounts payable............................................... -- 1,757
Other.......................................................... 115 --
------- -------
Total deferred tax assets................................... 5,920 5,297
Less valuation allowances................................... (4,145) (2,472)
------- -------
Net deferred tax assets..................................... $ 1,775 $ 2,825
------- -------
Deferred tax liabilities:
Intangible drilling costs...................................... $(1,375) $(1,285)
Depreciation of property and equipment......................... (306) (294)
Accounts receivable............................................ -- (1,152)
Other.......................................................... (94) (94)
------- -------
Total deferred tax liabilities.............................. (1,775) (2,825)
------- -------
Net deferred taxes.......................................... $ -- $ --
======= =======
</TABLE>

(11) STOCKHOLDERS' EQUITY

Common Stock

During 1993, holders of 3,000 shares of Series A Preferred Stock converted
these shares into 42,857 common shares of the Company; and holders of 7,500
shares of Series B Preferred Stock converted these shares into an aggregate of
192,300 common shares of the Company. Also during 1993, the Company issued
101,850 common shares at an average price of $2.42 per share pursuant to the
exercise of stock options.

In June 1994, the Board of Directors adopted (and the shareholders
approved) an amendment to the Company's Certificate of Incorporation increasing
the number of authorized shares of the Company's common stock from 15,000,000
shares to 25,000,000 shares.

In June 1994, the Company sold 1,071,538 shares of unregistered
newly-issued common stock in a private placement at $3.25 per share for gross
proceeds of approximately $3,482,000. The Company also issued to an agent
267,369 shares of common stock in connection with the above sale and the private
placement sale of the Company's Series D Preferred Stock and Series E Preferred
Stock. Additionally, the Company issued to BER 25,000 shares of common stock as
part of the consideration for the purchase of the Bakersfield Properties.

Pursuant to the terms of the above private placement sale agreement of
common stock, the Company filed on December 20, 1994 a registration statement
with the Securities and Exchange Commission covering the resale of such shares
of common stock by the initial purchasers thereof. Also included in the
registration statement were an additional 1,778,869 shares of common stock,
which included shares issued in a November 1992 private placement sale, shares
issuable upon conversion of the Company's Series B and Series C Preferred Stock
and shares issuable upon exercise of certain warrants. The Company has agreed to
keep a registration statement continuously effective for at most three years.

During 1994, the Company issued 15,000 common shares at a price of $2.19
per share pursuant to the exercise of stock options and issued an aggregate of
60,375 restricted shares of common stock to officers at

F-28
<PAGE> 94

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

$4.00 per share. Also during 1994, the Company issued 16,671 common shares
pursuant to the payment of Series E Preferred Stock dividends.

The Company issued to ING Capital an aggregate of 75,000 shares of its
common stock during 1995 pursuant to the terms of its Bridge Loan.

In April 1995, holders of 2,500 shares of Series B Preferred Stock
converted their shares into 64,100 common shares of the Company.

The Company issued 16,671 and 16,770 common shares pursuant to the payment
of Series E Preferred Stock dividends during 1994 and 1995, respectively.

Warrant Exchanges

In May 1995, BER exchanged its warrant to purchase 1,000,000 shares of the
Company's common stock at $5.00 per share for 182,500 unregistered shares of the
Company's common stock. The Company had ascribed a value of $850,000 to the
warrant upon its original issuance and has ascribed the same value to the common
stock issued in this exchange.

In July 1995, in connection with the Senior Secured Note Offering, the
Company and the Series D Holders effected an agreement pursuant to which the
Series D Holders exchanged their warrants to purchase shares of common stock for
unregistered common stock of the Company. The Series D Holders had warrants to
purchase 3,424,666 shares of common stock at an exercise price of $3.67 per
share at the time of the exchange. Pursuant to the agreement, the Series D
Holders exchanged all of their warrants for 1,100,000 unregistered shares of
common stock of the Company. This exchange agreement also contained certain
conditions including certain appreciation rights to the Series D Holders
effective during a two-year period following the exchange in the event of a sale
of the Company or its assets and certain registration rights to the Series D
Holders.

Subsequent to December 31, 1995, the Company completed exchange agreements
whereby certain holders of options and warrants to purchase the Company's common
stock exchanged all or a portion of their options and warrants outstanding for
unregistered shares of common stock of the Company. Pursuant to these exchange
agreements, an option to purchase 150,000 common shares at $4.875 per share, and
warrants to purchase an aggregate of 226,000 common shares at prices ranging
from $4.75 to $5.50 per share, were exchanged and canceled for 65,000
unregistered shares of common stock of the Company. Additionally, in March 1996,
a warrant to purchase 350,000 shares of the Company's common stock at $3.85 per
share which was issued in connection with the Note Offering was returned to the
Company and canceled.

Preferred Stock

The Series A 8% Convertible Preferred Stock, of which 5,000 shares are
outstanding, is convertible into common shares of the Company at $3.50 per
share, subject to certain anti-dilution provisions. At the Company's option, the
preferred stock may be redeemed. Upon liquidation of the Company, the preferred
shares have a preference over the common shares equal to the sum of the
aggregate offering price ($50 per share) plus accrued but unpaid dividends
thereon. The cumulative dividend of 8% is payable quarterly.

The Series B Preferred Stock, of which 20,000 shares are outstanding, is
convertible at the option of the respective holders into the Company's common
stock at $3.90 per share and will be automatically converted into common stock
of the Company at $3.90 per share on December 31, 1998. If the Company merges or
consolidates with, or sells all or substantially all of its assets to, any
entity which results in the stockholders of the Company owning less than 50% of
the voting power in the election of directors of such other entity; or if any
person other than Mark Harrington (Chairman of the Board, Chief Executive
Officer and director of the Company) acquires more than 50% of the Company's
outstanding common stock, then the conversion price

F-29
<PAGE> 95

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

shall be adjusted to the then-current market price of the Company's common
stock, but only if the then-current market price is less than the conversion
price. The Company may at its option elect to redeem the Series B Preferred
Stock at $150 per share at any time after December 31, 1994, if the then-current
market price of the Company's common stock exceeds $5.85 per share for 20 of 30
consecutive trading days. The cumulative dividend of 8% is payable quarterly.

The Series C 8% Convertible Preferred Stock, of which 10,000 shares are
outstanding at $100.00 per share, has substantially the same designations,
preferences and rights as the Series B 8% Convertible Preferred Stock.

Pursuant to the agreement with BER for the purchase of the Bakersfield
Properties, the Company issued 30,000 shares of Series E Junior Convertible
Preferred Stock (the "Series E Preferred Stock") to BER. The purchase price of
the Series E Preferred Stock was $100.00 per share for an aggregate face value
of $3,000,000. The Series E Preferred Stock is convertible at the option of the
holder into common stock at a conversion price of $3.50 per share, subject to
adjustment for certain stock dividends, subdivisions, reclassifications or
combinations with respect to the common stock and for certain other
distributions or events of consolidation, merger or sale, lease or conveyance of
all or substantially all of the assets of the Company. The Series E Preferred
Stock receives a cash dividend, cumulative from the date of issuance of the
Series E Preferred Stock and payable quarterly in arrears commencing on
September 30, 1994, at the rate of $4.00 per share per annum until June 30,
1995, and thereafter at the rate of $9.00 per share per annum. The Company has
the option of paying dividends on the Series E Preferred Stock either in cash or
in shares of common stock. The Series E Preferred Stock is redeemable in cash at
any time, in whole or in part, at the option of the Company, at a price of
$110.00 per share, plus accrued and unpaid dividends. The Company must redeem
the Series E Preferred Stock in cash upon completion of its first underwritten
public offering of securities following the issuance of the Series E Preferred
Stock in which the net proceeds received by the Company equal or exceed
$20,800,000.

Each share of Series E Preferred Stock entitles the holder thereof to such
number of votes per share as equals the whole number of shares of common stock
into which each share of Series E Preferred Stock is then convertible, and each
share of Series E Preferred Stock is entitled to vote on all matters as to which
holders of common stock are to vote, in the same manner and with the same effect
as such holders of common stock, voting together with the holders of common
stock as one class, except for certain matters in which holders of the Series E
Preferred Stock have class voting rights. At any time while a minimum of 50% of
the shares of Series E Preferred Stock remain outstanding, the Company shall not
take any action to alter or repeal its Certificate of Incorporation or Bylaws
which would adversely affect the rights, privileges or powers of the Series E
Preferred Stock (other than the issuance of additional series of stock or
increases in the authorized amount of existing series of stock) without the
consent or approval of at least a majority of the voting power of the Series E
Preferred Stock. The Company may not pay any dividend on its common stock unless
all accrued dividends on the Series E Preferred Stock have been paid.

Preferred Stock Dividends

The Company has paid dividends on preferred stocks for the three years
ended December 31, 1995 as follows:

<TABLE>
<CAPTION>
PREFERRED STOCK 1995 1994 1993
------------------------------------------------ ---------- ---------- --------
<S> <C> <C> <C>
8% Convertible Series A, B, C................... $ 265,000 $ 280,000 $246,468
9% Redeemable Series D.......................... 540,161 455,065 --
4%-9% Convertible Series E...................... 195,000 60,000 --
---------- ---------- --------
$1,000,161 $ 795,065 $246,468
========= ========= ========
</TABLE>

F-30
<PAGE> 96

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Dividends on 8% Series A, Series B and Series C Preferred Stock were paid
in cash for all years presented.

Dividends on the 9% Series D Preferred Stock for 1994 and the first two
quarters of 1995 were paid, at the option of the Company, in additional shares
of Series D Preferred Stock. Remaining accrued dividends on the Series D
Preferred Stock were paid in cash at its redemption in July 1995.

Dividends on the Series E Preferred Stock for 1994 and the first two
quarters of 1995 were paid, at the option of the Company, in shares of common
stock of the Company in lieu of cash. Dividends on the Series E Preferred were
paid in cash for the remaining two quarters of 1995. The coupon rate on the
Series E increased from 4% per annum to 9% per annum effective July 1, 1995.

(12) STOCK OPTIONS AND WARRANTS

Stock Options

In October 1992, the Board of Directors adopted the Company's 1992 Stock
Option Plan and the Company's 1992 Nonemployee Directors' Stock Option Plan. In
May 1994, the Board of Directors adopted the Company's 1994 Stock Option Plan
and amended the 1992 Nonemployee Directors' Stock Option Plan to increase the
aggregate number of shares which may be issued under that plan. These plans
initially had available an aggregate of 1,525,000 shares of common stock and
allow the granting of options to purchase shares to employees, officers and
nonemployee directors of the Company at a price, for any incentive stock
options, not less than the fair market value of the common stock at the time of
grant. In the case of options that do not constitute incentive stock options,
the options may not be less than 85% of the fair market value of the shares at
the time the option is granted. The options under these plans vest over a
two-year period and expire in five years.

In addition to the above stock option plans, the Company's Board of
Directors and Option Committee has, from time to time, granted options directly
to its officers and directors outside of the existing plans.

Option transactions for the three years ended December 31, 1995 are
summarized as follows:

<TABLE>
<CAPTION>
NUMBER OF OPTIONS
--------------------------------------------
AVAILABLE
EXERCISE FOR FUTURE
OUTSTANDING PRICE GRANT
----------- -------------- ----------
<S> <C> <C> <C>
Balance at December 31, 1992................. 693,150 $2.19 -- $3.85 226,500
Expired.................................... (112,800) $3.30 --
Exercised.................................. (101,850) $2.19 -- $2.80 --
Granted.................................... 167,000 $3.88 -- $4.68 (167,000)
----------- ----------
Balance at December 31, 1993................. 645,500 $2.19 -- $4.68 59,500
Exercised.................................. (15,000) $2.19 --
New plans or shares........................ -- -- 1,100,000
Granted.................................... 330,000 $3.38 -- $4.33 (280,000)
----------- ----------
Balance at December 31, 1994................. 960,500 $2.20 -- $4.68 879,500
Expired.................................... (62,000) $3.13 -- $4.68 62,000
Granted.................................... 150,000 $2.61 -- $3.71 (150,000)
----------- ----------
Balance at December 31, 1995................. 1,048,500 $2.20 -- $4.68 791,500
========= ========
</TABLE>

At December 31, 1995, options to purchase 1,048,500 common shares were
outstanding under these plans and agreements (744,000 exercisable with prices
ranging from $2.20 to $4.68 per share). At December 31, 1995, the aggregate
exercise price of these exercisable options was $2,758,000. Subsequent to
December 31,

F-31
<PAGE> 97

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

1995, an option to purchase 150,000 shares of common stock at $4.875 per share
was canceled pursuant to an exchange offer. (See Note 11.)

Warrants

The Company has issued warrants in connection with certain of its
financings. Issuances of these warrants are described in other footnotes herein
pertaining to those transactions. All warrant transactions for the three years
ended December 31, 1995 are summarized as follows:

<TABLE>
<CAPTION>
NUMBER OF
WARRANTS EXERCISE
OUTSTANDING PRICE
---------- --------------
<S> <C> <C>
Balance at December 31, 1992............................ 640,293 $3.20 -- $5.00
1993 Activity......................................... -- --
----------
Balance at December 31, 1993............................ 640,293 $3.20 -- $5.00
Granted............................................... 3,757,294 $4.65 -- $5.50
----------
Balance at December 31, 1994............................ 4,397,587 $3.20 -- $5.50
Expired............................................... (291,346) $5.00
Canceled.............................................. (4,424,666) $4.75 -- $5.00
Granted............................................... 3,051,765 $3.85 -- $4.75
----------
Balance at December 31, 1995............................ 2,733,340 $3.20 -- $5.50
=========
</TABLE>

At December 31, 1995, warrants to purchase 2,733,340 common shares were
outstanding and exercisable under all current warrant agreements. At December
31, 1995, the aggregate exercise price of these warrants was $11,045,000.
Subsequent to December 31, 1995, warrants to purchase an aggregate of 576,000
common shares at prices ranging from $3.85 to $5.50 per share were canceled
pursuant to certain exchange agreements. (See Note 11.)

In October 1995, the Financial Accounting Standards Board issued SFAS No.
123, "Accounting for Stock-Based Compensation." SFAS No. 123 encourages
companies to account for stock-based compensation awards based on the fair value
of the awards at the date they are granted. The resulting compensation cost
would be shown as an expense in the statement of income. Companies can choose
not to apply the new accounting method and continue to apply current accounting
requirements; however, disclosure will be required as to what net income and
earnings per share would have been had the new accounting method been followed.
SFAS No. 123 is effective for calendar year 1996, and the Company intends not to
apply SFAS No. 123 in its statement of operations in future periods.

F-32
<PAGE> 98

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

(13) RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES

The following table sets forth the Company's results of operations for oil
and gas producing activities for the years ended December 31, 1995, 1994 and
1993 (amounts in thousands):

<TABLE>
<CAPTION>
1995 1994 1993
------- ------- ------
<S> <C> <C> <C>
Oil and gas revenues................................... $16,030 $10,982 $6,507
Gas plant and related revenues......................... 6,362 1,978 --
------- ------- ------
22,392 12,960 6,507
------- ------- ------
Production costs....................................... 5,263 3,610 2,249
Gas plant operating costs.............................. 3,704 1,708 --
Exploration expenses................................... 311 329 229
Depreciation -- gas plant.............................. 316 159 --
Depletion, depreciation and impairment................. 5,619 3,694 2,619
------- ------- ------
15,213 9,500 5,097
------- ------- ------
Income before income taxes............................. 7,179 3,460 1,410
Income tax expense..................................... 2,513 1,211 479
------- ------- ------
Net income............................................. $ 4,666 $ 2,249 $ 931
======= ======= ======
</TABLE>

The results of operations from oil and gas producing activities were
determined in accordance with Statement of Financial Accounting Standards No.
69, "Disclosures About Oil and Gas Producing Activities" ("SFAS 69") and,
therefore, do not include corporate overhead, interest and other general income
and expense items.

The Company's depletion, depreciation and impairment expense for oil and
gas properties per physical unit of production measured in barrel of oil
equivalents (with six Mcf of gas equalling one barrel of oil) was $4.26, $4.26
and $5.13 for the years ended December 31, 1995, 1994 and 1993, respectively.
The Company's depletion and depreciation expense for 1995 included an impairment
write-down of $876,000 relating to the implementation of the provisions of SFAS
121. Excluding such impairment write-down, the Company's depletion and
depreciation expense was $3.60 per barrel of oil equivalent for 1995.

(14) CAPITALIZED COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES

The aggregate amounts of capitalized costs relating to the Company's oil
and gas producing activities and the related accumulated depletion,
depreciation, amortization and impairment at December 31, 1995 and 1994 were as
follows (amounts are in thousands):

<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Unproved properties............................................ $ 5,040 $ 7,414
Proved properties.............................................. 90,200 69,805
------- -------
Total capitalized costs........................................ 95,240 77,219
Less -- accumulated depletion, depreciation and amortization... (22,501) (16,565)
------- -------
$ 72,739 $ 60,654
======= =======
</TABLE>

F-33
<PAGE> 99

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

The following table sets forth the costs incurred, both capitalized and
expensed, in the Company's oil and gas property acquisition, exploration and
development activities for the years presented (amounts in thousands):

<TABLE>
<CAPTION>
1995 1994 1993
------- ------- ------
<S> <C> <C> <C>
Property acquisition costs --
Proved................................................. $ 407 $39,094 $5,148
Unproved............................................... -- 7,013 22
Exploration costs........................................ 311 329 229
Development costs........................................ 17,760 4,998 3,047
------- ------- ------
$18,478 $51,434 $8,446
======= ======= ======
</TABLE>

(15) MAJOR CUSTOMERS AND CREDIT RISK

Substantially all the Company's accounts receivable at December 31, 1995
result from oil and gas sales and joint interest billings to other companies in
the oil and gas industry. This concentration of customers and joint interest
owners may impact the Company's overall credit risk, either positively or
negatively, in that these entities may be similarly affected by industry-wide
changes in economic or other conditions. Such receivables are generally not
collateralized. Historically, credit losses incurred by the Company on
receivables generally have not been material. No known material credit losses
were experienced during 1995.

The Company grants short-term credit to its customers, primarily major oil
and gas companies, and generally receives payment within 30 to 60 days after the
month of production.

The following table summarizes the customers that accounted for more than
10% of the Company's oil and gas revenues in at least one of the years
indicated:

<TABLE>
<CAPTION>
CUSTOMER 1995 1994 1993
----------------------------------------------------------- ---- ---- ----
<S> <C> <C> <C>
Cabot Oil and Gas Marketing Corp. ......................... -- 21% --
Kern Oil and Refining...................................... 10% 17% --
Mock Resources, Inc. ...................................... 24% -- --
Valero Gas Marketing, L.P. ................................ 10% -- --
Washington Energy Marketing, Inc. ......................... -- -- 36%
</TABLE>

The Company considers its relationship with its current major customers to
be satisfactory.

(16) OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Reserves

The process of estimating proved developed and proved undeveloped oil and
gas reserves is very complex, requiring significant subjective decisions in the
evaluation of available geologic, engineering and economic data for each
reservoir. The data for a given reservoir may change over time as a result of,
among other things, additional development activity, production history and
viability of production under varying economic conditions. Consequently,
material revisions to existing reserve estimates may occur in the future.
Although every reasonable effort is made to ensure that reserve estimates are
based on the most accurate and complete information possible, the significance
of the subjective decisions required and variances in available data for various
reservoirs make these estimates generally less precise than other estimates
presented in connection with financial statement disclosures.

F-34
<PAGE> 100

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

The Company's oil and gas reserves, shown below, all of which are located
in the continental United States, consist of proved developed and undeveloped
reserves which, based on subjective judgments, are estimated to be recoverable
in the future under existing economic and operating conditions.

The following table sets forth the changes in the Company's total proved
reserves for the years ended December 31, 1995, 1994 and 1993. The reserve
estimates for the Royalty Interests were prepared by Huddleston Engineering. All
other U.S. reserve estimates for the Company were prepared by Ryder Scott
Company. Both firms are independent petroleum engineering firms.

During 1993, additional proved undeveloped reserves were assigned to STLP
as a result of development activities on these properties. Proved undeveloped
reserves were also added in 1993 for a new waterflood project in Lea County, New
Mexico. A portion of the proved undeveloped reserves from new waterflood
projects was moved to the proved developed reserve category in 1993 as a result
of a production response in one of the two projects during 1993. Reserves in
certain instances were revised downward as a result of lower oil prices
adversely affecting economic limits and also the reduced performance on some
projects.

During 1994, the acquisition of interests in the San Joaquin Basin
properties account for the reserve volumes purchased in 1994. Additional
development drilling work performed on the San Joaquin properties during the
last six months of 1994 has resulted in an extension of the proved undeveloped
reserve area and is reflected in the extension and discoveries. The improved
production performance of the properties has also resulted in an upward revision
of the proved reserves. Improved performance on certain Permian Basin properties
has also resulted in an increase in reserves. The less than expected performance
of the South Texas gas properties and reduced gas prices at December 31, 1994
has resulted in downward revisions of the South Texas reserves. Although gas
prices were generally lower at December 31, 1994, as compared to December 31,
1993, an increase in oil prices during the same period provided an offset in
revenue which prevented significant changes in economic limits for various
properties.

During 1995, the continued development drilling program on the San Joaquin
properties and the successful drilling of a step-out well on the Ellis Lease
resulted in a further extension of the proved undeveloped area which is
reflected in the extension and discoveries. The favorable gas production rates
on the properties also resulted in an upward revision of the proved gas
reserves. In 1995, the acquisition of interests in additional wells in the San
Joaquin properties and the acquisition of additional properties in the Permian
Basin account for the reserve volumes purchased in 1995.

F-35
<PAGE> 101

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

<TABLE>
<CAPTION>
OIL NGLS GAS
PROVED RESERVES (BBLS) (BBLS) (MCF)
- ------------------------------------------------------ ---------- --------- ----------
<S> <C> <C> <C>
Proved reserves December 31, 1992..................... 1,331,085 -- 6,591,417
Revisions of previous estimates..................... (512,883) -- (272,711)
Improved recovery................................... 695,198 -- 688,000
Extensions, discoveries and other additions......... 58,604 -- 7,645,825
Sales in place...................................... (562) -- (249,202)
Purchases in place.................................. 334,685 -- 4,750,447
Production.......................................... (181,759) -- (1,984,820)
---------- --------- ----------
December 31, 1993..................................... 1,724,368 -- 17,168,956
Revisions of previous estimates..................... 1,697,742 -- 5,538,878
Improved recovery................................... -- -- --
Extensions, discoveries and other additions......... 950,013 -- 5,356,714
Sales in place...................................... (2,411) -- (280,907)
Purchases in place.................................. 6,523,611 2,994,273 45,344,000
Production.......................................... (311,831) (85,940) (3,325,641)
---------- --------- ----------
December 31, 1994..................................... 10,581,492 2,908,333 69,802,000
Revisions of previous estimates..................... (17,124) 102,106 10,118,498
Improved recovery................................... -- -- --
Extensions, discoveries and other additions......... 1,851,381 174,991 12,291,500
Sales in place...................................... -- -- --
Purchases in place.................................. 404,508 -- 561,281
Production.......................................... (462,533) (206,823) (5,137,079)
---------- --------- ----------
December 31, 1995..................................... 12,357,724 2,978,607 87,636,200
========== ========= ==========
Proved developed reserves -- December 31, 1993........ 869,328 -- 11,361,784
========== ========= ==========
December 31, 1994..................................... 2,555,988 1,014,293 27,651,000
========== ========= ==========
December 31, 1995..................................... 2,801,504 939,088 32,474,000
========== ========= ==========
</TABLE>

F-36
<PAGE> 102

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

Standardized Measures of Discounted Future Net Cash Flows

The Company's standardized measure of discounted future net cash flows, and
changes therein, related to proved oil and gas reserves are as follows (amounts
in thousands):

<TABLE>
<CAPTION>
1995 1994 1993
--------- --------- ---------
<S> <C> <C> <C>
Future cash inflow............................ $ 478,302 $ 375,585 $ 57,052
Future production, development and abandonment
costs....................................... (238,517) (215,163) (22,662)
--------- --------- ---------
Future cash flows before income taxes......... 239,785 160,422 34,390
Future income taxes........................... (47,082) (27,228) (4,747)
--------- --------- ---------
Future net cash flows......................... 192,703 133,194 29,643
10% discount factor........................... (81,798) (52,381) (11,835)
--------- --------- ---------
Standardized measure of discounted future net
cash flow................................... $ 110,905 $ 80,813 $ 17,808
========= ========= =========
Changes in standardized measure of discounted
future net cash flows:
Sales of oil, gas and natural gas liquids,
net of production costs.................. $ (10,857) $ (7,643) $ (4,194)
Extensions, discoveries and other
additions................................ 13,667 6,381 9,015
Revisions of estimates of reserves proved in
prior years:
Quantity estimated....................... 7,685 16,144 (3,070)
Net changes in price and production
costs.................................. 22,261 (6,446) (2,931)
Accretion of discount....................... 8,668 2,098 1,693
Purchases of reserves in place.............. 3,252 57,001 6,406
Sales of reserves in place.................. -- (342) (238)
Development costs incurred.................. (16,691) (977) 2,854
Changes in future development costs......... 17,167 790 (1,913)
Net change in income taxes.................. (7,725) (2,696) (2,442)
Changes in production rates (timing) and
other.................................... (7,335) (1,305) (1,162)
--------- --------- ---------
Net change.................................. $ 30,092 $ 63,005 $ 4,018
========= ========= =========
</TABLE>

Estimated future cash inflows are computed by applying year-end prices of
oil and gas to year-end quantities of proved reserves. Future price changes are
considered only to the extent provided by contractual arrangements. 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 pretax net cash flows related to proved oil and gas reserves, less the
tax basis (including net operating loss carryforwards projected to be usable) of
the properties involved.

These estimates were determined in accordance with SFAS 69. Because of
unpredictable variances in expenses and capital forecasts, crude oil and natural
gas prices and the fact that the bases for such volume estimates vary
significantly, management believes the usefulness of this data is limited. These
estimates of future net cash flows do not necessarily represent management's
assessment of estimated fair market value, future profitability or future cash
flow to the Company. Management's investment and operating decisions are

F-37
<PAGE> 103

HARCOR ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED)

based upon reserve estimates that include proved as well as probable reserves
and upon different price and cost assumptions from those used herein.

The 1993 revisions of previous estimates of oil and gas reserves reflect
the significant decrease in oil prices from 1992 to 1993 and downward
adjustments due to performance on certain properties. The purchases in place of
oil and gas reserves reflect the acquisition of a larger interest in STLP and
the acquisition of interests in additional properties in Lea County, New Mexico.
Sales in place reflect the sale of two minor properties in STLP. Extensions and
discoveries are primarily a result of drilling activity on the STLP properties
during 1993. Improved recovery was primarily the result of projected recovery
from an additional secondary recovery project in Lea County, New Mexico. The
increased production rates in 1993 reflect a full year of production from
interests acquired in 1992 and production from additional property interests
acquired during 1993.

The 1994 revisions of the purchase of reserves in place reflect the
acquisition of the property interests in the San Joaquin Basin, California. The
extension and discoveries are a result of the extension of the proved
undeveloped area of the San Joaquin Leases. The upward revisions are primarily a
result of improved performance on the San Joaquin properties which offset the
under performance of certain South Texas Properties. The sales of oil and gas
are significantly increased reflecting the production from the San Joaquin
properties purchased June 30, 1994.

The 1995 upward revision in extensions and discoveries reflects the
increased proved undeveloped area on the Ellis Lease in the San Joaquin
properties which resulted from the development drilling activity and the
drilling of a step-out well. Revisions of previous estimates of proved reserves
are largely a result of favorable gas production on the San Joaquin properties.
The net changes in prices and production costs are primarily a reflection of
higher crude oil prices at December 31, 1995, as compared to prior year. Reserve
purchases include the acquisition of interests in additional San Joaquin wells
and the acquisition of additional properties in the Permian Basin.

The future cash flows presented in the "Standardized Measures of Discounted
Future Net Cash Flows" are based on contract prices for oil and gas for
contracted volumes over the contract period, as applicable, and year-end 1995
oil and gas prices for oil and gas volumes not covered under oil and gas
contracts. (See Note 9.)

F-38
<PAGE> 104

APPENDIX A

[RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERHEAD]

March 14, 1996

HarCor Energy, Inc.
Five Post Oak Park, Suite 2220
Houston, Texas 77027-3413

Gentlemen:

The estimated reserve volumes and future income amounts presented in this
report are related to hydrocarbon prices. December 1995 hydrocarbon prices were
used in the preparation of this report as required by Securities and Exchange
Commission (SEC) and Financial Accounting Standards Bulletin No. 69 (FASB 69)
guidelines; however, actual future prices may vary significantly from December
1995 prices. Therefore, volumes of reserves actually recovered and amounts of
income actually received may differ significantly from the estimated quantities
presented in this report.

The Company's reserves are located in the states of Alabama, California,
Louisiana, Michigan, New Mexico, Oklahoma, Texas and Wyoming. Our estimates of
the net proved reserves attributable to the interests of HarCor Energy, Inc.
(referred to herein as the Company) as of December 31, 1995 are presented below:

<TABLE>
<CAPTION>
PROVED NET RESERVES
AS OF DECEMBER 31, 1995
-----------------------------
LIQUID, BARRELS GAS, MMCF
--------------- ---------
<S> <C> <C>
Developed and Undeveloped......................... 15,283,842 86,569
Developed......................................... 3,687,803 31,406
</TABLE>

The "Liquid" reserves shown above are comprised of crude oil, condensate,
and natural gas liquids. Natural gas liquids comprise 25.5 percent of the
Company's developed liquid reserves and 19.5 percent of the Company's developed
and undeveloped liquid reserves. These natural gas liquids are attributable to
the Company's ownership in the Lost Hills Gas Plant in Kern County, California.
All hydrocarbon liquid reserves are expressed in standard 42 gallon barrels. All
gas volumes are sales gas expressed in MMCF at the pressure and temperature
bases of the area where the gas reserves are located.

The proved reserves presented in this report comply with the SEC's
Regulation S-X Part 210.4-10 Sec. (a) as clarified by subsequent Commission
Staff Accounting Bulletins, and are based on the following definitions and
criteria:

Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from
known reservoirs under existing conditions. Reservoirs are considered
proved if economic producibility is supported by actual production or
formation tests. In certain instances, proved reserves are assigned on the
basis of a combination of core analysis and electrical and other type logs
which indicate the reservoirs are analogous to reservoirs in the same field
which are producing or have demonstrated the ability to produce on a
formation test. The area of a reservoir considered proved includes (1) that
portion delineated by drilling and defined by fluid contacts, if any, and
(2) the adjoining

[RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERFOOT]

A-1
<PAGE> 105

portions not yet drilled that can be reasonably judged as economically
productive on the basis of available geological and engineering data. In
the absence of data on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the
reservoir. Proved reserves are estimates of hydrocarbons to be recovered
from a given date forward. They may be revised as hydrocarbons are produced
and additional data become available. Proved natural gas reserves are
comprised of non-associated, associated, and dissolved gas. An appropriate
reduction in gas reserves has been made for the expected removal of natural
gas liquids, for lease and plant fuel, and the exclusion of non-hydrocarbon
gases if they occur in significant quantities and are removed prior to
sale. Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or
the operation of an installed program in the reservoir provides support for
the engineering analysis on which the project or program was based, and (2)
it is reasonably certain the project will proceed. Improved recovery
includes all methods for supplementing natural reservoir forces and energy,
or otherwise increasing ultimate recovery from a reservoir, including (1)
pressure maintenance, (2) cycling, and (3) secondary recovery in its
original sense. Improved recovery also includes the enhanced recovery
methods of thermal, chemical flooding, and the use of miscible and
immiscible displacement fluids. Estimates of proved reserves do not include
crude oil, natural gas, or natural gas liquids being held in underground
storage. Depending on the status of development, these proved reserves are
further subdivided into:

(i) "developed reserves" which are those proved reserves reasonably
expected to be recovered through existing wells with existing equipment
and operating methods, including (a) "developed producing reserves"
which are those proved developed reserves reasonably expected to be
produced from existing completion intervals now open for production in
existing wells, and (b) "developed non-producing reserves" which are
those proved developed reserves which exist behind the casing of
existing wells which are reasonably expected to be produced through
these wells in the predictable future where the cost of making such
hydrocarbons available for production should be relatively small
compared to the cost of a new well; and

(ii) "undeveloped reserves" which are those proved reserves
reasonably expected to be recovered from new wells on undrilled acreage,
from existing wells where a relatively large expenditure is required,
and from acreage for which an application of fluid injection or other
improved recovery technique is contemplated where the technique has been
proved effective by actual tests in the area in the same reservoir.
Reserves from undrilled acreage are limited to those drilling units
offsetting productive units that are reasonably certain of production
when drilled. Proved reserves for other undrilled units are included
only where it can be demonstrated with reasonable certainty that there
is continuity of production from the existing productive formation.

Because of the direct relationship between volumes of proved undeveloped
reserves and development plans, we include in the proved undeveloped category
only reserves assigned to undeveloped locations that we have been assured will
definitely be drilled and reserves assigned to the undeveloped portions of
secondary projects which we have been assured will definitely be developed.

The Company has interests in certain tracts which have substantial
additional hydrocarbon quantities which cannot be classified as proved and
consequently are not included herein. The Company has active exploratory and
development drilling programs which may result in the reclassification of
significant additional volumes to the proved category.

[RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERFOOT]

A-2
<PAGE> 106

Our estimates of future cash inflows, future costs, and future net cash
inflows before income tax as of December 31, 1995 from this report are presented
as follows.

<TABLE>
<CAPTION>
AS OF DECEMBER 31, 1995
-----------------------
<S> <C>
Future Cash Inflows........................... $ 476,142,034
Future Costs Production....................... $ 176,878,327
Development................................. 60,698,858
------------
Total Costs......................... $ 237,577,185
Future Net Cash Inflows
Before Income Tax........................... $ 238,564,849
Present Value at 10%
Before Income Tax........................... $ 123,534,000
</TABLE>

The future cash inflows are gross revenues before any deductions and
include $4,037,117 attributable to the Company's ownership in the Lost Hills Gas
Plant in Kern County, California, from processing third party gas. The
production costs were based on current data and include production taxes and ad
valorem taxes in addition to the operating costs directly applicable to the
individual leases or wells. The development costs were based on current data.

The Company furnished us with gas prices in effect at December 31, 1995 and
with its forecasts of future gas prices which take into account SEC guidelines,
current market prices, contract prices, and fixed and determinable price
escalations where applicable. In accordance with SEC guidelines, the future gas
prices used in this report make no allowances for future gas price increases
which may occur as a result of inflation nor do they account for seasonal
variations in gas prices which may cause future yearly average gas prices to be
different than December gas prices. For gas sold under contract, the contract
gas price including fixed and determinable escalations exclusive of inflation
adjustments, was used until the contract expires and then was adjusted to the
current market price for the area and held at this adjusted price to depletion
of the reserves.

The Company furnished us with liquid prices in effect at December 31, 1995
and these prices were held constant to depletion of the properties. In
accordance with SEC guidelines, changes in liquid prices subsequent to December
31, 1995 were not considered in this report.

Operating costs for the leases and wells in this report were based on the
operating expense reports of the Company and include only those costs directly
applicable to the leases or wells. When applicable, the operating costs include
a portion of general and administrative costs allocated directly to the leases
and wells under terms of operating agreements. Development costs were furnished
to us by the Company and are based on authorizations for expenditure for the
proposed work or actual costs for similar projects. The current operating and
development costs were held constant throughout the life of the properties. At
the request of HarCor, their estimate of zero net abandonment costs after
salvage value for onshore properties was used in this report. Ryder Scott has
not performed a detailed study of the abandonment costs nor the salvage value
and makes no warranty for HarCor's estimate. No deduction was made for indirect
costs such as general administration and overhead expenses, loan repayments,
interest expenses, and exploration and development prepayments. We have included
gas imbalances for those properties located in South Texas. No attempt was made
to quantify or otherwise account for any accumulated gas production imbalances
that may exist in any other areas.

The estimates of reserves presented herein are based upon a detailed study
of the properties in which the Company owns an interest; however, we have not
made any field examination of the properties. No consideration was given in this
report to potential environmental liabilities which may exist nor were any costs
included for potential liability to restore and clean up damages, if any, caused
by past operating practices. The Company has informed us that they have
furnished us all of the accounts, records, geological and engineering data and
reports, and other data required for this investigation. The ownership
interests, prices, and other

[RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERFOOT]

A-3
<PAGE> 107

factual data furnished by the Company were accepted without independent
verification. The estimates presented in this report are based on data available
through December 1995.

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

In general, we estimate that future gas production rates will continue to
be the same as the average rate for the latest available 12 months of actual
production until such time that the well or wells are incapable of producing at
this rate. The well or wells were then projected to decline at their decreasing
delivery capacity rate. Our general policy on estimates of future gas production
rates is adjusted when necessary to reflect actual gas market conditions in
specific cases. The future production rates from wells now on production may be
more or less than estimated because of changes in market demand or allowables
set by regulatory bodies. Wells or locations which are not currently producing
may start producing earlier or later than anticipated in our estimates of their
future production rates.

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

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

Very truly yours,

RYDER SCOTT COMPANY
PETROLEUM ENGINEERS

C. Patrick McInturff, P.E.
Petroleum Engineer

CPM/sw

Approved:

Fred W. Ziehe, P.E.
Group Vice President

[RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERFOOT]

A-4
<PAGE> 108

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

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

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Available Information................ 2
Prospectus Summary................... 3
Risk Factors......................... 12
Use of Proceeds...................... 17
Capitalization....................... 18
Price Range of Common Stock.......... 19
Dividend Policy...................... 19
Dilution............................. 20
Selected Financial Data.............. 21
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 22
Business and Properties.............. 34
Management........................... 47
Principal and Selling Stockholders... 54
Transactions with Related Parties.... 56
Description of Capital Stock and
Other Securities................... 57
Shares Eligible for Future Sale...... 60
Underwriting......................... 62
Legal Matters........................ 63
Accountants.......................... 63
Engineers............................ 63
Glossary of Oil and Gas Terms........ 64
Index to Consolidated Financial
Statements......................... F-1
Summary Report of Ryder Scott
Company............................ A-1
</TABLE>

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

6,400,000 SHARES

[HARCOR ENERGY, INC. LOGO]

HARCOR ENERGY, INC.

COMMON STOCK

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

RAUSCHER PIERCE REFSNES, INC.

PETRIE PARKMAN & CO.

SOUTHCOAST CAPITAL
CORPORATION

July 25, 1996

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