EDGE PETROLEUM CORP, S-1/A, 1997-01-15

EDGE PETROLEUM CORP
S-1/A, 1997-01-15
CRUDE PETROLEUM & NATURAL GAS

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<PAGE>

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JANUARY 15, 1997

REGISTRATION NO. 333-17267
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- -------------------------------------------------------------------------------

SECURITIES AND EXCHANGE COMMISSION

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

AMENDMENT NO. 1

TO
FORM S-1

REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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

EDGE PETROLEUM CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

DELAWARE 1311 76-0511037
(STATE OR OTHER (PRIMARY STANDARD INDUSTRIAL (I.R.S. EMPLOYER
JURISDICTION OF CLASSIFICATION CODE NUMBER) IDENTIFICATION NO.)
INCORPORATION OR
ORGANIZATION)

TEXACO HERITAGE PLAZA
1111 BAGBY, SUITE 2100
HOUSTON, TEXAS 77002
(713) 654-8960
(ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE, OF
REGISTRANT'S PRINCIPAL EXECUTIVE OFFICES)

JAMES D. CALAWAY
PRESIDENT
EDGE PETROLEUM CORPORATION
TEXACO HERITAGE PLAZA
1111 BAGBY, SUITE 2100
HOUSTON, TEXAS 77002
(713) 654-8960
(NAME, ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE,
OF AGENT FOR SERVICE)

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

COPIES TO:
GENE J. OSHMAN T. MARK KELLY
BAKER & BOTTS, L.L.P. VINSON & ELKINS L.L.P.
3000 ONE SHELL PLAZA 1001 FANNIN, SUITE 2500
HOUSTON, TEXAS 77002-4995 HOUSTON, TEXAS 77002-6760
(713) 229-1234 (713) 758-2222

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

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

If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, check the following box. [_]

If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following
box and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [_]

If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]

If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [_]

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

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<PAGE>

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

SUBJECT TO COMPLETION DATED JANUARY 15, 1997
2,000,000 SHARES
[LOGO] EDGE PETROLEUM CORPORATION
COMMON STOCK

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All the shares of Common Stock offered hereby (the "Offering") are being
issued and sold by Edge Petroleum Corporation (the "Company"). Application has
been made for inclusion of the Common Stock on the Nasdaq National Market under
the symbol "EPEX." Prior to this Offering, there has been no public market for
the Common Stock. It is currently estimated that the initial public offering
price will be between $15.00 and $17.00 per share. See "Underwriting" for
factors to be considered in determining the initial public offering price.

-----------

SEE "RISK FACTORS" BEGINNING ON PAGE 11 FOR A DISCUSSION OF CERTAIN 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.

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- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS(1) COMPANY(2)
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Per Share................................ $ $ $
- --------------------------------------------------------------------------------
Total(3)................................. $ $ $
</TABLE>
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(1) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See "Underwriting."
(2) Before deducting expenses estimated at $ , payable by the Company.
(3) The Company has granted to the Underwriters a 30-day option to purchase up
to 300,000 additional shares of Common Stock on the same terms and
conditions as the securities offered hereby solely to cover over-
allotments, if any. If the option is exercised in full, the total Price to
Public, Underwriting Discounts and Commissions and Proceeds to Company will
be $ , $ and $ , respectively. See "Underwriting."

-----------

The shares of Common Stock are offered by the several Underwriters, subject
to prior sale, when, as and if delivered to and accepted by them, and subject
to certain other conditions including the right of the Underwriters to
withdraw, cancel, modify or reject any order in whole or in part. It is
expected that delivery of the shares will be made on or about , 1997, at
the offices of Raymond James & Associates, Inc., St. Petersburg, Florida.

-----------

RAYMOND JAMES & ASSOCIATES, INC.
JEFFERIES & COMPANY, INC.
PRINCIPAL FINANCIAL SECURITIES, INC.

The date of this Prospectus is , 1997
<PAGE>

[PHOTOGRAPH]

IN CONNECTION WITH THIS 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>

PROSPECTUS SUMMARY

The following summary is qualified in its entirety by the more detailed
information and financial statements, including the notes thereto, appearing
elsewhere in this Prospectus. Unless otherwise indicated, the information in
this Prospectus (i) gives effect to the Combination Transactions (as defined
below under "--The Combination Transactions") and assumes that all interests
that are the subject of such transactions are acquired by the Company in
exchange for the issuance of approximately 4,682,000 shares of common stock,
par value $.01 per share, of the Company (the "Common Stock") and (ii) assumes
that the Underwriters' over-allotment option will not be exercised. Unless
otherwise indicated by the context, references herein to the "Company" mean
Edge Petroleum Corporation, a Delaware corporation that is the issuer of the
Common Stock offered hereby, and its corporate and partnership subsidiaries and
predecessors. Certain terms used herein relating to the oil and natural gas
industry are defined in the Glossary of Certain Industry Terms included
elsewhere in this Prospectus.

THE COMPANY

OVERVIEW

The Company explores for oil and natural gas by emphasizing the integrated
application of highly advanced data visualization techniques and computerized
3-D seismic data analysis to identify potential hydrocarbon accumulations. The
Company believes its approach to processing and analyzing geophysical data
differentiates it from other independent exploration and production companies
and is more effective than conventional 3-D seismic data interpretation
methods. The Company utilizes a fully integrated, client-server environment
including nine workstation nodes with a high performance Silicon Graphics
server. This hardware configuration enables the Company to utilize advanced
interpretation software, including both Earth Cube and Voxel Geo technology.
The Company also believes that it maintains one of the largest databases of
onshore South Texas Gulf Coast 3-D seismic data of any independent oil and gas
company, and is continuously acquiring substantial additional data within this
core region.

The Company acquires 3-D seismic data by organizing and designing regional
data acquisition surveys for its proprietary use, as well as through selective
participation in regional non-proprietary 3-D surveys. The Company negotiates
seismic options for a substantial majority of the areas encompassed by its
proprietary surveys, thereby allowing it to secure identified prospect
leasehold interests on a non-competitive, pre-arranged basis. In the Company's
non-proprietary 3-D survey areas, the Company's technical capabilities allow it
to rapidly and comprehensively evaluate large volumes of regional 3-D seismic
data, facilitating its ability to identify attractive prospects within a
surveyed region and to secure the corresponding leasehold interests ahead of
other industry participants.

The Company's extensive technical expertise has enabled it to internally
generate all of its 3-D prospects drilled to date and to assemble a large
portfolio of 3-D based drilling prospects. The Company pursues drilling
opportunities that include a blend of shallower, normally pressured reservoirs
that generally involve moderate costs and risks as well as deeper, over-
pressured reservoirs that generally involve greater costs and risks, but have
higher economic potential. The Company mitigates its exposure to exploration
costs and risk by conducting its operations with industry partners, including
major oil companies and large independents, that generally pay a
disproportionately greater share of seismic acquisition and, in many instances,
leasing and drilling costs than the Company.

The Company has experienced rapid increases in reserves, production and cash
flow since early 1995 due to the growth of its 3-D based drilling activities
and the retention of progressively larger interests in its exploration
projects. From January 1, 1995 to September 30, 1996, reserves discovered from
Company-generated prospects totaled 91.1 Bcfe, while the Company's net proved
reserves more than tripled from 5.9 Bcfe to 18.6 Bcfe at an average finding
cost to the Company of $0.51 per Mcfe. The Company drilled 13 gross (0.42 net)
wells in 1994, 35 gross (13.5 net) wells in 1995 and 34 gross (14.7 net) wells
in the nine months ended September 30, 1996. For the period from January 1,
1995 through September 30, 1996, the Company's commercial well success rate was
approximately 67% for the 69 gross (28.2 net) exploratory wells drilled (of
which 62 were based on its interpretation of 3-D seismic data).

3
<PAGE>

The Company's future growth will be driven by the drilling and development of
existing opportunities from its prospect portfolio as well as new 3-D based
prospects that are continually being identified by the Company's exploration
team. The Company has budgeted 120 gross (46.3 net) wells in 1997. The Company
currently anticipates increasing its capital expenditure budget to at least
$20.0 million in 1997 from $11.2 million in 1996. The Company believes the
proceeds of this Offering will enable it to increase the number and size of
additional 3-D seismic acquisition projects in which it participates,
accelerate its drilling activities and retain a greater share of the reserves
it discovers.

BUSINESS STRATEGY

The Company's business strategy is to expand its reserves, production and
cash flow through a disciplined, integrated technology-based program of
exploring for oil and natural gas, which emphasizes the following key
components:

FOCUSED EXPLORATION. The Company intends to maintain its exploration
focus along the onshore Gulf Coast with continued emphasis in South Texas
because of its 3-D seismic expertise in this region. The Company believes,
based on the results of its recent exploration activities, that significant
undiscovered reserves remain in this region. The Company also plans to
utilize its existing database consisting of 567 square miles of 3-D seismic
and geologic data (509 square miles of which are in South Texas) and its
knowledge of the region's producing fields and trends to further expand its
operations within this core region. The Company is currently in the process
of acquiring an additional 459 square miles of 3-D seismic data in South
Texas, which the Company believes will generate a significant number of
additional prospects in 1997 and beyond.

TECHNOLOGICAL EXPERTISE. The Company seeks to explore for and add oil and
natural gas reserves through its advanced 3-D seismic data visualization
and interpretation techniques. These techniques enable its exploration team
to analyze large amounts of 3-D seismic information and to rapidly identify
important patterns or attributes in the data which may indicate hydrocarbon
traps. The Company's technical abilities have allowed it to discover oil
and natural gas reservoirs in existing producing trends with geological
complexities that have eluded conventional interpretation. The Company
plans to continue to enhance its visualization and interpretation strengths
as new technologies and processes are developed.

SOPHISTICATED AND EXPERIENCED TECHNICAL TEAM. The Company has assembled a
team of highly talented geoscientists and other technical personnel who are
experienced in the use of advanced exploration methodologies, and it
actively seeks to identify and attract new members to its exploration team.
The Company provides its personnel with a technologically advanced work
environment, training and results-oriented compensation, including
participation in the Company's stock option plan. The Company believes that
the use of advanced technology by its technical personnel together with
increased capital resources will be critical components to implementing its
business strategy.

PROSPECTS WITH ATTRACTIVE RISK/REWARD BALANCE. The Company typically
retains all or the majority of its interests in prospects with normally
pressured and generally shallow reservoirs. Such prospects are often
located in areas with existing pipelines and production infrastructure,
which facilitate and expedite the commencement of production and cash flow.
The Company typically sells to industry partners, on a promoted basis, a
portion of its interests in prospects that involve higher costs and greater
risks, or consist of deep, over-pressured and often larger reservoirs, in
order to mitigate its exploration risk and fund the anticipated capital
requirements for the portion of those prospects it retains.

4
<PAGE>

and optioning process; determining seismic survey design; overseeing data
acquisition and processing; preparing, integrating and interpreting the
data; and identifying each prospect and drill site. The Company seeks
operator status and control over the remaining aspects of field operations
when it believes its expertise can add value to these functions.

CURRENT EXPLORATORY PROJECTS

The Company is currently evaluating 14 exploration project areas covering
approximately 1,026 square miles (656,640 acres) that are based on 3-D seismic
surveys ranging from regional non-proprietary group shoots to single field
proprietary surveys. To date, all project areas for which seismic data has been
interpreted have yielded multiple prospects and drill sites. The Company is
continuing to receive and interpret data covering these project areas and
believes that each project area has the potential for additional prospects and
drill sites. The Company's partners in these projects include, among others,
Belco Oil and Gas Corp., Carrizo Oil and Gas, Inc., Chevron Corporation,
Cheyenne Petroleum Company, IP Petroleum Company, Inc., KCS Energy, Inc.,
Pennzoil Company, Phillips Petroleum Company and Texaco Inc. For additional
information as to these project areas, see "Business--Significant Project
Areas."

1997 3-D BASED EXPLORATION PROGRAM

<TABLE>
<CAPTION>
SQUARE MILES OF GROSS ACREAGE
3-D SEISMIC DATA SCHEDULED ADDITIONAL LEASED OR
RELATING TO 1997 1997 BUDGETED TOTAL 1997 UNDER OPTION AT
PROJECT AREAS PROJECT AREA WELLS (/1/) WELLS (/2/) BUDGETED WELLS SEPTEMBER 30, 1996
- ------------- ---------------- ----------- ------------- -------------- ------------------
<S> <C> <C> <C> <C> <C>
TEXAS
Encinitas/Kelsey...... 32 6 2 8 9,110
Everest............... 340 (/3/) 8 11 19 4,888
Cameron............... 325*(/3/) * * * *
Nita/Austin........... 42 2 2 4 19,119
Spartan............... 23 5 1 6 5,855
Belco................. 114* * 41(/4/) 41(/4/) 38,476
Tyler................. 25 1 -- 1 3,750
Buckeye............... 20* * 11(/4/) 11(/4/) 12,000
Hiawatha.............. 23 2 10 12 14,985
East McFaddin......... 11 4 3 7 6,640
Triple "A"............ 13 -- 1 1 2,830
MISSISSIPPI
Tallahala Creek....... 28 4 -- 4 3,240
Quito................. 10 1 3 4 2,760
ALABAMA
Barnett............... 20 2 -- 2 578
----- --- --- --- -------
Total................... 1,026 35 85 120 124,231
===== === === === =======
</TABLE>
- --------
* 3-D seismic data is currently being acquired in the project area.
(1) Consists of identified drill sites that are fully evaluated, leased and
scheduled to be drilled during 1997.
(2) Consists of budgeted wells based upon the Company's 1997 capital budget.
The number of budgeted wells drilled could be materially affected by
drilling results of other scheduled or budgeted wells. There is less
certainty as to the drilling of these wells than with scheduled wells.
(3) Represents non-proprietary group shoots in which the Company is a
participant.
(4) Includes prospects for which 3-D seismic data is being acquired. The number
of wells indicated is based upon statistical results of drilling activities
in adjoining Company 3-D project areas that the Company believes are
geologically similar.

5
<PAGE>

Although the Company is currently pursuing each scheduled or budgeted well as
set out in the preceding table, there can be no assurance that these wells will
be drilled at all or within the expected timeframe. The final determination
with respect to the drilling of any scheduled or budgeted wells will be
dependent upon a number of factors, including (i) the results of exploration
efforts and the acquisition, review and analysis of the seismic data, (ii) the
availability of sufficient capital resources by the Company and the other
participants for the drilling of the prospects, (iii) the approval of the
prospects by other participants after additional data has been compiled, (iv)
economic and industry conditions at the time of drilling, including prevailing
and anticipated prices for oil and natural gas and the availability of drilling
rigs and crews, (v) the financial resources and results of the Company, and
(vi) the availability of leases on reasonable terms and permitting for the
prospect. There can be no assurance that any of the scheduled or budgeted wells
identified on the preceding table will, if drilled, encounter reservoirs of
commercially productive oil or natural gas. See "Risk Factors--Dependence on
Exploratory Drilling Activities," "--Reserve Replacement Risk" and "--
Uncertainty of Reserve Information and Future Net Revenue Estimates."

THE COMBINATION TRANSACTIONS

Substantially all of the operations of the Company are currently conducted
through Edge Joint Venture II (the "Joint Venture"), the interests in which are
currently owned by certain affiliates of the Company. Concurrently with this
Offering, the Company plans to acquire, directly or indirectly, substantially
all of the interests in the Joint Venture in exchange for shares of Common
Stock (the "Combination Transactions"). If the Company acquires all of the
interests that are the subject of the Combination Transactions, an aggregate of
approximately 4,682,000 shares of Common Stock will be issued in the
Combination Transactions. Although the Company is seeking to acquire all of the
interests in the Joint Venture, if any interest holders elect to retain their
current interests, the Company will not own all of the interests in the Joint
Venture. The Joint Venture was dissolved on December 31, 1996 and entered into
a two year windup period. During such period the Company will continue to
develop existing properties and identified prospect areas through the Joint
Venture. Thereafter, the Joint Venture will liquidate and distribute its assets
to the Company and any interest holders who elect to retain their current
interests. The Company will be required to allow any non-exchanging offerees in
the Combination Transactions to participate in the continued development of
certain prospects and areas of mutual interest following the distribution of
such assets. See "Certain Transactions--The Combination Transactions."

6
<PAGE>

THE OFFERING

<TABLE>
<S> <C>
Common Stock offered by the Company...... 2,000,000 shares
Common Stock to be outstanding after this
Offering................................ 6,682,000 shares(1)
Proposed Nasdaq National Market Symbol... EPEX
Use of proceeds.......................... To repay indebtedness, to provide
working capital and for general
corporate purposes, including funding
the Company's 3-D seismic data
acquisition, exploration and
development activities. See "Use of
Proceeds."
</TABLE>
- --------
(1) Assumes approximately 4,682,000 shares will be issued in connection with
the Combination Transactions. Does not include (i) 250,585 shares of Common
Stock that will be issued pursuant to restricted stock awards that will be
granted to officers of the Company concurrent with this Offering, (ii)
approximately 350,000 shares of Common Stock issuable pursuant to options
at an exercise price per share equal to the initial public offering price
that will be granted to directors, officers and employees of the Company
concurrent with this Offering and (iii) 97,844 shares of Common Stock that
may be issued pursuant to outstanding options that will be assumed by the
Company from a predecessor entity at a weighted average exercise price of
$3.06 per share. See "Management--Incentive Plans."

RISK FACTORS

Prospective purchasers of Common Stock should carefully consider all of the
information contained in this Prospectus, particularly the factors set forth
herein under "Risk Factors."

7
<PAGE>

SUMMARY HISTORICAL COMBINED FINANCIAL AND OPERATING DATA

The following table sets forth summary historical combined financial
information of the Company as of September 30, 1996, for the five years ended
December 31, 1995 and for the nine months ended September 30, 1995 (unaudited)
and 1996. The financial information presented below, as of September 30, 1996
and for the nine months ended September 30, 1995 and 1996, reflects all
adjustments, consisting of normal and recurring adjustments, that in the
opinion of management are necessary for a fair presentation of the Company's
combined results of operations and financial position for such periods. The
information shown for the nine-month periods is not necessarily indicative of
full-year results. The following table also sets forth pro forma net income
(loss) per share for the Combination Transactions. The following financial
information should be read in conjunction with "Capitalization," "Selected
Historical Combined Financial and Operating Data," "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and the audited
Combined Financial Statements and the related notes thereto included elsewhere
in this Prospectus.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------------- -------------------
1991 1992 1993 1994 1995 1995 1996
------- ------- ------- -------- ------- ----------- -------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Oil and natural gas
revenue................. $ 423 $ 572 $ 1,455 $ 1,994 $ 2,040 $ 1,377 $ 5,105
------- ------- ------- -------- ------- ------- -------
Costs and expenses:
Oil and natural gas
operating expenses.... 52 76 167 305 686 502 711
Depreciation, depletion
and amortization...... 325 467 441 593 813 525 1,213
General and
administrative........ 1,577 2,228 1,734 2,026 2,484 2,070 2,126
------- ------- ------- -------- ------- ------- -------
Total operating
expenses............ 1,954 2,771 2,342 2,924 3,983 3,097 4,050
------- ------- ------- -------- ------- ------- -------
Operating income (loss).. (1,531) (2,199) (887) (930) (1,943) (1,720) 1,055
Interest expense......... (448) (679) (635) (385) (315) (195) (657)
Gain on sale of oil and
gas property............ 115 -- 247 2,284 3,337 3,135 --
------- ------- ------- -------- ------- ------- -------
Net income (loss)........ (1,864) (2,878) (1,275) 969 1,079 1,219 398
Pro forma provision in
lieu of income taxes
(unaudited).............
------- ------- ------- -------- ------- ------- -------
Pro forma net income
(loss) (unaudited).......$(1,864).$(2,878) $(1,275) $ 969 $ 1,079 $ 1,219 $ 398
======= ======= ======= ======== ======= ======= =======
Pro forma net income
(loss) per share
(unaudited) (1)......... $ (0.40) $ (0.61) $ (0.27) $ 0.21 $ 0.23 $ 0.26 $ 0.09
======= ======= ======= ======== ======= ======= =======
Pro forma weighted
average shares
outstanding
(unaudited)............. 4,682 4,682 4,682 4,682 4,682 4,682 4,682
STATEMENT OF CASH FLOW
DATA:
Net cash (used) provided
by operating activities
........................ (743) (2,035) (1,046) (604) (927) (124) 2,822
Net cash (used) provided
by investing activities
........................ (2,184) (149) (272) 291 (1,154) 1,266 (5,651)
Net cash (used) provided
by financing activities
........................ 5,304 230 1,421 (425) 1,932 (1,281) 3,559
OTHER OPERATING DATA:
EBITDA (2)............... $(1,091) $(1,732) $ (197) $ 1,947 $ 2,207 $ 1,939 $ 2,268
Operating cash flow (3).. (1,654) (2,411) (1,080) (722) (1,445) (1,390) 1,611
Capital expenditures..... 6,597 3,823 3,660 6,809 8,512 5,407 7,881
</TABLE>

<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1996
------------------------
ACTUAL AS ADJUSTED(4)
------------ ----------------
(IN THOUSANDS)
<S> <C> <C>
BALANCE SHEET DATA:
Working capital................................ $ (1,601) $ 19,543
Property and equipment, net.................... 12,384 12,384
Total assets................................... 18,435 37,247
Long-term debt, including current maturities... 10,449 499
Equity......................................... 1,413 31,756
</TABLE>
- -------
(1) Pro forma net income (loss) per share has been computed assuming the
estimated 4,682,000 shares of Common Stock which may be issued in
connection with the Combination Transactions were outstanding since the
beginning of each period presented. See "Certain Transactions--The
Combination Transactions."

(2) EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion and amortization. Management of the Company
believes that EBITDA may provide additional information about the Company's
ability to meet its future requirements for debt service, capital
expenditures and working capital. EBITDA is a financial measure commonly
used for the Company's industry and should not be considered in isolation
or as a substitute for net income, operating income, cash flows from
operating activities or any other measure of financial performance
presented in accordance with generally accepted accounting principles or as
a measure of a company's profitability or liquidity. Because EBITDA
excludes some, but not all, items that affect net income and may vary among
companies, the EBITDA presented above may not be comparable to similarly
titled measures of other companies.

(3) Operating cash flow represents cash flows from operating activities prior
to changes in assets and liabilities. Operating cash flow is a financial
measure commonly used for the Company's industry and should not be
considered in isolation or as a substitute for net income, operating
income, cash flows from operating activities or any other measure of
financial performance presented in accordance with generally accepted
accounting principles or as a measure of a company's profitability or
liquidity because operating cash flow excludes changes in assets and
liabilities, the operating cash flow presented above may not be comparable
to similarly titled measures of other companies.
(4) Assumes the issuance in the Offering of 2,000,000 shares of Common Stock at
$16.00 per share and the application of the net proceeds therefrom. See
"Use of Proceeds."

8
<PAGE>

SUMMARY HISTORICAL COMBINED OPERATING DATA

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
---------------------------------- -----------------
1991 1992 1993 1994 1995 1995 1996
------ ------ ------ ------ ------ -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Oil and condensate
(MBbls)................ 5 5 26 61 66 47 81
Natural gas (MMcf)...... 189 273 457 588 513 337 1,557
Natural gas equivalent
(MMcfe)................ 219 303 613 954 897 619 2,043
AVERAGE SALES PRICES:
Oil and condensate ($
per Bbls).............. $18.75 $19.52 $17.52 $17.66 $16.90 $ 16.61 $ 19.49
Natural gas ($ per Mcf). 1.69 1.77 2.20 1.57 1.87 1.79 2.26
Natural gas equivalent
($ per Mcfe)........... 1.95 1.90 2.38 2.09 2.28 2.23 2.50
AVERAGE COSTS ($ PER
MCFE):
Oil and natural gas
operating expenses..... $ 0.24 $ 0.25 $ 0.27 $ 0.32 $ 0.77 $ 0.81 $ 0.35
Depreciation, depletion
and amortization....... 0.08 0.09 0.24 0.27 0.35 0.19 0.40
Oil and natural gas
operating profit....... 1.63 1.56 1.89 1.50 1.16 1.23 1.75
NUMBER OF WELLS DRILLED:
Gross................... -- 6 12 13 35 19 34
Net(1).................. -- 0.54 0.27 0.42 13.51 4.61 14.67
</TABLE>
- --------
(1) Wells in which the Company holds an after payout working interest are not
included because such interests had not been earned at the time of
drilling. The percentage of the Company's wells in which it holds solely an
after payout working interest has substantially decreased in the last two
years.

9
<PAGE>

SUMMARY OIL AND NATURAL GAS RESERVE DATA

The following table sets forth summary data with respect to the Company's
estimated historical proved oil and natural gas reserves as of the dates
indicated and the estimated future net cash flows attributable thereto. Such
estimates are prepared on a pro forma basis after giving effect to the
Combination Transactions. See "Certain Transactions--The Combination
Transactions." All information in this Prospectus relating to estimated net
proved oil and natural gas reserves and the estimated future net revenues
attributable thereto is based upon the reserve report (the "Ryder Scott
Report") prepared by Ryder Scott Company, independent petroleum engineers
("Ryder Scott"). A summary of the Ryder Scott Report as of September 30, 1996
is included as Annex A to this Prospectus. All calculations of estimated net
proved reserves have been made in accordance with the rules and regulations of
the Securities and Exchange Commission (the "Commission") and, except as
otherwise indicated, give no effect to federal or state income taxes otherwise
attributable to estimated future net revenues from the sale of oil and natural
gas. There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures, including many factors beyond the control of the
Company. See "Risk Factors--Uncertainty of Reserve Information and Future Net
Revenue Estimates" and "Business--Oil and Natural Gas Reserves."

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
----------------------
AS OF
SEPTEMBER 30,
1993 1994 1995 1996(1)
------ ------- ------- -------------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
NET PROVED RESERVES:
Oil (MBbls)............................. 170 368 709 831
Natural gas (MMcf)...................... 2,550 3,673 8,821 13,564
Total (MMcfe)........................... 3,570 5,882 13,075 18,550
NET PROVED DEVELOPED RESERVES:
Oil (MBbls)............................. 170 261 653 789
Natural gas (MMcf)...................... 2,550 3,548 6,992 10,985
Total (MMcfe)........................... 3,570 5,114 10,910 15,719
Estimated future net revenues before
income taxes............................. $7,018 $10,561 $24,463 $35,281
Present value of estimated future net
revenues before income taxes(2).......... $5,778 $ 7,946 $17,443 $25,656
Standardized measure of discounted future
net cash flows(3)........................ $5,266 $ 6,872 $13,946 $19,984
</TABLE>
- --------
(1) The prices used as of September 30, 1996 averaged $21.17 per Bbl of oil and
$2.01 per Mcf of natural gas.
(2) The present value of estimated future net revenues attributable to the
Company's reserves was prepared using constant prices as of the calculation
date, discounted at 10% per annum on a pre-tax basis.
(3) The standardized measure of discounted future net cash flows represents the
present value of estimated future net revenues after income taxes
discounted at 10% per annum.

10
<PAGE>

RISK FACTORS

Prospective purchasers of the Common Stock should carefully consider the
risk factors set forth below, as well as the other information contained in
this Prospectus. This Prospectus contains certain forward looking statements.
Actual results may differ materially from those projected in the forward-
looking statements as a result of any number of factors, including the risk
factors set forth below.

DEPENDENCE ON EXPLORATORY DRILLING ACTIVITIES

The success of the Company will be materially dependent upon the continued
success of its exploratory drilling program, which will be funded in part with
the proceeds of this Offering. Exploratory drilling involves numerous risks,
including the risk that no commercially productive natural gas or oil
reservoirs will be encountered. The cost of drilling, completing and operating
wells is often uncertain, and drilling operations may be curtailed, delayed or
cancelled as a result of a variety of factors, including unexpected drilling
conditions, pressure or irregularities in formations, equipment failures or
accidents, adverse weather conditions, compliance with governmental
requirements and shortages or delays in the availability of drilling rigs and
the delivery of equipment. Although the Company believes that its use of 3-D
seismic data and other advanced technology should increase the probability of
success of its exploratory wells and should reduce average finding costs
through elimination of prospects that might otherwise be drilled solely on the
basis of 2-D seismic data and other traditional methods, exploratory drilling
remains a speculative activity. Even when fully utilized and properly
interpreted, 3-D seismic data and visualization techniques only assist
geoscientists in identifying subsurface structures and do not allow the
interpreter to know if hydrocarbons will in fact be present in such structures
if they are drilled. In addition, the use of 3-D seismic data and such
technologies requires greater predrilling expenditures than traditional
drilling strategies and the Company could incur losses as a result of such
expenditures. The Company's future drilling activities may not be successful
and, if unsuccessful, such failure will have an adverse effect on the
Company's future results of operations and financial condition. Prospects may
initially be identified through a number of methods, some of which do not
include interpretation of 3-D or other seismic data, and in which prospects
the Company may not have any option or lease rights. Although the Company has
identified numerous drilling prospects, there can be no assurance that such
prospects will be drilled or that natural gas or oil will be produced from any
such identified prospects or any other prospects. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations."

VOLATILITY OF NATURAL GAS AND OIL PRICES

The Company's revenues, profitability, future growth and ability to borrow
funds or obtain additional capital, as well as the carrying value of its
properties, are substantially dependent upon prevailing prices of natural gas
and oil. Historically, the markets for natural gas and oil have been volatile,
and such markets are likely to continue to be volatile in the future. Prices
for natural gas and oil are subject to wide fluctuation in response to
relatively minor changes in the supply of and demand for natural gas and oil,
market uncertainty and a variety of additional factors that are beyond the
control of the Company. These factors include the level of consumer product
demand, weather conditions, domestic and foreign governmental regulations, the
price and availability of alternative fuels, political conditions in the
Middle East, the foreign supply of natural gas and oil, the price of foreign
imports and overall economic conditions. It is impossible to predict future
natural gas and oil price movements with certainty. Declines in natural gas
and oil prices may materially adversely affect the Company's financial
condition, liquidity, ability to finance planned capital expenditures and
results of operations. Lower natural gas and oil prices also may reduce the
amount of natural gas and oil that the Company can produce economically. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Business--Marketing."

The Company periodically reviews the carrying value of its oil and natural
gas properties under the full cost accounting rules of the Commission. Under
these rules, capitalized costs of proved oil and natural gas properties may
not exceed the present value of estimated future net revenues from proved
reserves, discounted at 10%. Application of this "ceiling" test generally
requires pricing future revenue at the unescalated prices in

11
<PAGE>

effect as of the end of each fiscal quarter and requires a write down for
accounting purposes if the ceiling is exceeded, even if prices declined for
only a short period of time. The Company may be required to write down the
carrying value of its oil and natural gas properties when oil and natural gas
prices are depressed or unusually volatile. If a write down is required, it
would result in a charge to earnings and would not impact cash flow from
operating activities.

In order to reduce its exposure to short-term fluctuations in the price of
natural gas, the Company periodically enters into hedging arrangements. The
Company's hedging arrangements apply to only a portion of its production and
provide only partial price protection against declines in natural gas prices.
Such hedging arrangements may expose the Company to risk of financial loss in
certain circumstances, including instances where production is less than
expected, the Company's customers fail to purchase contracted quantities of oil
or natural gas or a sudden, unexpected event materially impacts oil or natural
gas prices. In addition, the Company's hedging arrangements limit the benefit
to the Company of increases in the price of natural gas. Total Mcfs of natural
gas purchased and sold under swap arrangements during the nine month period
ended September 30, 1996 and the year ended December 31, 1995 were 182,000 Mcf
and 62,000 Mcf, respectively. Gains and losses realized by the Joint Venture
under such swap arrangements were $5,270 and $(15,720) for the nine month
period ended September 30, 1996 and the year ended December 31, 1995,
respectively. There was no hedging activity in 1994 or 1993. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
General" and "Business--Marketing."

RESERVE REPLACEMENT RISK

In general, the volume of production from natural gas and oil properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent the Company acquires properties
containing proved reserves or conducts successful exploration and development
activities, or both, the proved reserves of the Company will decline as
reserves are produced. The Company's future natural gas and oil production is,
therefore, highly dependent upon its level of success in finding or acquiring
additional reserves. The business of exploring for, developing or acquiring
reserves is capital-intensive. To the extent cash flow from operations is
reduced and external sources of capital become limited or unavailable, the
Company's ability to make the necessary capital investment to maintain or
expand its asset base of natural gas and oil reserves would be impaired. As of
September 30, 1996, the Company had participated in a substantial percentage of
its wells as non-operator pursuant to various agreements. The failure of an
operator of the Company's wells to adequately perform operations, or such
operator's breach of the applicable agreements, could adversely impact the
Company. In addition, there can be no assurance that the Company's future
exploration, development and acquisition activities will result in additional
proved reserves or that the Company will be able to drill productive wells at
acceptable costs. See "Management's Discussion of Analysis and Financial
Condition and Results of Operation."

OPERATING RISKS OF NATURAL GAS AND OIL OPERATIONS

The natural gas and oil business involves certain operating hazards such as
well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas
or well fluids, fires, formations with abnormal pressures, pollution, releases
of toxic gas and other environmental hazards and risks, any of which could
result in substantial losses to the Company. The availability of a ready market
for the Company's natural gas and oil production also depends on the proximity
of reserves to, and the capacity of, natural gas and oil gathering systems,
pipelines and trucking or terminal facilities. In addition, the Company may be
liable for environmental damages caused by previous owners of property
purchased and leased by the Company. As a result, substantial liabilities to
third parties or governmental entities may be incurred, the payment of which
could reduce or eliminate the funds available for exploration, development or
acquisitions or result in the loss of the Company's properties. In accordance
with customary industry practices, the Company maintains insurance against
some, but not all, of such risks and losses. The Company does not carry
business interruption insurance. The occurrence of an event not fully covered
by insurance could have a material adverse effect on the financial condition
and results of operations of the Company. See "Business--Operating Hazards and
Insurance."

DEPENDENCE ON KEY PERSONNEL

The Company depends to a large extent on the services of certain key
management personnel, the loss of any of which could have a material adverse
effect on the Company's operations. The Company will enter into

12
<PAGE>

employment agreements with each of Mr. John E. Calaway (the Company's Chief
Executive Officer and Chairman of the Board), Mr. James D. Calaway (the
Company's President) and Mr. Michael G. Long (the Company's Chief Financial
Officer) described herein under "Management--Employment Agreements" prior to
this Offering. The Company does not maintain key-man life insurance with
respect to any of its employees. The Company believes that its success is also
dependent upon its ability to continue to employ and retain skilled technical
personnel. See "Business--Exploration Technology."

RELIANCE ON TECHNOLOGICAL DEVELOPMENT AND POSSIBLE TECHNOLOGICAL OBSOLESCENCE

The Company's business is dependent upon utilization of changing technology.
As a result, the Company's ability to adapt to evolving technologies, obtain
new products and maintain technological advantages will be important to its
future success. The Company believes that its ability to utilize state of the
art technologies currently gives it an advantage over many of its competitors.
This advantage, however, is based in part upon technologies developed by
others, and the Company may not be able to maintain this advantage. As new
technologies develop, the Company may be placed at a competitive disadvantage,
and competitive pressures may force the Company to implement such new
technologies at substantial cost. There can be no assurance that the Company
will be able to successfully utilize, or expend the financial resources
necessary to acquire, new technology, that others will not either achieve
technological expertise comparable to or exceeding that of the Company or that
others will not implement new technologies before the Company. One or more of
the technologies currently utilized by the Company or implemented in the
future may become obsolete. In such case, the Company's business, financial
condition and results of operations could be materially adversely affected. If
the Company is unable to utilize the most advanced commercially available
technology, the Company's business, financial condition and results of
operations could be materially and adversely affected. See "Business--
Exploration Technology."

SIGNIFICANT CAPITAL REQUIREMENTS

Due to its active exploration and development and technology development
programs, the Company has experienced and expects to continue to experience
substantial working capital needs. While the Company believes that the net
proceeds from this Offering, cash flow from operations and its existing credit
arrangements should allow the Company to successfully implement its present
business strategy, additional financing may be required in the future to fund
the Company's growth and developmental and exploratory drilling and continued
technological development. No assurances can be given as to the availability
or terms of any such additional financing that may be required or that
financing will continue to be available under the existing or new credit
facilities. In the event such capital resources are not available to the
Company, its drilling and other activities may be curtailed. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Liquidity and Capital Resources."

CERTAIN POTENTIAL CONFLICTS OF INTEREST AND EFFECTS OF THE COMBINATION
TRANSACTIONS

Upon the consummation of the Combination Transactions and this Offering, the
Company will continue as managing partner of the Joint Venture and will become
the general partner of certain limited partnerships currently holding
interests in the Joint Venture. In addition, while the Joint Venture was
dissolved on December 31, 1996 and will generally be liquidated over the next
two years, substantially all of the existing operations and assets of the
Company and the Revolving Credit Facility will remain at the Joint Venture
level during the wind-up phase and such facility will be available only to
fund such operations. In the event that any holders of interests that are the
subject of the Combination Transactions elect to retain such interests, the
Company will not own all of the interests in the Joint Venture. The Company
will have certain duties to any partners of such limited partners that do not
exchange their limited partner interests for shares of Common Stock and
certain conflicts of interest could arise between the Company and such non-
exchanging partners. In addition, if certain holders elect to exercise
dissenters rights in a merger in the Combination Transactions, the Company
will be required to utilize cash resources (which may include a portion of the
proceeds of this Offering) to make payments to such holders.

13
<PAGE>

CONTROL BY CERTAIN STOCKHOLDERS

Upon completion of this Offering and the Combination Transactions, members
of the Company's board of directors and their affiliates will own
approximately 39% (38% if the Underwriters' over-allotment option is exercised
in full) of the outstanding shares of Common Stock (assuming an initial public
offering price of $16.00 per share). As a result, such stockholders will be
able to significantly influence and possibly control the outcome of certain
matters requiring a stockholder vote, including the election of directors.
Such ownership of Common Stock may have the effect of delaying, deferring or
preventing a change of control of the Company and may adversely affect the
voting and other rights of other stockholders. See "Security Ownership of
Certain Beneficial Owners and Management."

BENEFITS OF THIS OFFERING TO PARTICIPANTS IN THE COMBINATION TRANSACTIONS

This Offering will provide certain benefits to the persons who will acquire
Common Stock in the Combination Transactions, including the Company's officers
and directors and their affiliates. These benefits will include liquidity
(including, in the case of Mr. Sfondrini, margin loan arrangements) for their
respective investments resulting from the exchange of their current interests
for shares of Common Stock and the creation of a public market for the Common
Stock. In addition, the exchange of such interests for shares of Common Stock
will result in the realization of potential gains by such persons in the value
of their investments, based upon the difference between the amount of such
investments and the aggregate value of their shares of Common Stock. Mr. John
Sfondrini will receive in respect of his general partner interest in Edge
Group II Limited Partnership ("Edge Group II"), shares for both accrued, but
unpaid management fees as well as shares in respect of future management fees.
A portion of such shares and Mr. Sfondrini's margin loan proceeds are expected
to be paid to the parents of the Chief Executive Officer and the President of
the Company pursuant to certain prior arrangements. A portion of the proceeds
of this Offering will be used to repay approximately $1.3 million of
indebtedness of the Company owed to Mr. James C. Calaway, the father of both
the Company's Chief Executive Officer and its President, and 21,669 shares of
Common Stock (assuming an initial public offering price of $16.00 per share)
will be issued to Mr. James C. Calaway in exchange for certain interests in
properties and prospects of the Joint Venture. As a general partner of Edge
Group II, Mr. Sfondrini is personally liable for its obligations. Upon
consummation of the Combination Transactions, Mr. Sfondrini will not be liable
for any future obligations of Edge Group II.

The Company has agreed to indemnify the general partners, certain affiliates
and the directors and officers of the partners to the Joint Venture against
certain losses, damages and liabilities arising out of the Combination
Transactions. See "Certain Transactions--The Combination Transactions" and "--
Transfer of Edge Group II General Partner Interests."

GOVERNMENT REGULATION AND ENVIRONMENTAL MATTERS

Oil and natural gas operations are subject to various federal, state and
local government regulations which may be changed from time to time in
response to economic or political conditions. Matters subject to regulation
include discharge permits for drilling operations, drilling bonds, reports
concerning operations, the spacing of wells, unitization and pooling of
properties and taxation. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow
of oil and natural gas wells below actual production capacity in order to
conserve supplies of oil and natural gas. In addition, the development,
production, handling, storage, transportation and disposal of oil and natural
gas, by-products thereof and other substances and materials produced or used
in connection with oil and natural gas operations are subject to regulation
under federal, state and local laws and regulations primarily relating to
protection of human health and the environment. The Company is also subject to
changing and extensive tax laws, the effects of which cannot be predicted. The
Company believes that it is in substantial compliance with applicable
regulations, although there can be no assurance that this is or will remain
the case. The implementation of new, or the modification of existing, laws or
regulations could have a material adverse effect on the Company. See
"Business--Regulation."

14
<PAGE>

ABILITY TO MANAGE GROWTH AND ACHIEVE BUSINESS STRATEGY

The Company has experienced significant growth in the recent past through
the expansion of its drilling program. The Company's rapid growth has placed,
and is expected to continue to place, a significant strain on the Company's
financial, technical, operational and administrative resources. As the Company
enlarges the number of projects it is evaluating or in which it is
participating, there will be additional demands on the Company's financial,
technical and administrative resources. The Company's ability to continue its
growth will depend upon a number of factors, including its ability to identify
and acquire new exploratory sites, its ability to develop existing sites, its
ability to continue to retain and attract skilled personnel, the results of
its drilling program, hydrocarbon prices, access to capital and other factors.
There can be no assurance that the Company will be successful in achieving
growth or any other aspect of its business strategy.

COMPETITION

The Company encounters competition from other oil and natural gas companies
in all areas of its operations, including the acquisition of exploratory
prospects and proven properties. The Company's competitors include major
integrated oil and natural gas companies and numerous independent oil and
natural gas companies, individuals and drilling and income programs. Many of
its competitors are large, well-established companies with substantially
larger operating staffs and greater capital resources than the Company's and
which, in many instances, have been engaged in the oil and natural gas
business for a much longer time than the Company. Such companies may be able
to pay more for exploratory prospects and productive natural gas and oil
properties and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than the Company's financial or human
resources permit. In addition, such companies may be able to expend greater
resources on the existing and changing technologies that the Company believes
are and will be increasingly important to the current and future success of
oil and natural gas companies. The Company's ability to explore for oil and
natural gas prospects and to acquire additional properties in the future will
be dependent upon its ability to conduct its operations, to evaluate and
select suitable properties and to consummate transactions in this highly
competitive environment. See "Business--Competition."

UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES

There are numerous uncertainties inherent in estimating natural gas and oil
reserves and their estimated values, including many factors beyond the control
of the producer. The reserve data set forth in this Prospectus represent only
estimates. Reservoir engineering is a subjective process of estimating
underground accumulations of natural gas and oil that cannot be measured in an
exact manner. Estimates of economically recoverable natural gas and oil
reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions concerning future natural
gas and oil prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, all of which may in fact
vary considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of natural gas and oil attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom
prepared by different engineers or by the same engineers but at different
times may vary substantially and such reserve estimates may be subject to
downward or upward adjustment based upon such factors. Actual production,
revenues and expenditures with respect to the Company's reserves will likely
vary from estimates, and such variances may be material. In addition, the 10%
discount factor, which is required by the Commission to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily
the most appropriate discount factor based on interest rates in effect from
time to time and risks associated with the Company or the oil and natural gas
industry in general. See "Business--Oil and Natural Gas Reserves."

ACQUISITION RISKS

The Company generally seeks to explore for oil and natural gas rather than
to purchase producing properties. As a result, the Company's experience in the
acquisition of such properties is limited. The successful acquisition

15
<PAGE>

of producing properties requires an assessment of recoverable reserves, future
oil and natural gas prices, operating costs, potential environmental and other
liabilities and other factors. Such assessments are necessarily inexact and
their accuracy inherently uncertain. In connection with such an assessment,
the Company performs a review of the subject properties that it believes to be
generally consistent with industry practices, which generally includes on-site
inspections and the review of reports filed with various regulatory entities.
Such a review, however, will not reveal all existing or potential problems nor
will it permit a buyer to become sufficiently familiar with the properties to
fully assess their deficiencies and capabilities. Inspections may not always
be performed on every well, and structural and environmental problems are not
necessarily observable even when an inspection is undertaken. Even when
problems are identified, the seller may be unwilling or unable to provide
effective contractual protection against all or part of such problems. There
can be no assurances that any acquisition of property interests by the Company
will be successful and, if unsuccessful, that such failure will not have an
adverse effect on the Company's future results of operations and financial
condition.

SHARES ELIGIBLE FOR FUTURE SALE

The holders of substantially all of the shares of Common Stock issued in the
Combination Transactions will be restricted by the Company's Bylaws from
disposing of such shares for a period of 180 days from the date of this
Prospectus without the prior consent of the representatives of the
Underwriters and the Company. Such consent may be given at any time and
without public notice. The investors receiving such shares in the Combination
Transaction have previously had no significant source of liquidity for their
investment. After such period, substantially all of the approximately
4,682,000 shares of Common Stock issued in the Combination Transactions will
be eligible for resale without restriction, except for sales by affiliates
which will be subject to the volume restrictions of Rule 144. In addition,
97,844 shares of Common Stock may be issued pursuant to currently outstanding
options that will be assumed by the Company from a predecessor at a weighted
average exercise price of $3.06 per share, 350,000 shares of Common Stock may
be issued pursuant to options that will be issued under the Company's
incentive plan concurrent with this Offering at an exercise price equal to the
initial public offering price in this Offering and 250,585 shares of Common
Stock will be issued pursuant to restricted stock awards granted under the
Company's incentive plan concurrent with this Offering. Future sales of
substantial amounts of Common Stock in the public market following this
Offering could adversely affect the market price of the Common Stock. For
further information concerning Common Stock available for resale after this
Offering, see "Shares Eligible for Future Sale."

ABSENCE OF DIVIDENDS ON COMMON STOCK

The Company currently intends to retain any earnings for the future
operation and development of its business and does not currently anticipate
paying any dividends in the foreseeable future. Any future dividends also may
be restricted by the Company's then-existing loan agreements. See "Dividend
Policy," "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources" and Note 3 to the
Company's Combined Financial Statements.

RECENT LOSSES

The Company has incurred net losses in three of the last five years of its
operations. There can be no assurance that the Company will be profitable in
the future. See "Selected Historical Combined Financial and Operating Data."

CERTAIN ANTI-TAKEOVER PROVISIONS

The Company's Certificate of Incorporation and Bylaws and the Delaware
General Corporation Law contain provisions that may have the effect of
delaying, deferring or preventing a change of control of the Company. These
provisions, among other things, provide for a classified Board of Directors
with staggered terms, restrict the ability of stockholders to take action by
written consent and authorize the Board of Directors to set the terms of
Preferred Stock. See "Description of Capital Stock."

16
<PAGE>

NO PRIOR PUBLIC MARKET

Prior to this Offering, there has been no public market for the Common
Stock. The initial public offering price will be determined by negotiation
between the Company and the Underwriters and may not be indicative of the
price at which the Common Stock will trade following the completion of this
Offering. See "Underwriting" for a discussion of the factors to be considered
in determining the initial public offering price. The completion of this
Offering provides no assurance that an active trading market for the Common
Stock will develop or, if developed, that it will be sustained. The market
price of the Common Stock could also be subject to significant fluctuation and
may be influenced by many factors, including variations in results of
operations, variations in natural gas and oil prices, investor perceptions of
the Company and the oil and natural gas industry and general economic and
other conditions.

DILUTION

Purchasers of Common Stock in this Offering will experience immediate and
substantial dilution in the net tangible book value of their stock of $11.25
per share (assuming an initial public offering price of $16.00 per share). See
"Dilution."

17
<PAGE>

USE OF PROCEEDS

The net proceeds to the Company from this Offering at an assumed initial
public offering price of $16.00 per share are estimated to be approximately
$29.0 million ($33.5 million if the Underwriters' over-allotment option is
exercised in full). The Company intends to use a portion of the net proceeds
to lend funds to the Joint Venture to be used to repay approximately $8.6
million of indebtedness incurred under the Revolving Credit Facility that
currently bears interest at 8% and matures on June 1, 1998 and to repay
approximately $1.3 million of subordinated indebtedness to Mr. James C.
Calaway that currently bears interest at 10% and matures on April 8, 1998. The
remainder of the net proceeds will be used to provide working capital to the
Company and for general corporate purposes, including funding the Company's
exploration, development and acquisition activities. Following application of
the proceeds of this Offering, the Company anticipates that its only long-term
indebtedness will consist of an aggregate of approximately $441,000 principal
amount of equipment loans. The indebtedness incurred under the Revolving
Credit Facility and the indebtedness to Mr. James C. Calaway was used
primarily for the Company's exploration, development and acquisition
activities and to provide working capital. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations."

DIVIDEND POLICY

The Company has not paid any dividends in the past and does not intend to
pay cash dividends on its Common Stock in the foreseeable future. The Company
currently intends to retain any earnings for the future operation and
development of its business, including exploration, development and
acquisition activities. Any future dividends also may be restricted by the
Company's then-existing loan agreements. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources."

18
<PAGE>

DILUTION

As of September 30, 1996, the pro forma net tangible book value of the
Company would have been approximately $2.7 million, or approximately $0.59 per
share of Common Stock, after giving pro forma effect to the issuance of
approximately 4,682,000 shares of Common Stock in connection with the
Combination Transactions as if such transactions had been completed at such
date. Net tangible book value per share represents the amount of the Company's
tangible book value (total book value of tangible assets less total
liabilities) divided by the total number of shares of Common Stock
outstanding. After further giving effect to the receipt of the estimated net
proceeds from this Offering (net of estimated underwriting discounts and
commissions and Offering expenses) at an assumed initial public offering price
of $16.00 per share, the adjusted pro forma net tangible book value of the
Common Stock outstanding at September 30, 1996 would have been $4.75 per
share, representing an immediate increase in net tangible book value of $4.16
per share to stockholders receiving Common Stock in the Combination
Transactions and an immediate dilution of $11.25 per share (the difference
between the assumed initial public offering price and the net tangible book
value per share after this Offering) to persons purchasing Common Stock at the
assumed initial public offering price. The following table illustrates such
per share dilution:

<TABLE>
<S> <C> <C>
Assumed initial public offering price per share................ $16.00
Pro forma net tangible book value per share before this
Offering.................................................... $0.59
Increase in pro forma net tangible book value per share
attributable to sale of Common Stock in this Offering....... 4.16
-----
Adjusted pro forma net tangible book value per share after
giving effect to this Offering................................ 4.75
------
Dilution in net tangible book value to the purchasers of Common
Stock in this Offering........................................ $11.25
======
</TABLE>

The following table sets forth, on a pro forma basis as of September 30,
1996, differences between (i) the number of shares of Common Stock to be
acquired from the Company by holders of interests in predecessor entities and
by investors purchasing shares in this Offering, (ii) the combined equity of
the predecessor entities adjusted to give effect to the Combination
Transactions and the related per share amount of Common Stock to be exchanged
pursuant to the Combination Transactions and (iii) the total price and the
average price per share paid or to be paid by investors purchasing shares in
this Offering (based upon an assumed initial public offering price per share
of $16.00).

<TABLE>
<CAPTION>
SHARES PURCHASED(2) TOTAL CONSIDERATION
--------------------------------------------
AVERAGE PRICE
NUMBER PERCENT AMOUNT PERCENT PER SHARE
----------- --------------------- ------- -------------
<S> <C> <C> <C> <C> <C>
Stockholders receiving
shares in the
Combination
Transactions(1)........ 4,682,000 70.1% $ 2,745,957(3) 7.9% $0.59
New investors........... 2,000,000 29.9% 32,000,000 92.1% 16.00
----------- ------- ----------- -----
Total................. 6,682,000 100.0% $34,745,957 100.0%
=========== ======= =========== =====
</TABLE>
- --------
(1) The existing investors in the Company, after giving effect to the
Combination Transactions, will have acquired all of their shares of Common
Stock in exchange for the assets acquired by the Company in the
Combination Transactions.

(2) Does not include (i) 250,585 shares of Common Stock that will be issued
pursuant to restricted stock awards that will be granted to officers of
the Company upon completion of this Offering, (ii) approximately 350,000
shares of Common Stock issuable pursuant to options at an exercise price
per share equal to the initial public offering price that will be granted
to directors, officers and employees of the Company upon completion of
this Offering and (iii) 97,844 shares of Common Stock that may be issued
pursuant to outstanding options that will be assumed by the Company from a
predecessor entity at a weighted average exercise price of $3.06 per
share. The exercise of such stock options will be dilutive to the
interests of new investors. See "Management--Incentive Plans."

(3) Total consideration for the shares received in the Combination
Transactions represents the book value at September 30, 1996 of the net
assets and liabilities contributed by the interest holders of the combined
predecessor entities. The assets and liabilities contributed by the
interest holders were recorded at historical cost rather than fair market
value by the Company in accordance with generally accepted accounting
principles.

19
<PAGE>

CAPITALIZATION

The following table sets forth (i) the historical combined capitalization of
the Company as of September 30, 1996, (ii) the pro forma capitalization of the
Company as of September 30, 1996 after giving effect to the issuance of
approximately 4,682,000 shares of Common Stock in connection with the
Combination Transactions and (iii) the pro forma capitalization of the Company
as of September 30, 1996 as adjusted to give effect to the sale of 2,000,000
shares of Common Stock in this Offering at an assumed initial public offering
price of $16.00 per share and the application of the estimated net proceeds
therefrom. This table should be read in conjunction with the Combined
Financial Statements and notes thereto and "Management's Discussion and
Analysis of Financial Condition and Results of Operations" included elsewhere
in this Prospectus.

<TABLE>
<CAPTION>
SEPTEMBER 30, 1996
----------------------------------
PRO FORMA
HISTORICAL FOR PRO FORMA
COMBINED COMBINATION AS ADJUSTED
---------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash and cash equivalents................... $ 930 $ 931 $20,492
======= ======= =======
Current portion of long-term debt........... 316 316 316
======= ======= =======
Long-term debt.............................. 10,133 10,133 183
Stockholders' equity(1):
Preferred stock, $0.01 par value,
10,000,000
shares authorized; none outstanding...... -- -- --
Common stock, $0.01 par value, 40,000,000
shares authorized; 4,682,000 shares
issued
and outstanding pro forma; 6,682,000
shares issued and outstanding pro forma
as adjusted.............................. -- 47 67
Additional paid in capital................ -- 2,699 31,689
Retained earnings......................... -- -- --
Combined equity........................... 1,413 -- --
------- ------- -------
Total stockholders' equity.................. 1,413 2,746 31,756
------- ------- -------
Total capitalization........................ $11,546 $12,879 $31,939
======= ======= =======
</TABLE>
- --------
(1) Does not include (i) 250,585 shares of Common Stock that will be issued
pursuant to restricted stock awards that will be granted to officers of
the Company upon completion of this Offering, (ii) approximately 350,000
shares of Common Stock issuable pursuant to options at an exercise price
per share equal to the initial public offering price that will be granted
to directors, officers and employees of the Company upon completion of
this Offering and (iii) 97,844 shares of Common Stock that may be issued
pursuant to outstanding options that will be assumed by the Company from a
predecessor entity at a weighted average exercise price of $3.06 per
share.

20
<PAGE>

SELECTED HISTORICAL COMBINED FINANCIAL AND OPERATING DATA

The following table sets forth selected historical combined financial
information of the Company as of September 30, 1996, for the five years ended
December 31, 1995 and for the nine months ended September 30, 1995 (unaudited)
and 1996. The financial information presented below, as of September 30, 1996
and for the nine months ended September 30, 1995 and 1996, reflects all
adjustments, consisting of normal and recurring adjustments, that in the
opinion of management are necessary for a fair presentation of the Company's
combined results of operations and financial position for such periods. The
information shown for the nine-month periods is not necessarily indicative of
full-year results. The following table also sets forth pro forma net income
(loss) per share for the Combination Transactions. The following financial
information should be read in conjunction with "Capitalization," "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
the audited Combined Financial Statements and the related notes thereto
included elsewhere in this Prospectus.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------------------------- ------------------
1991 1992 1993 1994 1995 1995 1996
------- ------- ------- ------ ------ ----------- ------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS
DATA:
Oil and natural gas
revenue............... $ 423 $ 572 $ 1,455 $1,994 $2,040 $ 1,377 $5,105
------- ------- ------- ------ ------ ------- ------
Costs and expenses:
Oil and natural gas
operating expenses.. 52 76 167 305 686 502 711
Depreciation,
depletion and
amortization........ 325 467 441 593 813 525 1,213
General and
administrative...... 1,577 2,228 1,734 2,026 2,484 2,070 2,126
------- ------- ------- ------ ------ ------- ------
Total operating
expenses.......... 1,954 2,771 2,342 2,924 3,983 3,097 4,050
------- ------- ------- ------ ------ ------- ------
Operating income
(loss)................ (1,531) (2,199) (887) (930) (1,943) (1,720) 1,055
Interest expense....... (448) (679) (635) (385) (315) (195) (657)
Gain on sale of oil
and gas property...... 115 -- 247 2,284 3,337 3,134 --
------- ------- ------- ------ ------ ------- ------
Net income (loss)
before taxes.......... (1,864) (2,878) (1,275) 969 1,079 1,219 398
Pro forma provision in
lieu of income taxes
(unaudited)........... -- -- -- -- -- -- --
Pro forma net income
(loss) (unaudited).... -- -- -- -- -- -- --
------- ------- ------- ------ ------ ------- ------
$(1,864) $(2,878) $(1,275) $ 969 $1,079 $ 1,219 $ 398
======= ======= ======= ====== ====== ======= ======
Pro forma net income
(loss) per share
(unaudited) (1)....... $ (0.40) $ (0.61) $ (0.27) $ 0.21 $ 0.23 $ 0.26 $ 0.09
======= ======= ======= ====== ====== ======= ======
Pro forma weighted
average shares
outstanding
(unaudited)........... 4,682 4,682 4,682 4,682 4,682 4,682 4,682
STATEMENTS OF CASH FLOWS
DATA:
Net cash (used)
provided by operating
activities............ (734) (2,035) (1,046) (604) (927) (124) 2,822
Net cash (used)
provided by investing
activities............ (2,184) (149) (272) 291 (1,154) 1,266 (5,651)
Net cash (used)
provided by financing
activities............ 5,304 230 1,421 (425) 1,933 (1,281) 3,559
OTHER OPERATING DATA:
EBITDA (2)............. $(1,091) $(1,732) $ (197) $1,947 $2,207 $ 1,939 $2,268
Operating cash flow
(3)................... (1,654) (2,411) (1,080) (722) (1,445) (1,390) 1,611
Capital expenditures... 6,597 3,823 3,660 6,809 8,512 5,407 7,881
</TABLE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------------
AS OF
SEPTEMBER 30,
1991 1992 1993 1994 1995 1996
------ ------ ------ ------ ------ -------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital........... $4,099 $1,205 $ (862) $ (973) $ (947) $ (1,601)
Property and equipment,
net...................... 2,724 2,475 2,622 4,136 7,911 12,384
Total assets.............. 9,666 6,388 5,190 6,128 9,858 18,435
Long-term debt, including
current maturities....... 4,597 4,627 4,240 4,177 6,124 10,449
Equity (deficit).......... 3,162 285 (991) (34) 1,031 1,413
</TABLE>
- --------
(1) Pro forma net income (loss) per share has been computed assuming the
estimated 4,682,000 shares of Common Stock which may be issued in
connection with the Combination Transactions were outstanding since the
beginning of each period presented. See "Certain Transactions--The
Combination Transactions."

(2) EBITDA represents earnings before interest expense, income taxes,
depreciation, depletion and amortization. Management of the Company
believes that EBITDA may provide additional information about the
Company's ability to meet its future requirements for debt service,
capital expenditures and working capital. EBITDA is a financial measure
commonly used for the Company's industry and should not be considered in
isolation or as a substitute for net income, operating income, cash flows
from operating activities or any other measure of financial performance
presented in accordance with generally accepted accounting principles or
as a measure of a company's profitability or liquidity. Because EBITDA
excludes some, but not all, items that affect net income and may vary
among companies, the EBITDA presented above may not be comparable to
similarly titled measures of other companies.

21
<PAGE>

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

THE COMPANY

GENERAL OVERVIEW

The Company began operations in 1983 and until 1992 generated exploratory
drilling prospects based on 2-D seismic data for sale to other exploration and
production companies. During 1992, as a result of the advent of economic
onshore 3-D seismic surveys and the improvement and increased affordability of
data interpretation technologies, the Company changed its exploration strategy
to emphasize the acquisition of 3-D seismic data covering certain of its
existing 2-D based project areas. From 1992 to 1995, the Company reduced its
inventory of 2-D based prospects, began limited drilling for its own account
of certain existing 2-D based prospects and began developing prospects based
on 3-D seismic data. Since early 1995, the Company has almost exclusively
drilled prospects generated from 3-D seismic data, while accelerating its
drilling activity and increasing its working interests in new project areas.
This shift in the Company's business strategy is reflected in a number of
changes in the Company's financial results. A majority of the income in 1994
and 1995 was attributable to gains on sales of unproved oil and gas
properties. The Company expects in the future to retain and develop a majority
of its oil and gas properties. Similarly, the Company expects depreciation,
depletion and amortization and oil and gas operating expenses will continue to
increase. The Company expects to continue retaining all or the majority of its
interests in prospects with normally pressured and generally shallow
reservoirs and selling a portion of its interests in deeper over-pressured 3-D
seismic prospects, which generally require greater capital expenditures, to
industry participants in order to fund the capital expenditures for the
interests it retains.

The Company uses the full-cost method of accounting for its oil and gas
properties. Under this method, all acquisition, exploration and development
costs, including certain general and administrative costs that are directly
attributable to the Company's acquisition, exploration and development
activities, are capitalized in a "full-cost pool" as incurred. The Company
records depletion of its full-cost pool using the unit of production method.
To the extent that such capitalized costs in the full cost pool (net of
depreciation, depletion and amortization and related deferred taxes) exceed
the present value (using a 10% discount rate) of estimated future net after-
tax cash flows from proved oil and gas reserves, such excess costs are charged
to operations. Once incurred, a write-down of oil and gas properties is not
reversible at a later date.

During 1991, the Joint Venture was formed by Edge Petroleum Corporation, a
Texas corporation ("Old Edge"), Edge Group II, Gulfedge Limited Partnership
("Gulfedge") and Edge Group Partnership ("Edge Group") to conduct the business
of a predecessor partnership. The Joint Venture purchased approximately $5.2
million in net assets (on a historical financial statement basis) and assumed
substantially all of the liabilities of the predecessor, which had been
engaged in oil and gas exploration and production operations since 1983. A
substantial portion of the annual cash flows generated by the predecessor
partnership had been distributed to its partners resulting in a low level of
equity accumulation prior to the formation of the Joint Venture.

Edge Group II, Gulfedge and Edge Group were not required to pay federal
income taxes due to their status as partnerships, which are "pass through"
entities that are not subject to federal income taxation. Instead, taxes
relating to the Joint Venture interests for such periods were paid by the
partners of such entities. Old Edge was required to pay such taxes on its
share of Joint Venture income. Accordingly, the Combined Financial Statements
of the Company set forth elsewhere in this Joint Proxy and Consent
Solicitation Statement/Prospectus are prepared on the basis of a combination
of the Joint Venture, Old Edge, Edge Group II and Gulfedge. Upon the
consummation of the Combination Transactions, the Company will be required to
record its deferred taxes, if any, in accordance with SFAS No. 109,
"Accounting for Income Taxes." If the Combination Transactions had been
consummated at September 30, 1996 a deferred tax asset of approximately $1.2
million would have been available for future use to offset future tax
liabilities of the Company subject to any limitations imposed by the
Combination Transactions. The ultimate amount of the deferred tax asset and
its future utilization is dependent upon a number of factors and cannot be
determined until consummation of the Combination Transactions.

22
<PAGE>

The Company's revenues, profitability, future growth and ability to borrow
funds or obtain additional capital, and the carrying value of its properties,
are substantially dependent on prevailing prices of natural gas and oil. It is
impossible to predict future natural gas and oil price movements with
certainty. Declines in prices received for natural gas and oil may have an
adverse affect on the Company's financial condition, liquidity, ability to
finance capital expenditures and results of operations. Lower prices may also
impact the amount of reserves that can be produced economically by the
Company.

Due to the instability of oil and natural gas prices, in 1995 the Company
began utilizing, from time to time, certain hedging instruments (e.g., swaps)
for a portion of its gas production to achieve a more predictable cash flow,
as well as to reduce the exposure to price fluctuations. However, hedging
arrangements, when utilized, limit the benefit to the Company of increases in
the price of natural gas. The Company's hedging arrangements apply to only a
portion of its production and provide only partial price protection against
declines in natural gas prices and limits potential gains from future
increases in modest prices. Such hedging arrangements may expose the Company
to risk of financial loss in certain circumstances, including instances where
production is less than expected, the Company's customers fail to purchase
contracted quantities of oil or natural gas or a sudden, unexpected event
materially impacts oil or natural gas prices. The Company accounts for all
these transactions as hedging activities and, accordingly, gains and losses
are included in oil and gas revenues during the period the hedged transactions
occur. Total Mcf's of Natural Gas purchased and sold under swap arrangements
during the nine month period ended September 30, 1996 and the year ended
December 31, 1995 were 182,000 Mcf and 62,000 Mcf respectively. Gains and
losses realized by the Joint Venture under such swap arrangements were $5,270
and $(15,720) for the nine month period ended September 30, 1996 and the year
ended December 31, 1995 respectively. There was no hedging activity in 1994 or
1993. The Company expects that the amount of hedges that it has in place will
vary from time to time. Outstanding hedges at December 31, 1995 were not
material and the Company had no existing hedging positions as of September 30,
1996.

RESULTS OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 1996 COMPARED TO NINE MONTHS ENDED SEPTEMBER
30, 1995

Oil and natural gas revenues for the nine months ended September 30, 1996
increased 271% from $1.4 million to $5.1 million as compared to the same
period in 1995. Production volumes for oil increased 74% from 47 MBbls in the
1995 period to 81 MBbls in the 1996 period. The increase in oil production
increased revenues $573,000. In addition, a 17% increase in average oil prices
increased revenue by $233,000. Production volumes for natural gas increased
362% from 337 MMcf in 1995 to 1,557 MMcf in 1996. The increase in natural gas
production increased revenues by $2.2 million. In addition, a 26% increase in
average gas prices increased revenues by $732,000. The increase in oil and
natural gas production was due to new wells being successfully drilled and
completed during 1996, which was partially offset by normal production
declines from existing wells. Increases in average oil and gas prices were
directly attributable to the general improved market conditions.

The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
nine months ended September 30, 1995 and 1996.

<TABLE>
<CAPTION>
NINE MONTHS ENDED 1996 PERIOD COMPARED
SEPTEMBER 30, TO 1995 PERIOD
----------------- ---------------------
INCREASE % INCREASE
1995 1996 (DECREASE) (DECREASE)
-------- -------- ---------- ----------
<S> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Oil and condensate (MBbls)............ 47 81 34 74%
Natural gas (MMcf).................... 337 1,557 1,220 362%
AVERAGE SALES PRICES:
Oil and condensate ($ per Bbl)........ $ 16.61 $ 19.49 $ 2.88 17%
Natural gas ($ per Mcf)............... 1.79 2.26 0.47 26%
OPERATING REVENUES:
Oil and condensate (in thousands)..... $ 773 $ 1,582 $ 809 105%
Natural gas (in thousands)............ 604 3,523 2,919 484%
-------- -------- ------
Total (in thousands)................ $ 1,377 $ 5,105 $3,728 271%
======== ======== ======
</TABLE>

23
<PAGE>

Oil and natural gas operating expenses for the nine months ended September
30, 1996 increased 42% from $502,000 to $711,000 as compared to the same period
in 1995. Oil and natural gas operating expenses increased due to increased
production generated from new oil and gas wells drilled and completed since
September 30, 1995.

Depreciation, depletion and amortization ("DD&A") expense for the nine months
ended September 30, 1996 increased 131% from $525,000 to $1.2 million as
compared to the same period in 1995. This increase was due to the increase in
oil and gas production as well as a 31% increase in the depletion rate. The
increased DD&A rate was primarily caused by the amortization of increased
exploration costs attributable to new wells drilled and completed since
September 30, 1995. Exploration costs increased due to the Company's retaining
larger working interests in its 3-D prospects, as the Company increasingly
drilled for its own account. Prior to September 30, 1995, a significant portion
of the Company's well costs were carried by other owners, resulting in a lower
historical DD&A rate.

General and administrative expense for the nine months ended September 30,
1996 remained constant at $2.1 million as compared to the same period in 1995.
An increase in salary expense of $187,000 due to the addition of new employees
was primarily offset by a $133,000 decrease in Edge Group II's General Partner
management fees further offset by decreases in various other direct expenses.

Interest expense for the nine months ended September 30, 1996 increased 237%
from $195,000 to $657,000 as compared to the same period in 1995. The weighted
average debt was $8.1 million for the nine month period ended September 30,
1996 as compared to $2.4 million for the comparable period in 1995. This
increase was primarily due to the establishment in July 1995 of, and borrowings
under, the Revolving Credit Facility and the repayment of a promissory note in
March 1995, which was offset slightly by a lower average interest rate.

There were no gains on the sale of oil and gas property for the nine months
ended September 30, 1996 as compared to a gain of $3.1 million in 1995. The
majority of the gain recorded in 1995 was attributable to the sale of a
property for $3.4 million that resulted in a gain of $2.8 million.

Net income for the nine months ended September 30, 1996 was $398,000 as
compared to $1.2 million for the 1995 period, as a result of the factors
described above.

YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994

Oil and natural gas revenues remained relatively unchanged at approximately
$2.0 million in both 1994 and 1995. Production volumes for oil increased 5%
from 61 MBbls in 1994 to 64 MBbls in 1995. Increased production was partially
offset by a 4% decrease in average oil prices. Production volumes for natural
gas decreased 13% from 588 MMcf in 1994 to 513 MMcf in 1995. The decrease in
natural gas production was offset by an 19% increase in average natural gas
prices. Oil and natural gas revenues were impacted by the addition of four new
wells, the sale of a property and declining production experienced at South
Mermentau and one other property caused by workovers that required the wells to
be shut in for a portion of the year.

24
<PAGE>

The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 1994 and 1995.

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, 1995 COMPARED TO 1994
------------- ---------------------
INCREASE % INCREASE
1994 1995 (DECREASE) (DECREASE)
------ ------ ---------- ----------
<S> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Oil and condensate (MBbls)................ 61 64 3 5%
Natural gas (MMcf)........................ 588 513 (75) (13%)
AVERAGE SALES PRICES:
Oil and condensate ($ per Bbl)............ $17.66 $16.90 $(.76) (4%)
Natural gas ($ per Mcf)................... 1.57 1.87 0.30 19%
OPERATING REVENUES:
Oil and condensate (in thousands)......... $1,071 $1,079 $ 9 1%
Natural gas (in thousands)................ 923 961 38 4%
------ ------ -----
Total (in thousands).................... $1,994 $2,040 $ 47 2%
====== ====== =====
</TABLE>

Oil and gas operating expenses increased 125% from $305,000 in 1994 to
$686,000 in 1995. The increase was primarily attributable to increased
operating expenses of approximately $223,000 on a property that was acquired
during November 1994 and nonrecurring expenses of approximately $120,000 on
another property. The remaining net increase experienced in 1995 was caused by
increased production from new wells which was offset by the sale of a property
in March 1995.

DD&A expense increased 37% from $593,000 in 1994 to $813,000 in 1995, as a
result of increased production and a higher depletion rate. The higher
depletion rate was primarily due to costs relating to a prospect that resulted
in a dry hole. These increases were offset by a decrease in amortization of
regional seismic costs of approximately $149,000 in 1995, compared to 1994,
due to certain regional seismic costs that became fully amortized in 1995.

General and administrative expense increased 23% from $2.0 million in 1994
to $2.5 million in 1995. Approximately $241,000 of the increase was
attributable to the hiring of additional geologist and land department
employees as well as salary increases for existing employees. The remaining
increase was due to other general expenses that were directly attributable to
increased 3-D prospect generation and drilling activity.

Interest expense decreased 18% from $385,000 in 1994 to $315,000 in 1995.
This decrease in 1995 was due to a lower weighted average outstanding debt
balance and a lower effective interest rate. The weighted average outstanding
debt balance decreased from approximately $4.0 million in 1994 to
approximately $2.7 million in 1995. The decrease in the weighted average
outstanding debt balance and effective interest rate was due to the repayment
of $3.3 million of promissory notes during March 1995 which bore interest at a
rate of 10%. The Company subsequently entered into the Revolving Credit
Facility in July 1995 which had an effective interest rate of 9.25% at
December 31, 1995.

The gains on sales of oil and gas properties in 1995 and 1994 represented
sales of unproved properties and proved properties. The majority of the gains
recorded in 1995 was the result of the sale of a property for approximately
$3.4 million, resulting in a gain of approximately $2.8 million. A majority of
income recorded in 1994 was attributable to the sale of a property for
approximately $1.5 million, resulting in a gain of approximately $1.3 million.

Net income in 1995 was approximately $1.1 million, compared to $969,000 in
1994, as a result of the factors described above.

25
<PAGE>

YEAR ENDED DECEMBER 31, 1994 COMPARED TO YEAR ENDED DECEMBER 31, 1993

Oil and natural gas revenues increased 37% from $1.5 million in 1993 to $2.0
million in 1994. Production volumes for oil increased 136% from 26 MBbls in
1993 to 61 MBbls in 1994. The increase in oil production increased revenues by
$612,000 which were further increased slightly due to a 1% increase in average
oil prices. Production volumes for natural gas increased 29% from 457 MMcf in
1993 to 588 MMcf in 1994. This increase in natural gas production contributed
$288,000 to revenues which was offset by a 29% decrease in average natural gas
prices which decreased revenues by $371,000. A portion of the overall increase
in oil and natural gas production in 1994 was due to certain prospects in
which the Company had a reversionary interest reaching payout during the year
and two other prospects in which the Company had a reversionary interest that
reached payout in 1993 but did not contribute a full year of production in
that year. These two prospects contributed an additional $451,000 in revenues
in 1994. Additionally, the Company successfully drilled and completed several
new natural gas wells in the fourth quarter of 1994, which contributed
approximately $272,000 in revenues. The increases were offset by the shutting
in of a well on the South Maurice Field during 1993 and normal declining
production on various properties.

The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 1993 and 1994.

<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, 1994 COMPARED TO 1993
------------- ---------------------
INCREASE % INCREASE
1993 1994 (DECREASE) (DECREASE)
------ ------ ---------- ----------
<S> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Oil and condensate (MBbls)................ 26 61 35 136%
Natural gas (MMcf)........................ 457 588 131 29%
AVERAGE SALES PRICE:
Oil and condensate ($ per Bbl)............ $17.52 $17.66 $ 0.14 1%
Natural gas ($ per Mcf)................... 2.20 1.57 (0.63) (29%)
OPERATING REVENUES:
Oil and condensate (in thousands)......... $ 450 $1,071 $ 621 138%
Natural gas (in thousands)................ 1,005 923 (82) (8%)
------ ------ ------
Total (in thousands).................... $1,455 $1,994 $ 539 37%
====== ====== ======
</TABLE>

Oil and natural gas operating expenses increased 83% from $167,000 in 1993
to $305,000 in 1994. The increase was primarily attributable to increased oil
and gas production and a higher average severance tax rate in 1994 as well as
higher working interests on new wells drilled in 1994.

DD&A expense increased 34% from $442,000 in 1993 to $593,000 in 1994,
largely as a result of increased production. Additionally, amortization of
seismic costs increased approximately $126,000 in 1994 from 1993 as a result
of the purchase of regional seismic data in 1994.

General and administrative expense increased 17% from $1.7 million in 1993
to $2.0 million in 1994. Approximately $291,000 of the increase was
attributable to hiring additional geologists and land department employees
during 1994 as well as salary increases for existing employees.

Interest expense decreased 39% from $636,000 in 1993 to $385,000 in 1994 due
to a lower effective interest rate and a lower weighted average outstanding
debt balance in 1994. The weighted average outstanding debt balance decreased
from approximately $4.5 million in 1993 to approximately $4.0 million in 1994
due to scheduled debt payments on a promissory note.

The gain on sale of oil and gas property in 1994 primarily represented the
sale of an unproved property for $1.5 million that resulted in a gain of $1.3
million. There was no such significant sale of unevaluated properties during
1993.

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Net income increased from a net loss of $1.3 million in 1993 to a net income
of $969,000 in 1994, as a result of the factors described above.

LIQUIDITY AND CAPITAL RESOURCES

The Company's primary sources of liquidity have included funds generated by
operations, the sale of prospects and producing properties, equity capital
from private sources and borrowings, primarily at the Joint Venture level
under the Revolving Credit Facility and a subordinated secured loan (the
"Subordinated Loan") from Mr. James C. Calaway, the father of both the
Company's Chief Executive Officer and its President. A portion of the proceeds
from the Offering will be loaned to the Joint Venture to repay the amounts
outstanding under both the Revolving Credit Facility and the Subordinated
Loan. The Revolving Credit Facility will remain outstanding for future
borrowings and the Subordinated Loan will be terminated. The Joint Venture is
required to comply with various operating and financial covenants under the
Revolving Credit Facility. The continued availability to the Joint Venture of
funds borrowed under the Revolving Credit Facility is subject to continued
compliance with such covenants.

Cash flows provided (used) by operations were ($1.0 million), ($604,000),
($927,000) and $2.8 million for the years ended December 31, 1993, 1994, 1995
and the nine month period ended September 30, 1996, respectively. The increase
in operating cash flows for the nine month period ended September 30, 1996 was
primarily attributable to increased drilling activity and resulting increases
in accounts payable. This increase was primarily due to Old Edge becoming an
oil and gas well operator in late 1995 and a significant increase in drilling
activities during the nine month period ended September 30, 1996. Due to the
same factors discussed above, accounts receivable increased which somewhat
offset the increase in accounts payable. Accrued liabilities increased by
$182,000 for the nine months ended September 30, 1996 due to deferred offering
costs accrued but not yet paid. The increase in cash flows used in 1995 as
compared to 1994 was due primarily to the increase in operating loss, which
was offset by various changes in balance sheet accounts. Accounts receivable,
working interest owners increased by $213,000 in 1995 due to increased
drilling activity in which Old Edge was the operator. Accounts payable, trade
and accounts payable to related parties increased by $420,000 and $266,000,
respectively. These increases were caused by increased drilling activity for
its own account as well as an increase in Edge Group II General Partner
management fees which have accumulated but have not yet been paid. The
decrease in cash used from operations from 1993 to 1994 was due to decreases
in various working capital accounts. Accounts receivable trade and accounts
payable trade increased $269,000 and $145,000, respectively during 1994
primarily due to the increased oil and gas production and drilling activities
in 1994 primarily attributable to higher working interests on new wells
drilled in 1994. Accounts payable to related partners increased by $258,000
primarily due to an increase of $266,000 for Edge Group II's General Partner
managers fees as referred to above.

The Company expects capital expenditures in 1997 to be at least $20 million.
A substantial portion of capital expenditures will be invested in the
Company's portfolio of 3-D prospects to fund drilling activities and expand
its reserve base. In addition, the Company will continue to expand and improve
its technological and 3-D seismic interpretation capabilities. Based on its
existing business plan, the Company expects to drill 50 gross (21.4 net) wells
in 1996 and has budgeted for 120 gross (46.3 net) wells in 1997. The actual
number of wells drilled may differ significantly from such estimate. See
"Business of the Company--Significant Project Areas." In addition to its
existing leased acreage prospects, the Company has acquired various 3-D
seismic options which will allow it to lease approximately 59,562 gross
(29,781 net) undeveloped acres.

During the first nine months of 1996, the Company continued to reinvest a
substantial portion of its cash flows into increasing its 3-D prospect
portfolio, improving its 3-D seismic interpretation technology and funding its
drilling program. As a result the Company used $5.7 million in cash in
investor activities during the nine months ended September 30, 1996. Capital
expenditures during the first nine months of 1996 were $7.9 million. The
Company expects to incur additional capital expenditures of $3.3 million in
the fourth quarter of 1996 for

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the drilling of approximately 16 new wells. Investing activities used $1.2
million in cash in 1995 compared to providing $.3 million in cash in 1994.
This change was directly attributable to an increase in capital expenditures.
Capital expenditures were $3.7 million, $6.8 million and $8.5 million in 1993,
1994 and 1995, respectively. The Company's drilling efforts resulted in the
successful completion of four wells in 1993, nine wells in 1994 and 22 wells
in 1995 that increased pretax present value of reserves by $2.5 million, $1.6
million and $10.2 million, respectively. In 1995 the Company sold one of its
proved producing properties and received total cash proceeds from such sale of
$3.4 million. These proceeds were used to pay down debt and fund general
working capital and corporate needs. The Company also sold several undeveloped
oil and gas properties receiving cash proceeds of $3.4 million, $7.1 million
and $4.0 million in 1993, 1994 and 1995, respectively.

Cash flows from financing activities for the nine months ended September 30,
1996 were $3.6 million. These cash flows were primarily a result of drawdowns
on the Revolving Credit Facility, which were partially offset by deferred
offering costs. Cash flows from financing activities were $1.9 million for the
year ended December 31, 1995 compared to a use of cash flows of $.4 million
for the previous year. The increase in cash flows from financing activities in
1995 was due to the proceeds from the Revolving Credit Facility, somewhat
offset by the repayment of the RIMCO Note.

Due to the Company's active exploration and development and technology
enhancement programs, the Company has experienced and expects to continue to
experience substantial working capital requirements. While the Company
believes that the net proceeds from the Offering, cash flow from operations
and borrowings by the Joint Venture under the Revolving Credit Facility should
allow the Company to successfully implement its present business strategy,
additional financing may be required in the future to fund the Company's
growth, development and exploration drilling and continued technological
enhancement. In the event such capital resources are not available to the
Company, its drilling and other activities may be curtailed.

REVOLVING CREDIT FACILITY

In July 1995, the Joint Venture entered into the two year Revolving Credit
Facility with Compass Bank-Houston ("Compass"), which provides a maximum loan
amount of $20 million, subject to borrowing base limitations. Under the
Revolving Credit Facility, principal outstanding is due and payable upon
maturity in June 1998 with interest due monthly. At November 30, 1996, the
borrowing base was $11.5 million and borrowings outstanding under the
Revolving Credit Facility were $8.7 million. Beginning on December 1, 1996 and
on the first day of each month thereafter, the borrowing base is required to
be reduced by $325,000. The Revolving Credit Facility is without recourse to
Old Edge and the other participants in the Joint Venture. The Company will
loan a portion of the proceeds of the Offering to the Joint Venture for the
purpose of repaying all outstanding indebtedness under the Revolving Credit
Facility. See "Certain Transactions--The Combination Transactions--Description
of Joint Venture." However, the Revolving Credit Facility will be available
for future borrowings by the Joint Venture during its wind-down period. The
Joint Venture may seek to adjust the terms and availability of the Revolving
Credit Facility in the future.

Semi-annually, Compass makes, in its sole discretion, the borrowing base
determination based upon the Joint Venture's proved oil and gas properties
determined in accordance with Compass' normal and customary procedures for
evaluating oil and gas reserves and other related assets. The Joint Venture
may request two additional borrowing base redeterminations per annum, provided
that Compass will not be obligated to perform a redetermination more than one
time per quarter, including quarters that contain a scheduled redetermination.

The interest rate for borrowings is either the Base Rate plus 0.5% or LIBOR
plus 2.5%. The Base Rate is the higher of (i) the Federal Funds Rate plus 0.5%
or (ii) the prime rate. The Joint Venture also pays a quarterly commitment fee
of 0.5% per annum for the unused portion of the borrowing base and a fee of
$5,000 for each regularly scheduled and borrower requested borrowing base
redetermination.

The Joint Venture is subject to certain covenants under the terms of the
Revolving Credit Facility, including, but not limited to (i) tangible
venturer's capital (total assets exclusive of certain intangibles minus total
liabilities)

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<PAGE>

must be at least equal to $2.0 million plus 50% of positive net income and
100% of equity raised for all quarterly periods subsequent to June 30, 1996;
(ii) the ratio at the end of any quarter of cash flow (net income plus
depreciation, depletion, amortization and other non-cash expenses less non-
cash net income for such quarter) to debt service coverage (cash payments made
for principal on debt or capital leases for such quarter) must be at least
1.25 to 1.00; and (iii) the dividends and distributions to the venturers,
among other things, may not exceed 50% of the cash flow in excess of the cash
flow required to maintain the ratio referred to in (ii) above. The Revolving
Credit Facility also places restrictions on additional indebtedness, liens,
sales of properties, amendment of the Joint Venture Agreement and other
matters. The Joint Venture's obligations under the Revolving Credit Facility
are secured by substantially all of the oil and gas properties of the Joint
Venture.

SUBORDINATED LOAN

In December 1994, the Joint Venture entered into an agreement providing for
the Subordinated Loan ("The Subordinated Loan Agreement"). Such agreement
provides for a $1 million term loan and a $1 million line of credit. Drawdowns
under the line of credit require 30 days' notice. At September 30, 1996, the
aggregate amount outstanding under the Subordinated Loan was $1.3 million,
including $300,000 outstanding under the line of credit. The principal is due,
unless earlier retired by the Joint Venture, upon the earlier of April 8, 1998
or the conclusion of the Joint Venture's wind up period. Interest at 10% per
annum is due monthly. The Subordinated Loan is secured by certain oil and gas
properties, equipment and other assets of the Joint Venture, but is
subordinate to the Revolving Credit Facility. The mortgage and security
agreement restricts the transfer of properties, creation of liens and other
matters. The Subordinated Loan is without recourse to the participants in the
Joint Venture. Under the Subordinated Loan Agreement, Mr. James C. Calaway has
a right to receive specified reversionary and overriding royalty interests on
prospects of the Joint Venture and certain rights to convert such interests
into shares of Common Stock, which shares are expected to be issued in
connection with the Combination Transactions. See "Certain Transactions--The
Combination Transactions--The Calaway Exchange." A portion of the proceeds
from the Offering will retire the Subordinated Loan.

In addition to the financing arrangements referred to above, the Company has
historically had other subordinate credit arrangements with certain
shareholders and related parties. Following the Offering these credit
arrangements will not be available.

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 (decreases), there
could be a corresponding increase (decrease) in the operating cost that the
Company is required to bear for operations, as well as an increase (decrease)
in revenues. Inflation has had a minimal effect on the Company.

OTHER

In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 121 ("SFAS No. 121") regarding accounting
for the impairment of long-lived assets. The Company adopted SFAS No. 121
effective January 1, 1996. However, its provisions are not applicable to the
Company's oil and gas properties as they are accounted for under the full cost
method of accounting. The effect of adopting SFAS No. 121 was not material for
any period presented.

In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123 ("SFAS No. 123"). SFAS No. 123 is a
new standard of accounting for stock-based compensation and establishes a fair
value method of accounting for awards granted after December 31, 1995 under
stock compensation plans. SFAS No. 123 encourages, but does not require,
companies to adopt the fair value method of accounting in place of the
existing method of accounting for stock-based compensation whereupon
compensation costs are recognized only in situations where stock compensation
plans award intrinsic value to recipients at the date of grant.

The Company has elected not to adopt the fair value accounting of SFAS No.
123 and continues to account for these plans under APB Opinion No. 25, under
which no compensation costs have been recognized.

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BUSINESS

OVERVIEW

The Company explores for oil and natural gas by emphasizing the integrated
application of highly advanced data visualization and computerized 3-D seismic
data analysis to identify potential hydrocarbon accumulations. The Company
believes its approach to processing and analyzing geophysical data
differentiates it from other independent exploration and production companies
and is more effective than conventional 3-D seismic data interpretation
methods. The Company utilizes a fully integrated, client-server environment
including nine workstation nodes with a high performance Silicon Graphics
server. This hardware configuration enables the Company to utilize advanced
interpretation software, including both Earth Cube and Voxel Geo technology.
The Company also believes that it maintains one of the largest databases of
onshore South Texas Gulf Coast 3-D seismic data of any independent oil and gas
company, and is continuously acquiring substantial additional data within this
core region.

The Company acquires 3-D seismic data by organizing and designing regional
data acquisition surveys for its proprietary use, as well as through selective
participation in regional non-proprietary 3-D surveys. The Company negotiates
seismic options for a substantial majority of the areas encompassed by its
proprietary surveys, thereby allowing it to later secure identified prospect
leasehold interests on a non-competitive, pre-arranged basis. In the Company's
non-proprietary 3-D survey areas, the Company's technical capabilities allow
it to rapidly and comprehensively evaluate large volumes of regional 3-D
seismic data, facilitating its ability to identify attractive prospects within
a surveyed region and to secure the corresponding leasehold interests ahead of
other industry participants.

The Company's extensive technical expertise has enabled it to internally
generate all of its 3-D prospects drilled to date and to assemble a large
portfolio of 3-D based drilling prospects . The Company pursues drilling
opportunities that include a blend of shallower, normally pressured reservoirs
that generally involve moderate costs and risks as well as deeper, over-
pressured reservoirs that generally involve greater costs and risk, but have
higher economic potential. The Company mitigates its exposure to exploration
costs and risks by conducting its operations with industry partners, including
major oil companies and large independents, that generally pay a
disproportionately greater share of seismic acquisition and, in many
instances, leasing and drilling costs than the Company.

The Company has experienced rapid increases in reserves, production and cash
flow since early 1995 due to the growth of its 3-D based drilling activities
and the retention of progressively larger interests in its exploration
projects. From January 1, 1995 to September 30, 1996, reserves discovered from
Company-generated prospects totaled 91.1 Bcfe, while the Company's net proved
reserves more than tripling from 5.9 Bcfe to 18.6 Bcfe at an average finding
cost to the Company of $0.51 per Mcfe. The Company drilled 13 gross (0.42 net)
wells in 1994, 35 gross (13.5 net) wells in 1995 and 34 gross (14.7 net) wells
in the nine months ended September 30, 1996. For the period from January 1,
1995 through September 30, 1996, the Company's commercial well success rate
was approximately 67% for the 69 gross (28.2 net) exploratory wells drilled
(of which 62 were based on its interpretation of 3-D seismic data).

The Company's future growth will be driven by the drilling and development
of existing opportunities from its prospect portfolio as well as new 3-D based
prospects that are continually being identified by the Company's exploration
team. The Company anticipates drilling 16 gross (7.4 net) wells in the fourth
quarter of 1996 and has budgeted for drilling 120 gross (46.3 net) wells in
1997. The Company currently anticipates increasing its capital expenditure
budget to at least $20.0 million in 1997 from $11.2 million in 1996. The
Company believes the proceeds of this Offering will enable it to increase the
number and size of additional 3-D seismic acquisition projects in which it
participates, accelerate its drilling activities and retain a greater share of
the reserves it discovers.

The address of the Company's principal executive offices is Texaco Heritage
Plaza, 1111 Bagby, Suite 2100, Houston, Texas 77002, and its telephone number
is (713) 654-8960.

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BACKGROUND

The Company began operations in 1983 and until 1992 generated drilling
prospects based on 2-D seismic data for sale to other exploration and
production companies. From the Company's inception, it has generated
approximately 130 prospects, many of which were large projects with deep
targets that required substantial drilling costs. Given the uncertainties of
drilling based on 2-D seismic information, the substantial drilling costs of
the projects and the Company's limited financial resources, the Company
generally sold substantially all of its interests in such prospects for cash
while retaining a reversionary interest. A substantial portion of the annual
cash flows generated by the Company during this period was distributed to its
interest holders resulting in a low level of equity accumulation. During this
period, however, the Company developed extensive expertise in generating and
obtaining drilling prospects, particularly in the onshore Gulf Coast area.

During 1992, as a result of the advent of economic onshore 3-D seismic
surveys and the improvement and increased affordability of data interpretation
technologies, the Company changed its exploration strategy to emphasize the
acquisition of 3-D seismic data covering certain of its existing 2-D based
project areas. From 1992 to 1995, the Company reduced its inventory of 2-D
based prospects, began limited drilling for its own account of certain
existing 2-D based prospects and began developing prospects based on 3-D
seismic data. Since early 1995, the Company has almost exclusively drilled
prospects generated from 3-D seismic data, while accelerating its drilling
activity and increasing its working interests in new project areas as
available capital has allowed.

BUSINESS STRATEGY

FOCUSED EXPLORATION. The Company intends to maintain its exploration
focus along the onshore Gulf Coast with continued emphasis in South Texas
because of its 3-D seismic expertise in this region. The Company believes,
based on the results of its recent exploration activities, that significant
undiscovered reserves remain in this region. The Company also plans to
utilize its existing database consisting of 567 square miles of 3-D seismic
and geologic data (509 square miles of which are in South Texas) and its
knowledge of the region's producing fields and trends to further expand its
operations within this core region. The Company is currently in the process
of acquiring an additional 459 square miles (293,760 acres) of 3-D seismic
data in South Texas, which the Company believes will generate a significant
number of additional prospects in 1997 and beyond.

SOPHISTICATED AND EXPERIENCED TECHNICAL TEAM. The Company has assembled a
team of highly talented geoscientists and other technical personnel who are
experienced in the use of advanced exploration techniques, and it actively
seeks to identify and attract new members to its exploration team. The
Company provides its personnel with a technologically advanced work
environment, training and results-oriented compensation, including
participation in the Company's stock option plan. The Company believes that
the use of advanced technology by its technical personnel together with
increased capital resources will be critical components to implementing its
business strategy.

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<PAGE>

commencement of production and cash flow. The Company typically sells to
industry partners, on a promoted basis, a portion of its interests in
prospects that involve higher costs and greater risks, or consist of deep,
over-pressured and often larger reservoirs, in order to mitigate its
exploration risk and fund the anticipated capital requirements for the
portion of those prospects it retains.

CONTROL OVER CRITICAL EXPLORATION FUNCTIONS. In its participation
agreements with industry partners, the Company generally seeks to exercise
control over what it believes to be the most critical functions in the
exploration process. These functions include determining the area to
explore; managing the land permitting and optioning process; determining
seismic survey design; overseeing data acquisition and processing;
preparing, integrating and interpreting the data; and identifying each
prospect and drill site. The Company seeks operator status and control over
the remaining aspects of field operations when it believes its expertise
can add value to these functions.

EXPLORATION TECHNOLOGY

Since 1992, as a result of the advent of economic onshore 3-D seismic
surveys and the improvement and increased affordability of data interpretation
technologies, the Company had relied almost exclusively on the interpretation
of 3-D seismic data in its exploration strategy. The principal advantage of 3-
D seismic data over 2-D seismic data is that it affords a geoscientist the
ability to investigate the entire prospective area using a 3-D seismic data
volume, as compared to the limited number of two dimensional profiles covering
a small percentage of the prospective area that are available using 2-D
seismic data. As a consequence, a geoscientist using 3-D seismic data is able
to more fully evaluate prospective areas and produce more accurate
interpretations. The use of structural maps based upon 3-D seismic data can
significantly improve the probability of drilling commercially successful
wells, since this data allows structurally advantageous positions to be more
accurately located in highly drilled exploration plays where only 2-D seismic
data was used in the past.

The Company's methodology for interpreting 3-D seismic data has advanced
beyond traditional 3-D interpretation techniques which consist of interpreting
multiple closely spaced 2-D profiles extracted from 3-D seismic volumes to
generate 3-D structural maps. The Company's advanced visualization and data
analysis techniques and resources enable its geoscientists to view
collectively large volumes of information contained within the 3-D seismic
data. This improves the geoscientist's ability to recognize certain important
patterns or attributes in the data which may indicate hydrocarbon traps and
which, if viewed incorrectly or with the application of improper techniques,
could go undetected. Visualization techniques also enable the geoscientist to
quickly identify and prioritize key areas from the large volumes of data
reviewed in order to realize the greatest early benefit. The Company's
sophisticated computing resources and unique visualization and data analysis
techniques allow its geoscientists to more easily identify features such as
shallow amplitude anomalies, complex channel systems, sharp structural details
and fluid contacts, which might have been overlooked using less sophisticated
3-D seismic data interpretation techniques.

The application of advanced 3-D exploration technology requires large scale
information processing and graphic visualization, made possible by the rapid
improvements in computing technology. The Company has made a significant
investment in its 3-D seismic data visualization technology, which is closely
linked with the Company's well-log database and other geoscience application
software. Additionally, the Company has developed a fully integrated, client-
server environment utilizing nine scientific workstation nodes. For large
scale visualization, the Company uses a Silicon Graphics Onyx R10000 server
with the SGI Reality Engine-2. The Company uses a comprehensive suite of
Landmark Graphics geoscience applications in its interpretation environment,
including Landmark's EarthCube software, which is designed specifically to
integrate visualization and 3-D geologic interpretation. In addition, the
Company utilizes Cogniseis' Voxel Geo technology in its visualization efforts.

The Company's technological success is dependent in part upon hiring and
retaining highly skilled technical personnel. The Company has assembled a
technical team that it believes has the capacity to adapt to the rapidly
changing technological demands in the field of oil and natural gas
exploration. This team consists of seven

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geoscientists with an average of 15 years industry experience, most of which
have had extensive experience with major oil companies. The Company provides
its technical team with a sophisticated work environment and enables these
employees to participate in the upside potential of prospects by assigning
them overriding royalty interests in prospects they identify. See
"Management--Other Compensatory Arrangements." With its technical capabilities
and personnel, the Company believes that it will be able to analyze
increasingly large quantities of data without a commensurate increase in the
number of employees. Additionally, the expertise of the Company's team of
geoscientists reduces its dependence on outside technical consultants and
enables the Company to internally generate substantially all of its prospects.

EXPLORATION AND OPERATING APPROACH

The Company's exploration approach is to acquire large 3-D seismic data sets
along prolific, producing trends of the onshore Gulf Coast and to utilize
advanced visualization and interpretation techniques to identify or evaluate
prospects and then drill the prospects which it believes provide the potential
for significant returns. The Company typically seeks to explore in areas with
(i) numerous accumulations of normally pressured reserves at shallow depths
and in geologic traps that are difficult to define without the use of advanced
3-D data visualization and interpretation and (ii) the potential for large
accumulations of deeper, over-pressured reserves. The Company typically sells
a portion of its interest in the deep, over-pressured prospects in order to
mitigate its exploration risk and fund the anticipated capital requirements
for the interests it retains in such prospects, while retaining all or the
majority of its interest in the prospects with normally pressured reservoirs.

The Company emphasizes preplanning in project development to lower capital
and operational costs and to efficiently integrate potential well locations
into the existing and planned infrastructure, including gathering systems and
other surface facilities. In constructing surface facilities, the Company
seeks to use reliable, high quality, used equipment in place of new equipment
to achieve cost savings. The Company also seeks to minimize cycle time from
drilling to hook-up of wells, thereby accelerating cash flow and improving
ultimate project economics.

An important component of the Company's exploration approach is the
acquisition of large 3-D seismic data sets at the lowest possible cost. The
Company has sought to obtain large 3-D data sets either by participating in
large seismic data acquisition programs through joint venture arrangements
with other energy companies or "group shoots" in which the Company shares the
costs and results of seismic surveys. The Company believes its technical
capabilities allow it to rapidly evaluate these large 3-D datasets and
identify and secure drilling opportunities prior to the other participants in
these group shoots. In both the joint ventures and the group shoots, the
Company's partners have borne a disproportionate share of the up-front costs
of seismic data acquisition and interpretation in return for the Company's
expertise in the management of seismic surveys, interpretation of 3-D seismic
data, development of prospects and acquisition of exploration rights.
Substantially all of the Company's operations are conducted through joint
operations with industry participants. The Company is currently actively
involved in 14 joint project areas based on 3-D seismic surveys with, among
others, Belco Oil and Gas Corp., Carrizo Oil and Gas Inc., Chevron
Corporation, Cheyenne Petroleum Company, IP Petroleum Company, Inc., KCS
Energy, Inc., Pennzoil Company, Phillips Petroleum Company and Texaco Inc.
Following this Offering, the Company intends to increase the number and size
of seismic data acquisitions and interpretation projects it manages to
accelerate its prospect generation activities and capture a greater share of
the oil and natural gas properties discovered as a result of its technological
expertise.

Under the participation agreements on its recent projects, the Company is
generally responsible for determining the area to explore; managing the land
permitting and optioning process; determining seismic survey design;
overseeing data acquisition and processing; preparing, integrating and
interpreting the data; identifying the drill site; and in selected instances,
managing drilling and production operations. The Company is therefore
responsible for exercising control over what it believes are the critical
functions in the exploration process. The Company seeks to obtain lease
operator status and control over field operations, including decisions
regarding drilling and completion methods and accounting and reporting
functions, only when its expertise and planning capabilities indicate that
meaningful value can be added through its performance of these functions.
Typically,

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<PAGE>

in cases when the Company does not have field operator status, the Company is
primarily responsible for identifying prospects for the operator and, when
necessary, asserts its rights under its joint operating agreements to ensure
drilling of such prospects. The Company began field operations of wells in
1995 and currently operates producing oil and natural gas wells in South Texas
and Alabama. These wells range in depth from 3,000 feet to greater than 14,000
feet.

The Company has developed extensive experience in the development and
management of projects along the Gulf Coast. Over the past 13 years, the
Company has generated and assembled approximately 130 prospects within the
onshore Gulf Coast area. The Company believes that the ability to develop
large scale 3-D projects in this area on an economic basis requires experience
in obtaining the rights to explore and is a source of competitive advantage
for the Company.

The Company's primary strategy for acreage acquisition is to obtain leasing
options covering large geographic areas prior to conducting its 3-D seismic
surveys. The Company, therefore, typically seeks to acquire seismic permits
that include options to lease, thereby reducing the cost and the level of
competition for leases on drilling prospects that may result upon completing a
successful seismic data acquisition program over a project area.

SIGNIFICANT PROJECT AREAS

Set forth below are descriptions of the Company's key project areas where it
is actively exploring for potential oil and natural gas prospects and in many
cases currently has production. The 3-D surveys the Company is using to
analyze its project areas range from regional non-proprietary group shoots to
single field proprietary surveys. The Company has participated in these
project areas with industry partners under agreements that typically provide
for the industry partners to bear a disproportionately greater share of the
up-front costs associated with obtaining option arrangements with landowners,
seismic data acquisition and related data interpretation than the costs
incurred by the Company.

Although the Company is currently pursuing prospects within the project
areas listed below, there can be no assurance that these prospects will be
drilled at all or within the expected timeframe. The final determination with
respect to the drilling of any scheduled or budgeted wells will be dependent
on a number of factors, including (i) the results of exploration efforts and
the acquisition, review and analysis of the seismic data, (ii) the
availability of sufficient capital resources by the Company and the other
participants for the drilling of the prospects, (iii) the approval of the
prospects by other participants after additional data has been compiled, (iv)
economic and industry conditions at the time of drilling, including prevailing
and anticipated prices for natural gas and oil and the availability of
drilling rigs and crews, (v) the financial resources and results of the
Company and (vi) the availability of leases on reasonable terms and permitting
for the prospect. There can be no assurance that these projects can be
successfully developed or that the scheduled or budgeted wells discussed will,
if drilled, encounter reservoirs of commercially productive natural gas or
oil. The reserve data set forth below for the various prospects is based upon
the Ryder Scott Report. There are numerous uncertainties in estimating
quantities of proved reserves, including many factors beyond the control of
the Company. See "Risk Factors--Dependence on Exploratory Drilling
Activities," "--Reserve Replacement Risk" and "--Uncertainty of Reserve
Information and Future Net Revenue Estimates."

TEXAS

Encinitas/Kelsey Project Area: Frio-Vicksburg Trend

The Encinitas/Kelsey Project Area is located in Brooks County, Texas in the
geologically complex Frio-Vicksburg trend. The Company acquired 9,110 acres in
this project area in December 1994 to re-develop the property. Upon
acquisition of its interests in this project area, the Company undertook a
comprehensive petrophysical study and a 32 square mile 3-D survey over the
area which has resulted in the identification of numerous prospects. Four of
these prospects were drilled between January and June 1996, resulting in four
new

34
<PAGE>

field discoveries. During the quarter ended September 30, 1996, the Company's
share of production from wells in this project area was 54 Bbls/d of oil and
2.6 MMcf/d of gas. As of September 30, 1996, the Company's net estimated
proved reserves in the fields were 1.8 Bcf of gas and 23 MBbls of oil. The
Company has identified seven drill sites, one of which is currently being
drilled, with the remaining six to be drilled in the first half of 1997. Two
additional wells may be drilled in 1997, depending upon the results of the
eight wells scheduled to be drilled. The Company believes that continuing
interpretation of the 3-D seismic data will result in additional prospects and
drilling locations. The Company has a 22.5% working interest and an 18.8% net
revenue interest in the properties in this project area.

Everest Project Area: Frio-Vicksburg Trend

The Everest Project Area is located in Starr and Hidalgo Counties, Texas in
the prolific Frio-Vicksburg Trend. The Company and a partner licensed
approximately 340 square miles of non-proprietary 3-D seismic data in this
project area in August 1995 and June 1996. Through its data processing,
analysis and interpretation techniques, the Company has identified 58
prospects in the shallow Frio trend and the deeper structurally complex
Vicksburg Trend, and two potentially large prospects in the relatively
unexplored Eocene Trend. The Company and its partner currently control 18 of
these prospects (ten Frio, seven Vicksburg and one Eocene). Seven of these
prospects have been drilled (five Frio prospects and two Vicksburg), resulting
in six new field discoveries and one field extension. These discoveries have
resulted in additional net proved reserves to the Company of 3.8 Bcf of gas
and 47 MBbls of oil. A portion of the Company's interest in the Vicksburg
prospects was sold to industry partners, the proceeds of which were used to
finance the drilling costs of the Company's retained working interest. For
1997, the Company has scheduled two development wells on previous discoveries
and six exploratory wells. The Company has also budgeted for drilling 11
additional exploratory prospects to be selected from the remaining inventory
of 42 prospects. The Company also believes that continuing interpretation of
the Everest Project 3-D data will result in additional prospects and drilling
locations. The Company is entitled to 50% of any interests acquired by the
Company and its partner in prospects developed in this project area.

Cameron Project Area: Wilcox and Jackson-Yegua Trends

The Cameron Project Area is located in Webb and Duval Counties, Texas in the
prolific structurally complex Wilcox trend and the highly stratigraphic
Jackson-Yegua trend. The Company and a partner have underwritten approximately
325 square miles of non-proprietary 3-D seismic data in this project area. The
first 100 square miles of the data is expected to be received by the Company
in March 1997, with the remainder expected to be delivered to the Company over
the remainder of 1997. As in the Everest Project, the Company's strategy is to
drill all shallow, normally pressured prospects and to sell portions of the
deeper over-pressured prospects using the resulting proceeds to finance the
drilling costs of the retained interests in such prospects. The Company
believes that, given the geologic similarities of the Everest and Cameron
Project areas, the Company's experience in the Everest Project Area will
assist it in its exploration efforts in the Cameron Project. The Company is
entitled to 50% of any interests acquired by the Company and its partner in
prospects developed in this project area.

Nita/Austin Project Area

Nita/Austin Project Area: Wilcox Formation. The Nita/Austin Project Area is
located along the Gulf Coast of South Texas in Goliad County. The Company has
identified two large Wilcox prospects in this project area. The first of these
prospects was discovered by the Company and is called the Bego Field. An
initial test well drilled in 1991 based on 2-D seismic data resulted in a new
field discovery. A second well in the Bego Field was drilled in 1994 and
experienced mechanical failure. In early 1995 the Company acquired a 42 square
mile 3-D seismic survey covering this project area. A third Bego Field well
was drilled in 1995 using the 3-D seismic data and is currently in the
developmental stage. Currently, two delineation wells are also being drilled.
Given the early stage of development and current uncertainty as to the
commerciality of the field, the Company has not attempted to make any estimate
of reserves from these wells. The second of the two large Wilcox prospects was
identified using 3-D seismic data and is scheduled to be drilled in the first
quarter of 1997. The

35
<PAGE>

Company has an average 1.7% working interest and an average 6% after payout
working interest in its properties in the Wilcox formation portion of this
project area.

Nita/Austin Project Area: Shallow Frio Trend. In mid-1995, the Company,
through its analysis of the Nita/Austin 3-D seismic survey, identified 26
prospects in the shallow Frio trend. During the second half of 1995 and the
first nine months of 1996, 22 of these prospects were drilled, resulting in 17
commercial wells. For the quarter ended September 30, 1996, these wells
produced 2.8 MMcf/d of natural gas net to the Company. The estimated net
proved reserves to the Company for these wells were 4.6 Bcf of natural gas as
of September 30, 1996. The Company currently expects to drill one additional
well in the shallow Frio trend portion of this project area during the first
quarter of 1997. The Company has also budgeted two additional shallow Frio
wells for the end of 1997. The Company has an average 80% working interest and
an average 60% net revenue interest in the properties in the shallow Frio
trend portion of this project area.

Spartan Project Area: Frio Trend

The Spartan Project Area is a 23 square mile 3-D seismic project area
located adjacent to the Nita/Austin Project Area in Goliad and Victoria
Counties, Texas. The Company currently has approximately 5,855 acres under
lease or option in this project area. The objective for this project area is
primarily the shallow Frio trend, with additional potential in the deeper
Yegua and Wilcox formations. The Company began interpreting the 23 square
miles of seismic data in August 1996, and has identified four Frio drill
sites, one deep Wilcox prospect and one Yegua prospect to date. The Company
has completed the first Frio well, and the remaining wells are scheduled to be
drilled in 1997. The Company has also budgeted for 1997 one additional well
that is currently being evaluated. The Company's primary exploration leases
and options, if exercised, provide for a 50% working interest and an average
39.5% net revenue interest in its properties in this project area.

Belco Project Area: Frio Trend and Yegua and Wilcox Formations

The Belco Project Area is located in Goliad, Bee and Victoria Counties,
Texas where the Company controls 38,476 acres through lease or option. The
primary exploration objectives for this project area, like the Nita/Austin
Project Area and the Spartan Project Area, are the shallow Frio gas
accumulations, with the secondary objectives being the deeper Yegua and Wilcox
formations. The Company and its partner on this project area, Belco Oil & Gas
Corp. ("Belco"), are currently in the initial phase of this project which
involves acquiring a total of 250 square miles of proprietary 3-D seismic
data. The first 114 square miles of the seismic data area are currently being
shot, and the seismic data is expected to be available for interpretation
during the first quarter of 1997. If the Company is successful in the
development of this initial phase, the project is expected to expand to a
total of 750 square miles of data acquisition. The Company's agreement with
Belco provides for the Company to manage all aspects of the project's
development, with Belco performing field operations for the deep prospects
developed and the Company operating any shallow Frio wells. The Company has
budgeted to drill 41 wells in this project area in 1997 based upon statistical
results of drilling activities in the adjoining Nita/Austin and Spartan
Project Areas that the Company believes are geologically similar. The Company
is entitled to 50% of any interests acquired by the Company and Belco in
prospects developed in this project area.

Tyler Project Area: Wilcox, Hockley, Pettus and Yegua Formations

The Tyler Project Area is located in Live Oak County, Texas where the
Company currently has approximately 3,750 gross acres under lease. The
exploration objectives are the deep, over-pressured zones of the expanded
Upper Wilcox formation and the shallow zones of the Hockley, Pettus and Yegua
formations. A 25 square mile proprietary 3-D seismic survey over the project
area was shot in 1994, from which an approximately 3,500 acre Wilcox prospect
was identified. An initial well drilled on the project area in 1995 was
temporarily abandoned for mechanical reasons, but the Company reentered and
completed the well and it was flowing at a rate of 1.0 MMcf/d of gas as of
September 30, 1996. The Company is currently attempting to

36
<PAGE>

complete an additional deep well that was drilled in late 1996 and experienced
mechanical problems. One additional deep prospect is anticipated to be drilled
in 1997. The Company has a 1.5% working interest and a 15.2% after payout
working interest in these wells. In addition, in the shallow zones of the
Hockley and Pettus formations, the Company has drilled and developed six
producing wells which are currently producing approximately 130 Bbls/d and 180
Mcf/d net to the Company's interest. These six discoveries have resulted in
additional reserves of 0.5 Bcf of gas and 150 MBbls of oil net to the Company
as of September 30, 1996. The Company has working interests ranging from 56%
to 100% in the shallow producing wells.

Buckeye Project Area: Wilcox, Hockley, Pettus and Yegua Formations

The Buckeye Project Area is located in Live Oak County, Texas adjacent to
the Company's Tyler Project Area. The Company currently holds approximately
12,000 acres under option and is currently acquiring an approximately 20
square mile 3-D seismic survey of the area. As with the Tyler Project Area,
the exploration objectives for the Buckeye Project Area are the shallow zones
of the Hockley, Pettus and Yegua formations and the deep zones of the expanded
upper Wilcox formation. The Company plans to drill any prospects it identifies
in the shallow formations and to seek to promote any deep Wilcox prospects
identified to other energy companies for cash and a reversionary interest. The
Company has budgeted to drill 11 wells in this project area in 1997 based upon
statistical results of drilling activities in the adjoining Tyler Project Area
that the Company believes is geologically similar. The Company's lease
options, if exercised, provide for a 50% working interest and an average of
approximately 39% net revenue interest in the acreage in this project area.

Hiawatha Project Area: Pettus and Yegua Formations

The Hiawatha Project Area is located in Duval County, Texas. The majority of
past drilling and production activity occurred in the 1940s, with the most
recent well in the area being drilled in the 1970s. Although the area has
experienced limited recent exploration due to complex landowner and leasehold
owner problems, the Company has leased 11,754 acres and has options on an
additional 3,231 acres in this project area. A 23 square mile proprietary 3-D
seismic survey was obtained by the Company in August 1996 and is currently
being interpreted with multiple prospect leads under evaluation. Three wells
were completed in the project area during the fourth quarter of 1996, and an
additional well was completed in January 1997. Two additional wells are
currently scheduled to be drilled during 1997. The Company has identified at
least 10 additional prospects in various stages of development which it has
budgeted for drilling in 1997. Some of these wells are dependent upon the
results of the first four scheduled wells. The Company has an average 50%
working interest and an average 38.5% net revenue interest in the acreage
under lease in this project area.

East McFaddin Project Area: Frio Formation

The East McFaddin Project Area is located in Victoria County, Texas. In
1995, the Company obtained a 40% working interest in a 4,680 acre lease in the
project area by agreeing to conduct and pay for a 3-D seismic survey of the
project area. Subsequently, the Company expanded its leasehold acreage and
purchased options for 1,760 acres. The Company then obtained a partner to fund
an approximately 11 square mile 3-D seismic survey in exchange for 50% of the
Company's 40% interest. Two successful wells and three dry holes have been
drilled on the lease since acquisition of the 3-D seismic data. The two
successful wells produced an average of over 1.9 MMcf/d of gas during the
third quarter of 1996. The two producing wells are currently awaiting hook-up
from a low-pressure to a high-pressure pipeline, in order to increase
production rates. The 3-D seismic data was recently reprocessed and four
prospects are currently being evaluated and are scheduled to be drilled in
1997. Three additional wells have been budgeted to be drilled in 1997.

Triple "A" Project Area: Frio Formation

The Triple "A" Project Area involves the redevelopment of a mature field
located in San Patricio County, Texas. All of the prospects in this project
area are located in the normally pressured Frio trend. In 1995 the Company
acquired a 2,230 acre lease in the Triple "A" Project Area by conducting a 13
square mile 3-D seismic

37
<PAGE>

survey over the field area. An additional 600 acres has been acquired by the
Company to cover what the Company believes to be the prospective areas around
the field. The Company has recently drilled and completed the first of two
identified prospects. The well is currently producing 470 Mcf/d of gas and 10
Bbls/d of oil net to the Company's interest with net proved reserves of 0.4
Bcf of gas and 7.0 MBbls of oil as of September 30, 1996. Should the Company
identify any additional drill sites, it would expect to drill the normally
pressured prospects and, like in the Starr-Hidalgo Project Area, it would seek
to develop and sell deeper prospects for up-front cash and an after payout
working interest. The Company has an average 25% working interest and an
average 18.8% net revenue interest in the acreage under lease in this project
area.

MISSISSIPPI

Tallahala Creek Field: Cotton Valley and Smackover Formation

The Tallahala Creek Field is located in Smith County, Mississippi, and
approximately 3,240 acres are under lease. Following acquisition of the field,
improvements in operations of producing wells and several recompletions
identified by the Company in a detailed petrophysical study of the existing
wells resulted in a production increase from 180 Bbls/d of oil at the time of
acquisition in November 1994 to 370 Bbls/d of oil during the quarter ended
September 30, 1996. As of September 30, 1996, the estimated proved reserves of
this field were 1.2 MMBbls of oil and 1.5 Bcf of natural gas. In the fourth
quarter of 1995 the Company acquired a 28 square mile 3-D seismic survey over
the field. Interpretation of the 3-D data has revealed five prospects within
the field. The Company is currently drilling the first of these locations to a
depth of approximately 16,200 feet. The Company has an 18% to 23.5% working
interest and a 10.6% to 17.4% net revenue interest in the properties in this
field.

Quito Prospect: Cotton Valley and Smackover Formation

The Quito Prospect is located in Wayne County, Mississippi, and
approximately 2,760 acres are under lease. The Company identified the prospect
using 2-D seismic data and acquired 3-D seismic data in November 1996 to
better delineate the prospect. The Company believes the 3-D seismic data
indicates a structure that could potentially support four producing wells. The
Company has an average 50% working interest and an average 36.3% net revenue
interest in the acreage under lease.

ALABAMA

Barnett Project Area: Smackover Formation

The Barnett Project Area is located in Escambia County, Alabama, and
approximately 578 acres are under lease. A 20 square mile 3-D seismic survey
was acquired and interpreted in 1994, resulting in the identification of six
prospects in the Smackover Formation. Four of these prospects have been
drilled, resulting in the completion of three producing wells. Production from
the first two producing wells averaged 730 Bbls/d of oil and 825 Mcf/d of gas
during the quarter ended September 30, 1996. The third well began production
in the fourth quarter of 1996. The two remaining prospects are scheduled to be
drilled during 1997. The Company has an average 18.5% after payout working
interest and an average 13.6% after payout net revenue interest in the acreage
under lease in this project area.

LOUISIANA

South Mermentau Field

The South Mermentau Field is located in Acadia Parish, Louisiana. The
Company discovered a new natural gas reservoir in this field by drilling an
initial exploration well. A second well was drilled on an offset fault block
and was also found to be productive. The field produced approximately 9.8
MMcf/d of natural gas and 575 Bbls/d of oil during the third quarter of 1996.
The Company's net estimated proved reserves are 0.8 Bcf of

38
<PAGE>

gas and 44 Mbls of oil as of September 30, 1996. The Company is currently
attempting to permit a 3-D survey over this project area. The Company has a
15.8% working interest and an 11.3% net revenue interest in its properties in
this field.

SIGNIFICANT FULLY DEVELOPED PROPERTIES

In addition to its exploration project areas, the Company has interests in
the following significant development properties. No exploration is expected
to be conducted on such properties. The reserve data set forth below for the
properties is based on the Ryder Scott Report. There are numerous
uncertainties in estimating quantities of proved reserves, including many
factors beyond the control of the Company. See "Risk Factors--Uncertainty of
Reserve Information and Future Net Revenue Estimates."

South Maurice Field

South Maurice Field is located in Vermillion Parish, Louisiana, and is the
largest single discovery made to date by the Company. The field has produced
approximately 80 Bcf of gas since its discovery by the Company in 1987 and was
producing 21.4 MMcf/d of gas and 120 Bbls/d of oil as of September 30, 1996.
The Company distributed most of its interests in this field to its former
equity holders, but still retains a 2.7% working interest and a 2.0% average
net revenue interest with proved reserves of 0.4 Bcfe attributable to the
Company as of September 30, 1996.

North Excel Field

The North Excel Field is located in Monroe County, Alabama, and
approximately 769 acres are under lease. The North Excel Field was discovered
by the Company in November 1994. During 1994, a 3-D seismic survey was
acquired and interpreted within the Frisco City Sands and the Norphlet Sands.
Four producing wells have been completed in the field, which produced 790
Bbls/d of oil and 4,700 Mcf/d of gas during the quarter ended September 30,
1996 with estimated proved reserves of 188 MBbls of oil and 0.5 Bcf of gas as
of September 30, 1996. The Company believes that the North Excel Field is
fully drilled and offers the potential for increased reserves solely from
operational and engineering improvements. The Company has a 13% after payout
working interest in the acreage under lease in this field, with approximately
$700,000 remaining until payout as of September 30, 1996.

ESSEX ROYALTY PROPERTIES

The Company is the managing venturer of two joint ventures (the "Essex
Royalty Joint Ventures") that have acquired royalty, overriding royalty, net
profits and other non-operating interests with respect to producing and non-
producing properties located in Louisiana, Texas, Alabama, Mississippi, New
Mexico and Oklahoma.

Pursuant to the joint venture agreements for the Essex Royalty Joint
Ventures, the Company, as managing venturer, receives certain management fees.
In addition, after the other participants in each of the two Essex Royalty
Joint Ventures receive distributions equivalent to 110% and 111.3%,
respectively, of their capital contributions, the Company will receive 40% and
25%, respectively, of the profits, losses and distributions of the Essex
Royalty Joint Ventures. As of September 30, 1996, approximately $1.2 million
and $2.4 million remained until payout with respect to the two Essex Royalty
Joint Ventures. The Company is currently in the process of attempting to cure
title defects with respect to a property with accrued revenue in suspense of
approximately $325,000 as of September 30, 1996 with respect to the Essex
Royalty Joint Venture with $2.4 million remaining until payout. For a more
extensive discussion of the joint venture agreements with respect to the Essex
Royalty Joint Ventures, see "Certain Transactions--Essex Royalty Joint
Ventures."

From its inception in 1992 through September 30, 1996, in addition to the
payment of management fees, the Essex Royalty Joint Ventures made
distributions of $2.2 million, all of which, pursuant to the sharing ratios
described above, were distributed to the other participants in the Essex
Royalty Joint Ventures.

39
<PAGE>

OIL AND NATURAL GAS RESERVES

The following table sets forth estimated net proved oil and natural gas
reserves of the Company and the present value of estimated future pretax net
cash flows related to such reserves as of September 30, 1996. The reserve data
and the present value as of September 30, 1996 were prepared by Ryder Scott.
For further information concerning Ryder Scott's estimate of the proved
reserves of the Company at September 30, 1996, see Ryder Scott's letter
included as Annex A to this Prospectus. The present value of estimated future
net revenues before income taxes was prepared using constant prices as of the
calculation date, discounted at 10% per annum on a pretax basis, and is not
intended to represent the current market value of the estimated oil and
natural gas reserves owned by the Company. For further information concerning
the present value of future net revenue from these proved reserves, see Note 9
of Notes to Combined Financial Statements. Also see "Risk Factors--Uncertainty
of Reserve Information and Future Net Revenue Estimates."

<TABLE>
<CAPTION>
PROVED RESERVES
-----------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Oil and condensate (MBbls).................... 789 42 831
Natural gas (MMcf)............................ 10,985 2,579 13,564
Total proved reserves (MMcfe)................. 15,719 2,831 18,550
Present value of estimated future net revenues
before income taxes(1)....................... $23,024 $2,632 $25,656
</TABLE>
- --------
(1) The present value of estimated future pretax net cash flows as of
September 30, 1996 was determined by using the September 30, 1996 weighted
average sales prices of $21.17 per Bbl of oil and $2.01 per Mcf of natural
gas. By comparison, the present value of estimated future pretax net cash
flows as of December 31, 1995 was determined by using the weighted average
sales prices that were being realized as of that date of $17.77 per Bbl of
oil and $2.12 per Mcf of natural gas.

There are numerous uncertainties inherent in estimating quantities of proved
oil and natural gas reserves and in projecting future rates of production and
timing of development expenditures, including many factors beyond the control
of the producer. The reserve data set forth herein represents estimates only.
Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact way,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
As a result, estimates made by different engineers often vary from one
another. In addition, results of drilling, testing and production subsequent
to the date of an estimate may justify revision of such estimates, and such
revisions may be material. Accordingly, reserve estimates are generally
different from the quantities of oil and natural gas that are ultimately
recovered. Furthermore, the estimated future net revenues from proved reserves
and the present value thereof are based upon certain assumptions, including
future prices, production levels and costs, that may not prove correct.

No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Commission.

The prices used in calculating the estimated future net revenue attributable
to proved reserves do not necessarily reflect market prices for oil and
natural gas production subsequent to September 30, 1996. There can be no
assurance that all of the proved reserves will be produced and sold within the
periods indicated, that the assumed prices will actually be realized for such
production or that existing contracts will be honored or judicially enforced.

40
<PAGE>

VOLUMES, PRICES AND OIL & GAS OPERATING EXPENSE

The following table sets forth certain information regarding the production
volumes of, average sales prices received for and average production costs
associated with the Company's sales of oil and natural gas for the periods
indicated.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
NINE MONTHS ENDED
1993 1994 1995 SEPTEMBER 30, 1996
------- ------- ------- ------------------
<S> <C> <C> <C> <C>
PRODUCTION:
Oil and condensate (MBbls)..... 26 61 66 81
Gas (MMcf)..................... 457 588 565 1,557
Total (MMcfe).................. 611 952 959 2,044
AVERAGE SALES PRICE:
Oil and condensate ($ per
MBbl)......................... $ 17.52 $ 17.66 $ 16.43 $19.49
Gas ($ per MMcf)............... 2.20 1.57 1.70 2.26
Average Oil & Gas Operating
Expense ($ per MMcfe)(1)...... 0.27 0.32 0.72 0.35
</TABLE>
- --------
(1) Includes direct lifting costs (labor, repairs and maintenance, materials
and supplies), workover costs and the administrative costs of production
offices, insurance and property and severance taxes.

FINDING AND DEVELOPMENT COSTS

The following table sets forth certain information regarding the costs
associated with finding, acquiring and developing the Company's proved oil and
natural gas reserves.

<TABLE>
<CAPTION>
COST TO
FIND AND
RESERVES DEVELOP
CAPITALIZED ADDED (PER
COSTS(1) (MCFE)(2) MCFE)
----------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
1993...................................... $ 555 1,497 $0.37
1994...................................... 935 1,081 0.86
1995...................................... 3,883 7,916 0.49
1996 (through September 30)............... 3,792 7,071 0.54
------ ------
January 1, 1993 through September 30,
1996..................................... $9,165 17,565 $0.52
====== ======
</TABLE>
- --------
(1) Capitalized costs represent all capitalized expenditures of the Company
excluding acquisition costs for unproved prospects as shown in the table
under the caption "--Development, Exploration and Acquisition Capital
Expenditures."
(2) Reserves added equals the extensions and discoveries on an Mcfe basis. See
Note 8 to the unaudited Combined Financial Statements.

41
<PAGE>

DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES

The following table sets forth certain information regarding the capitalized
costs incurred in the purchase of proved and unproved properties and in
development and exploration activities.

<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------- -----------------
1993 1994 1995 1995 1996
------- ------- ------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Acquisition Costs:
Unproved prospects............ $ 2,914 $ 5,497 $ 3,659 $3,695 $3,309
Proved properties............. 7 26 91 91 36
Exploration..................... 527 670 2,642 1,122 2,052
Development..................... 21 238 1,150 297 1,714
------- ------- ------- -------- --------
Total capitalized costs..... $ 3,469 $ 6,431 $ 7,542 $5,205 $7,111
======= ======= ======= ======== ========
</TABLE>

DRILLING ACTIVITY

The following table sets forth the drilling activity of the Company for the
years ended December 31, 1993, 1994 and 1995 and for the nine months ended
September 30, 1996. In the table, "gross" refers to the total wells in which
the Company has a working interest and "net" refers to gross wells multiplied
by the Company's working interest therein. Wells in which the Company holds a
reversionary interest are not included in the following table because such
interests had not been earned at the time of drilling. The percentage of the
Company's wells in which it holds solely a reversionary interest has decreased
in the last two years.

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
NINE MONTHS
ENDED
1993 1994 1995 SEPTEMBER 30, 1996
--------- --------- ----------- --------------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ----- --------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Exploratory Wells
Productive........... 3 .07 4 .09 17 8.66 24 11.92
Nonproductive........ 8 .20 4 .10 12 4.64 9 2.55
--- --- --- --- --- ----- -------- ----------
Total.............. 11 .27 8 .19 29 13.30 33 14.47
Development Wells
Productive........... 1 -- 5 .23 5 .20 -- --
Nonproductive........ -- -- -- -- 1 .01 1 .20
--- --- --- --- --- ----- -------- ----------
Total.............. 1 -- 5 .23 6 .21 1 .20
</TABLE>
- --------
* An additional 1 gross (.004 net) exploratory well drilled in 1996 was
awaiting completion at September 30, 1996 and could not yet be classified
as productive or nonproductive.

Since September 30, 1996, the Company has drilled 6 gross productive
exploratory wells (3.47 net). The Company is currently drilling or evaluating
1 gross exploratory well (.25 net) and 1 gross development well (.22 net).

PRODUCTIVE WELLS

The following table sets forth the number of productive oil and natural gas
wells in which the Company owned an interest as of September 30, 1996.

<TABLE>
<CAPTION>
COMPANY-
OPERATED OTHER TOTAL
----------- ----------- -----------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Oil................................... 3 1.66 31 5.57 34 7.23
Natural gas........................... 19 13.27 32 5.95 51 19.22
--- ----- --- ----- --- -----
Total............................. 22 14.93 63 11.52 85 26.45
</TABLE>

42
<PAGE>

ACREAGE DATA

The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of September 30, 1996. Developed
acres refers to acreage within producing units and undeveloped acres refers to
acreage that has not been placed in producing units.

<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES
---------------- -----------------
GROSS NET GROSS NET
-------- ------- -----------------
<S> <C> <C> <C> <C>
Alabama................................ 2,925 157 7,712 1,262
Louisiana.............................. 2,841 315 117 97
Mississippi............................ 2,660 87 6,041 747
Texas.................................. 30,486 7,740 50,512 14,451
-------- ------- -------- --------
Total.............................. 38,912 8,299 64,382 16,557
======== ======= ======== ========
</TABLE>

Leases covering approximately 11,828 gross (1,754 net), 16,524 gross (5,140
net), 22,707 gross (4,316 net), 1,822 gross (196 net) and 1,604 gross (161
net) undeveloped acres are scheduled to expire in 1996, 1997, 1998, 1999 and
2000, respectively.

The table does not include 59,562 gross (29,781 net) acres that the Company
has a right to acquire pursuant to various seismic option agreements. In
addition, the Company is expected to acquire options on an additional 37,900
acres pursuant to various seismic option agreements by December 31, 1997.

MARKETING

The Company's production is marketed to third parties consistent with
industry practices. Typically, oil is sold at the wellhead at field-posted
prices and natural gas is sold under contract at a negotiated price based upon
factors normally considered in the industry, such as distance from the well to
the pipeline, well pressure, estimated reserves, quality of natural gas and
prevailing supply/demand conditions.

The Company's marketing objective is to receive the highest possible
wellhead price for its product. The Company is aided by the presence of
multiple outlets near its production in the Gulf Coast. The Company takes an
active role in determining the available pipeline alternatives for each
property based upon historical pricing, capacity, pressure, market
relationships, seasonal variances and long-term viability.

There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and
natural gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and natural gas, the marketing of
competitive fuels and the effects of state and federal regulations on oil and
natural gas production and sales. The Company has not experienced any
difficulties in marketing its oil and natural gas. The oil and natural gas
industry also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual customers.

The Company markets its own production where feasible with a combination of
market-sensitive pricing and forward-fixed pricing. Forward pricing is
utilized to take advantage of anomalies in the futures market and to hedge a
portion of the Company's production deliverability at prices exceeding
forecast. All of such hedging transactions provide for financial rather than
physical settlement. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--General Overview."

Despite the measures taken by the Company to attempt to control price risk,
the Company remains subject to price fluctuations for natural gas sold in the
spot market due primarily to seasonality of demand and other factors beyond
the Company's control. Domestic oil prices generally follow worldwide oil
prices, which are subject to price fluctuations resulting from changes in
world supply and demand. The Company continues to evaluate the potential for
reducing these risks by entering into, and expects to enter into, additional
hedge

43
<PAGE>

transactions in future years. In addition, the Company may also close out any
portion of hedges that may exist from time to time as determined to be
appropriate by management. As of December 31, 1996, there were no existing
hedge positions. Total Mcfs of natural gas purchased and sold under swap
arrangements during the nine month period ended September 30, 1996 and the
year ended December 31, 1995 were 182,000 Mcf and 62,000 Mcf, respectively.
Gains and losses realized by the Joint Venture under such swap arrangements
were $5,270 and $(15,720) for the nine month period ended September 30, 1996
and the year ended December 31, 1995, respectively. There was no hedging
activity in 1994 or 1993.

COMPETITION

REGULATION

The availability of a ready market for oil and gas production depends upon
numerous factors beyond the Company's control. These factors include
regulation of natural gas and oil production, federal and state regulations
governing environmental quality and pollution control, state limits on
allowable rates of production by well or proration unit, the amount of natural
gas and oil available for sale, the availability of adequate pipeline and
other transportation and processing facilities and the marketing of
competitive fuels. For example, a productive natural gas well may be "shut-in"
because of an oversupply of natural gas or lack of an available natural gas
pipeline in the areas in which the Company may conduct operations. State and
federal regulations generally are intended to prevent waste of natural gas and
oil, protect rights to produce natural gas and oil between owners in a common
reservoir, control the amount of natural gas and oil produced by assigning
allowable rates of production and control contamination of the environment.
Pipelines are subject to the jurisdiction of various federal, state and local
agencies. The following discussion summarizes the regulation of the United
States oil and gas industry. The Company believes that it is in substantial
compliance with such statutes, rules, regulations and governmental orders,
although there can be no assurance that this is or will remain the case. The
following discussion is not intended to constitute a complete discussion of
the various statutes, rules, regulations and governmental orders to which the
Company's operations may be subject.

REGULATION OF NATURAL GAS AND OIL EXPLORATION AND PRODUCTION. The Company's
operations are subject to various types of regulation at the federal, state
and local levels. Such regulation includes requiring permits for the drilling
of wells, maintaining bonding requirements in order to drill or operate wells
and regulating the location of wells, the method of drilling and casing wells,
the surface use and restoration of properties upon which wells are drilled in,
the plugging and abandoning of wells and the disposal of fluids used in
connection with operations. The Company's operations are also subject to
various conservation laws and regulations. These

44
<PAGE>

include the regulation of the size of drilling and spacing units or proration
units and the density of wells which may be drilled in and the unitization or
pooling of oil and gas properties. In this regard, some states allow the forced
pooling or integration of tracts to facilitate exploration while other states
rely primarily or exclusively on voluntary pooling of lands and leases. In
areas where pooling is voluntary, it may be more difficult to form units, and
therefore, more difficult to develop a project if the operator owns less than
100% of the leasehold. In addition, state conservation laws establish maximum
rates of production from oil and natural gas wells, generally prohibit the
venting or flaring of natural gas and impose certain requirements regarding the
ratability of production. The effect of these regulations may limit the amount
of oil and natural gas the Company can produce from its wells and may limit the
number of wells or the locations at which the Company can drill. The regulatory
burden on the oil and gas industry increases the Company's costs of doing
business and, consequently, affects its profitability. Inasmuch as such laws
and regulations are frequently expanded, amended and reinterpreted, the Company
is unable to predict the future cost or impact of complying with such
regulations.

FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS. Historically,
the transportation and sale for resale of natural gas in interstate commerce
have been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the
Natural Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission (the "FERC"). Maximum
selling prices of certain categories of natural gas sold in "first sales,"
whether sold in interstate or intrastate commerce, were regulated pursuant to
the NGPA. On July 26, 1989, the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act") was enacted, which removed, as of not later than January 1,
1993, all remaining federal price controls from natural gas sold in "first
sales." The FERC's jurisdiction over natural gas transportation was unaffected
by the Decontrol Act.

Historically, producers typically sold their production to intrastate and
interstate pipelines, which then functioned as the wholesalers selling to the
local distributors and other end-use customers. However, in April 1992, the
FERC issued Order No. 636, a rule designed to restructure the interstate
natural gas transportation and marketing system and remove various barriers and
practices that have historically limited non-pipeline natural gas sellers,
including producers, from effectively competing with interstate pipelines for
sales to local distribution companies and large industrial and commercial
customers. The most significant provisions of Order No. 636: (a) require that
interstate pipelines provide firm and interruptible transportation solely on an
"unbundled" basis, separate from their sales service, and convert each
pipeline's bundled firm sales service into unbundled firm transportation
service; (b) provide for the issuance of blanket certificates to pipelines to
provide unbundled sales service, giving all customers a chance to purchase
their firm supplies from nonpipeline merchants (see the discussion of Order No.
547 below); (c) require that pipelines provide firm and interruptible
transportation service on a basis that is equal in quality for all natural gas
supplies, whether purchased from the pipeline or elsewhere; (d) require that
pipelines provide new, nondiscriminatory "no-notice" transportation for certain
of their traditional sales customers that largely replicates the "bundled"
sales service previously provided by pipelines; (e) establish two new generic
programs for the reallocation of firm pipeline capacity; (f) require that all
pipelines offer access to their storage facilities on a firm and interruptible
basis; (g) provide for pregranted abandonment of pipeline sales agreements,
interruptible and short-term (defined as one year or less) transportation
agreements and conditional pregranted abandonment of long-term transportation
service; (h) modify transportation rate design by requiring that all fixed
costs related to transportation be recovered through the reservation charge;
and (i) provide mechanisms for the recovery by pipelines of certain types of
costs likely to occur from implementation of Order No. 636. The restructuring
process has been implemented on a pipeline-by-pipeline basis through
negotiations in individual pipeline proceedings. All of the interstate
pipelines have filed their Order No. 636 compliance plans with the FERC and
most have had those plans approved, subject to certain conditions and subject
to appeals to the reviewing court respecting various issues. Since the issuance
of Order No. 636, the FERC has issued two orders making relatively minor
modifications to Order No. 636. Numerous parties have filed for judicial review
of Order No. 636 as well as for judicial review of the FERC's orders approving
restructuring plans for various individual pipelines. The United States Court
of Appeals for the District of Columbia Circuit (the "Court") recently issued
its decision in the appeal of Order No. 636. The Court largely upheld the basic
tenets of Order No. 636, including the requirements that interstate pipelines
"unbundle" their sales of gas from transportation and that pipelines provide
open-access transportation on a basis that is equal for all gas supplies. The
Court remanded five relatively narrow issues for further explanation by the
FERC. In doing

45
<PAGE>

so, the Court made it clear that the FERC's existing rules on the remanded
issues would remain in effect pending further consideration. The Court's
decision is still subject to rehearing and parties could potentially petition
for writ of certiorari to the United States Supreme Court. It is not possible
to predict what effect, if any, the ultimate outcome of this judicial review
process or the other appeals still pending in individual pipeline restructuring
proceedings will have on the FERC's open-access regulations or on the Company.

For decades, the principal methodology used to set pipeline rates has been
based on the actual cost to provide that service. In recent years, regulators
have concluded that sufficient competition may exist in certain markets to
allow a relaxation of this historic approach. In January 1996, the FERC issued
a statement of policy and a request for comments concerning alternatives to its
traditional cost-of-service ratemaking methodology to establish the rates
interstate pipelines may charge for their services. The policy statement
articulates the criteria that the FERC will use to evaluate proposals to charge
market-based rates for the transportation of natural gas. The policy statement
also provides that the FERC will consider proposals for negotiated rates for
individual shippers of natural gas, so long as a cost-of-service-based rate is
available to the customer to protect against abuse. The FERC requested comments
on whether it should allow gas pipelines the flexibility to negotiate the terms
and conditions of transportation service with prospective shippers. The Company
cannot predict what further action the FERC will take on these matters;
however, the Company does not believe that it will be affected by any action
taken materially differently than other natural gas producers, gatherers and
marketers with which it competes.

The FERC recently issued a notice of proposed rulemaking ("NOPR") pursuant to
which it proposes to substantially revise its regulations regarding releases of
firm interstate pipeline capacity. In the NOPR, the FERC proposes to (i)
require pipelines to have comparable procedures for capacity release
transactions and interruptible transportation transactions; (ii) allow
replacement shippers to release capacity in segments and change primary receipt
and delivery points; (iii) eliminate the requirement to bid on release
transactions; and (iv) lift the price cap for released capacity, interruptible
transportation, and short-term firm pipeline capacity in markets where the
shipper or the pipeline demonstrates a lack of market power. Simultaneously
with the issuance of the NOPR, the FERC issued an order establishing an
experimental pilot program that would implement certain provisions of the NOPR
during the 1996-97 winter heating season. The FERC intends the pilot programs
to help in determining whether the criteria in the NOPR is indicative of a lack
of market power. The Company cannot predict what further action the FERC will
take on these matters; however, the Company does not believe that it will be
affected by any action taken materially differently than other natural gas
producers, gatherers and marketers with which it competes.

In May 1995, the FERC issued a policy statement on how interstate 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.

Commencing in May 1994, the FERC issued a series of orders in individual
cases that delineate a new gathering policy in light of the interstate pipeline
industry's restructuring under Order No. 636. As a general matter, gathering is
exempt from the FERC's jurisdiction; however, the courts have held that where
the gathering is performed by the interstate pipelines in association with the
pipeline's jurisdictional transportation activities, the FERC retains
regulatory control over the associated gathering services to prevent abuses.
Among other matters, the FERC slightly narrowed its statutory tests for
establishing gathering status and reaffirmed that, except in situations in
which the gatherer acts in concert with an interstate pipeline affiliate to
frustrate the FERC's transportation policies, the FERC does not generally have
jurisdiction over natural gas gathering facilities and services. In the FERC's
opinion, such facilities and services are more properly regulated by state
authorities. In addition, the FERC has approved several transfers proposed by
interstate pipelines of gathering facilities to unregulated independent or
affiliated gathering companies. Certain of the FERC's orders delineating its
new gathering policy recently were the subject of an opinion issued by the
Court. That opinion generally upheld the FERC's policy of approving the
interstate pipeline's proposed "spindown" of its gathering facilities to an
unregulated affiliate company, but reversed and remanded to the FERC that
portion of the FERC's orders

46
<PAGE>

imposing so-called "default contracts" by which the unregulated affiliate was
obligated to continue existing gathering services to customers under "default
contracts" for up to two years after spindown. It remains unclear whether the
FERC will attempt to reimpose such conditions or will otherwise act in response
to producer requests for additional protection against perceived monopolistic
action by pipeline-related gatherers. In addition, in February 1996, the FERC
issued a policy statement that, among other matters, reaffirmed, with some
clarifications, its long-standing test for determining whether particular
pipeline facilities perform a jurisdictional transmission function or non
jurisdictional gathering function. While changes to the FERC's gathering policy
affect the Company only indirectly, such changes could affect the price and
availability of capacity on certain gathering facilities, and thus access to
certain interstate pipelines, which, in turn, could affect the price of gas at
the wellhead and in markets in which the Company competes. However, the Company
does not believe that it will be affected by these changes to the FERC's
gathering policy materially differently than other natural gas producers with
which it competes.

In December 1992, the FERC issued Order No. 547, governing the issuance of
blanket marketer sales certificates to all natural gas sellers other than
interstate pipelines. The order applies to non-first sales that remain subject
to the FERC's NGA jurisdiction. Among other things, the order eliminates the
need for natural gas producers and marketers to seek specific authorization
under Section 7 of the NGA from the FERC to make sales of natural gas for
resale. Instead, effective January 7, 1993, these natural gas sellers, by
operation of the order, were issued blanket certificates of public convenience
and necessity allowing them to make jurisdictional natural gas sales for resale
at negotiated rates without seeking specific FERC authorization, thus allowing
such sellers to compete with sellers making deregulated first sales. The FERC
intends Order 547, in tandem with Order No. 636, to foster a competitive market
for natural gas by giving natural gas purchasers access to multiple supply
sources at market-driven prices. Order No. 547 may increase competition in
markets in which the Company's natural gas is sold.

In October 1992, the Energy Policy Act of 1992 was enacted. This Act
streamlined the permitting process necessary to import Canadian natural gas and
altered the treatment of such gas under the NGPA, eliminating the FERC's
jurisdiction over the price of non-pipeline sales of natural gas imported from
Canada. Canadian natural gas imports still require import authorizations from
the Department of Energy's Office of Fossil Energy under Section 3 of the NGA
and construction and siting authorizations, where applicable, from the FERC.
These changes could enhance the ability of Canadian producers to export natural
gas to the United States and increase competition in the domestic natural gas
market.

Commencing in October 1993, the FERC has modified its regulation of oil
pipeline rates and services in order to comply with the Energy Policy Act of
1992. That Act mandated the FERC to streamline oil pipeline ratemaking by
abandoning its old, cumbersome procedures. It also grandfathered certain
existing rates. To respond to the statute, the FERC issued a series of rules
(Order Nos. 561 and 561-A) establishing an indexing system under which oil
pipelines will be able to change their transportation rates, subject to
prescribed ceiling levels. The indexing system, which allows or may require
pipelines to make rate changes to track changes in the Producer Price Index for
Finished Goods, minus one percent, became effective January 1, 1995. The FERC's
decision in these matters was recently affirmed by the Court. The Company is
not able at this time to predict the effects of Order Nos. 561 and 561-A, if
any, on the transportation costs associated with oil production from the
Company's oil producing operations.

Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.

OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate
and gas liquids by the Company are not currently regulated and are made at
market prices. The FERC has issued an order establishing an indexing system for
transportation rates for oil that could increase the cost of transporting oil
to the purchaser. Because this order is subject to administrative and judicial
review, the Company is not able to predict what effect, if any, this order will
have on it.

ENVIRONMENTAL REGULATIONS. The Company's operations are subject to numerous
laws and regulations governing the discharge of materials into the environment
or otherwise relating to environmental protection.

47
<PAGE>

Public interest in the protection of the environment has increased
dramatically in recent years. The trend of more expansive and stricter
environmental legislation and regulations could continue. To the extent laws
are enacted or other governmental action is taken that restricts drilling or
imposes environmental protection requirements that result in increased costs
to the oil and gas industry in general, the business and prospects of the
Company could be adversely affected.

The Company generates wastes, including hazardous wastes, that are subject
to the federal Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes. The EPA and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes.
Furthermore, certain wastes generated by the Company's oil and natural gas
operations that are currently exempt from treatment as "hazardous wastes" may
in the future be designated as "hazardous wastes," and therefore be subject to
more rigorous and costly operating and disposal requirements.

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

The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted in
1990 and contain provisions that may result in the gradual imposition of
certain pollution control requirements with respect to air emissions from the
operations of the Company. The EPA and states have been developing regulations
to implement these requirements. The Company may be required to incur certain
capital expenditures in the next several years for air pollution control
equipment in connection with maintaining or obtaining operating permits and
approvals addressing other air emissionrelated issues. However, the Company
does not believe its operations will be materially adversely affected by any
such requirements.

Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control, countermeasure and response plans relating to the
possible discharge of oil into surface waters. The Oil Pollution Act of 1990,
as amended ("OPA"), contains numerous requirements relating to the prevention
of and response to oil spills into waters of the United States. The OPA
subjects owners of facilities to strict joint and several liability for all
containment and cleanup costs and certain other damages arising from a spill,
including, but not limited to, the costs of responding to a release of oil to
surface waters. The OPA also requires owners and operators of offshore
facilities that could be the source of an oil spill into waters of the United
States, including wetlands, to post a bond, letter of credit or other form of
financial assurance in the amount of $35 million, subject to later increase to
as much as $150 million if a formal risk assessment indicates that the
increase is warranted, to cover costs that could be incurred by governmental
authorities in responding to an oil spill. In addition to OPA, other federal
and state laws for the control of water pollution also provide varying civil
and criminal penalties and liabilities in the case of releases of petroleum or
its derivatives into surface waters or into the ground. Regulations are
currently being developed under OPA and state laws concerning oil pollution
prevention and other matters that may impose additional regulatory burdens on
the Company. In addition, the CWA and analogous state laws require permits to
be obtained to authorize discharge into surface waters or to construct
facilities in wetland areas. With respect to certain of its operations, the
Company is required to maintain such permits or meet general permit
requirements. The EPA recently adopted regulations concerning discharges of
storm water runoff. This program requires covered facilities to obtain
individual permits, participate in a group permit or seek coverage under an
EPA

48
<PAGE>

general permit. The Company believes that it will be able to obtain, or be
included under, such permits, where necessary, and minor modifications to
existing facilities and operations that would not have a material effect on
the Company.

The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, and similar state laws impose
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that are considered to have contributed to the
release of a "hazardous substance" into the environment. These persons include
the owner or operator of the disposal site or sites where the release occurred
and companies that disposed or arranged for the disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources, and it is
not uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by the hazardous
substances released into the environment.

The Company also is subject to a variety of federal, state and local
permitting and registration requirements relating to protection of the
environment. Management believes that the Company is in substantial compliance
with current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse effect
on the Company.

OPERATING HAZARDS AND INSURANCE

The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosion, blow-out, pipe failure, casing
collapse, abnormally pressured formations and environmental hazards such as
oil spills, gas leaks, ruptures and discharges of toxic gases, the occurrence
of any of which could result in substantial losses to the Company due to
injury or loss of life, severe damage to or destruction of property, natural
resources and equipment, pollution or other environmental damage, cleanup
responsibilities, regulatory investigation and penalties and suspension of
operations.

In accordance with customary industry practice, the Company maintains
insurance against some, but not all, of the risks described above. The
Company's insurance does not cover business interruption or protect against
loss of revenues. There can be no assurance that any insurance obtained by the
Company will be adequate to cover any losses or liabilities. The Company
cannot predict the continued availability of insurance or the availability of
insurance at premium levels that justify its purchase. The occurrence of a
significant event not fully insured or indemnified against could materially
and adversely affect the Company's financial condition and operations.

TITLE TO PROPERTIES

The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and
natural gas industry. The Company's properties are subject to customary
royalty interests, liens incident to operating agreements, liens for current
taxes and other burdens which the Company believes do not materially interfere
with the use of or affect the value of such properties. As is customary in the
industry in the case of undeveloped properties, little investigation of record
title is made at the time of acquisition (other than a preliminary review of
local records). Investigations, including a title opinion of local counsel,
are generally made before commencement of drilling operations. The Revolving
Credit Facility is secured by substantially all of the Company's oil and
natural gas properties.

EMPLOYEES

At September 30, 1996, the Company had approximately 27 full-time and three
part-time employees, primarily professionals, including five
geologists/geophysicists, two data visualization geoscientists and two
engineers. The Company believes that its relationships with its employees are
good. None of the Company's

49
<PAGE>

employees are covered by a collective bargaining agreement. From time to time,
the Company utilizes the services of independent consultants and contractors
to perform various professional services, particularly in the areas of
construction, design, well site surveillance, permitting and environmental
assessment. Field and on-site production operation services, such as pumping,
maintenance, dispatching, inspection and testing, are generally provided by
independent contractors.

LEGAL PROCEEDINGS

From time to time the Company is a party to various legal proceedings
arising in the ordinary course of business. The Company is not currently a
party to any litigation that it believes could have a material adverse effect
on the financial position of the Company.

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<PAGE>

MANAGEMENT

DIRECTORS, EXECUTIVE OFFICERS AND OTHER KEY EMPLOYEES

Following the completion of the Combination Transactions and this Offering,
the officers, directors and key employees of the Company will be substantially
the same as those of Old Edge, immediately prior to such events. The following
table sets forth certain information with respect to directors, executive
officers and certain employees of the Company, together with their ages (as of
January 1, 1997) and positions:

<TABLE>
<CAPTION>
DIRECTOR'S
TERM
NAME AGE POSITION ENDING
---- --- -------- ----------
<S> <C> <C> <C>
Executive Officers and
Directors:
John E. Calaway........ 39 Chief Executive Officer and Chairman of the 2000
Board
James D. Calaway....... 39 President and Director 2000
Michael G. Long........ 44 Chief Financial Officer
Richard S. Dale........ 41 Controller, Treasurer and Secretary
Vincent Andrews........ 56 Director 1999
David B. Benedict...... 57 Director 1999
Nils P. Peterson....... 60 Director 1999
Stanley S. Raphael..... 61 Director 1998
John Sfondrini......... 48 Director 2000
Robert W. Shower....... 59 Director* 1998
Other Key Employees:
David L. Blake......... 35 Director of Exploration
Mark J. Gabrisch....... 36 Director of Land
John O. Hastings, Jr... 36 Director of Exploration
John O. Tugwell........ 33 Director of Production Engineering
</TABLE>
- --------
*Mr. Shower will become a director of the Company following the completion of
this Offering.

The Company's Board of Directors is divided into three classes with
staggered terms of office, initially ending as set forth above. Thereafter,
the term for each class will expire on the date of the third annual
stockholders' meeting for the election of directors following the most recent
election of directors for such class. Each director holds office until the
next annual meeting of stockholders for the election of directors of his class
and until his successor has been duly elected and qualified. The 1997 Annual
Meeting of Stockholders will be held prior to the completion of this Offering.
Officers serve at the discretion of the Board of Directors.

The Board of Directors will have three standing committees: the Audit
Committee, the Compensation Committee and the Nominating Committee.

JOHN E. CALAWAY is the Chief Executive Officer and Chairman of the Board of
the Company. He was a founder of the predecessor of Old Edge and has served as
the Chief Executive Officer and Chairman of the Board of Old Edge or its
predecessor since 1986. Mr. John E. Calaway has more than 20 years of
experience in the oil and natural gas exploration and production business.

JAMES D. CALAWAY is the President and a director of the Company. He served
as a director of Old Edge since April 1991. Since January 1994, Mr. James D.
Calaway has served as Special Advisor to Old Edge. From 1989 to January 1994,
Mr. James D. Calaway was primarily engaged in the organization and
capitalization of several high technology companies, including The Forefront
Group, Inc. Prior thereto, he served as Vice President of Business Development
for Space Industries International, Inc., a company he co-founded in 1982 that
develops, fabricates, integrates and operates spacecraft and spaceflight
equipment. Mr. James D. Calaway received a B.A. in Economics from the
University of Texas and an M.A. in Politics, Philosophy and Economics from
Oxford University.

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<PAGE>

MICHAEL G. LONG is the Chief Financial Officer of the Company and has held
this position since December 1996. Mr. Long served as Vice President--Finance
of W&T Offshore, Inc., an oil and gas exploration and production company, from
July 1995 to December 1996. From May 1994 to July 1995, he served as Vice
President of the Southwest Petroleum Division for Chase Manhattan Bank, N.A.
Prior thereto, he served in various capacities with First National Bank of
Chicago, most recently that of Vice President and Senior Corporate Banker of
the Energy and Transportation Department, from March 1992 to May 1994. Mr.
Long received a B.A. in Political Science and an M.S. in Economics from the
University of Illinois.

RICHARD S. DALE is the Controller, Treasurer and Secretary of the Company.
He has held the same positions with Old Edge and its predecessor since 1986.
Prior thereto, Mr. Dale was a Senior Accountant at the public accounting firm
of Kares & Cihlar and a staff accountant with Texaco Inc. He is a Certified
Public Accountant, a member of the American Institute of Certified Public
Accountants and holds a B.B.A. in Accounting from the University of
Mississippi.

VINCENT ANDREWS is a director of the Company and has served as a director of
Old Edge since April 1991. Mr. Andrews has, for more than five years, served
as President of Vincent Andrews Management Corporation, a privately held
investment company primarily involved in personal financial management. He
received a B.S. in Business Administration from Georgetown University. In
1994, Mr. Andrews and Vincent Andrews Management Corporation, a company of
which Mr. Andrews is the President, each filed a voluntary petition for
reorganization pursuant to Chapter 11 of the United States Bankruptcy Code.

DAVID B. BENEDICT is a director of the Company. He was appointed a director
of Old Edge in March 1995, and has been an active investor in Old Edge and its
predecessor since 1983. Since 1987, Mr. Benedict has served as Managing
Director of Capital Markets for First Albany Corporation, an investment
banking and brokerage firm. Prior thereto, he served in various capacities
with other investment banking firms, including Dillon Read & Company, Bear
Stearns Companies Inc. and Oppenheimer Capital L.P. Mr. Benedict holds a B.A.
and a B.S. in Metallurgical Engineering from Lehigh University.

NILS P. PETERSON is a director of the Company and has served as a director
of Old Edge since March 1995. Since January 1991 he has been primarily engaged
as a private investor and formerly served as a director of the Eastern
Bancorp, Inc. and the Boston Mutual Life Insurance Co. Prior thereto, he was
Chief Investment Officer of the Harvard Management Company, investment manager
of the Harvard University endowment funds.

STANLEY S. RAPHAEL is a director of the Company and has served as a director
of Old Edge since April 1991. For more than five years, Mr. Raphael has been
primarily engaged as a private investor and is presently a director of
American Polymers Inc., a polystyrene manufacturer, Big City Bagels Inc., a
publicly held bagel store franchisor, and Trade Consultants, Inc., a
management consulting firm. Previously, he was active in trading crude oil,
petroleum products, LPG, petrochemicals, and plastics worldwide. Mr. Raphael
received a B.B.A. in Foreign Trade and Economics from the City College of New
York.

JOHN SFONDRINI is a director of the Company and has served as a director of
Old Edge or its predecessor since 1986, when he arranged for the
capitalization of the Joint Venture's predecessor. For more than five years,
he has managed various general and limited partnerships that invest primarily
in the oil and natural gas industry. He holds a B.S. in Economics from the
Wharton School of Finance. Mr. Sfondrini and Napamco, Ltd. ("Napamco"), a
corporation wholly owned by Mr. Sfondrini of which he is the President, are
the general partners of certain partnerships that are affiliates of Old Edge.

ROBERT W. SHOWER will become a director of the Company following the
completion of this Offering. Mr. Shower served as Executive Vice President and
Chief Financial Officer of Seagull Energy Corporation, an oil and gas
exploration, development and production company, from December 1993 until his
retirement in April 1996. From March 1992 to December 1993, he served as such
company's Senior Vice President. From 1991 to 1992, Mr. Shower served as
Senior Vice President, Corporate Development for Albert Fisher, Inc., a
company

52
<PAGE>

engaged in produce distribution. Prior thereto, he served as Senior Vice
President and Chief Financial Officer of Ameriserv. Mr. Shower also serves as
a director of Lear Corporation and Highlands Insurance Group, Inc.

There are no family relations, of first cousin or closer, among the
Company's directors or executive officers, by blood, marriage or adoption,
except that Mr. John E. Calaway and Mr. James D. Calaway are twin brothers.

OTHER KEY EMPLOYEES

DAVID L. BLAKE is a Director of Exploration for the Company and served as a
geophysicist/geologist with Old Edge since July 1989. From 1984 to July 1989,
he held the position of geophysicist for Mobil Exploration and Production
Company. Mr. Blake holds a B.S. in Geophysics from Texas A&M University.

MARK J. GABRISCH is the Director of Land for the Company. Since November
1994, he served in a similar capacity with Old Edge. From 1985 to October
1994, he was a land man, most recently a Senior Land man, for Shell Oil
Company. Mr. Gabrisch holds a B.S. in Petroleum Land Management from the
University of Houston.

JOHN O. HASTINGS, JR. is a Director of Exploration for the Company and
served in a similar capacity with Old Edge since February 1994. From 1984 to
February 1994, he was an exploration geologist with Shell Oil Company, serving
as Senior Geologist before his departure. Mr. Hastings holds a B.A. from
Dartmouth in Earth Sciences and an M.S. in Geology from Texas A&M University.

JOHN O. TUGWELL is the Director of Production Engineering for the Company
and served as Senior Petroleum Engineer of Old Edge since May 1995. From 1986
to May 1995, he held various reservoir/production engineering positions with
Shell Oil Company, most recently that of Senior Reservoir Engineer. Mr.
Tugwell holds a B.S. in Petroleum Engineering from Louisiana State University.
Mr. Tugwell is a registered Professional Engineer in the State of Texas.

DIRECTOR COMPENSATION

Directors who are employees of the Company are not entitled to receive
additional compensation for serving as directors. Following this Offering,
each director who is not an employee of the Company or a subsidiary (a
"Nonemployee Director") will receive, subject to attending a minimum of three
Board meetings per year, an annual retainer of $10,000 to be paid 50% in cash
and 50% in shares of restricted Common Stock (the "Director Restricted Stock")
pursuant to the Incentive Plan of Edge Petroleum Corporation (the "Incentive
Plan"). The Director Restricted Stock will vest ratably, subject to continued
service as a director, over three years beginning on the first anniversary of
the date of grant. Each Nonemployee Director shall receive a $1,000 cash
payment for in-person attendance at a meeting of the Board of Directors ($400
if such attendance is telephonic) and $400 for each meeting of a Committee of
the Board of Directors attended (whether in-person or telephonic). All
directors will be reimbursed for out-of-pocket expenses incurred in attending
meetings of the Board or Board committees and for other expenses incurred in
their capacity as directors. In addition, Nonemployee Directors will receive
options for the purchase of Common Stock pursuant to the Incentive Plan. See
"--Incentive Plans--Incentive Plan."

OFFICER AND DIRECTOR INDEMNIFICATION

The Company's Bylaws provide for the indemnification of its officers and
directors, and the advancement to them of expenses in connection with
proceedings and claims, to the fullest extent permitted by the Delaware
General Corporation Law. The Bylaws include related provisions meant to
facilitate the indemnitee's receipt of such benefits. These provisions cover,
among other things: (i) specification of the method of determining entitlement
to indemnification and the selection of independent counsel that will in some
cases make such determination; (ii) specification of certain time periods by
which certain payments or determinations must be made and actions must be
taken; and (iii) the establishment of certain presumptions in favor of an
indemnitee. The benefits of certain of these provisions are available to an
indemnitee only if there has been a change in

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<PAGE>

control (as defined therein). The Company intends to enter into
indemnification agreements with its directors and officers that provide for
similar protections. In addition, the Company expects to purchase directors'
and officers' liability insurance policies that will take effect upon the
closing of this Offering.

EXECUTIVE COMPENSATION

The following table sets forth certain summary information concerning the
compensation provided by Old Edge to its Chief Executive Officer and each of
the other persons that will serve as executive officers of the Company who
earned more than $100,000 in combined salary and bonus from Old Edge during
the year ended December 31, 1995 (collectively, the "Named Executive
Officers").

SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
ANNUAL
COMPENSATION(1)
---------------- ALL OTHER
NAME AND PRINCIPAL POSITION SALARY BONUS COMPENSATION(2)
--------------------------- -------- ------- ---------------
<S> <C> <C> <C>
John E. Calaway.............................. $322,666 -- $48,124
Chief Executive Officer and Chairman of the
Board
James D. Calaway............................. 150,000 -- 30,302
Special Advisor(3)
Richard S. Dale.............................. 90,000 $10,000 32,535
Controller, Treasurer and Secretary
</TABLE>
- --------
(1) Other annual compensation for the named individuals during 1995 did not
exceed the lesser of $50,000 or 10% of the annual compensation earned by
such individual.
(2) Represents the value of overriding royalty interests granted in 1995 in
respect of certain arrangements described under "--Other Compensatory
Arrangements" and in the case of Mr. John E. Calaway, $1,180 paid by Old
Edge for life insurance premiums. Substantially all of such overriding
royalty interests were sold shortly after the grant thereof. Accordingly,
such valuation is based primarily on the proceeds received from the sales
of such interests, and in cases where such interests have not been sold,
on sales of comparable interests.
(3) Mr. James D. Calaway served as Special Advisor of Old Edge during fiscal
1995. He currently serves as President of the Company.

No options were granted to any of the Named Executive Officers in 1995
pursuant to the Edge Petroleum Corporation 1994 Incentive Stock Option Plan
(the "Old Edge Plan"). In connection with the Combination Transactions, all
options previously granted under the Old Edge Plan will be converted into
options for the purchase of Common Stock. See "--Incentive Plans--Old Edge
Plan." The following table summarizes the number and value of the outstanding
options granted under the Old Edge Plan with respect to the Named Executive
Officers, adjusted for such conversion into options for the purchase of Common
Stock. None of the Named Executive Officers exercised any stock options during
1995. There are no outstanding stock appreciation rights, shares of restricted
stock or long-term incentive plans with respect to Old Edge.

54
<PAGE>

1995 YEAR-END OPTION/SAR VALUES

<TABLE>
<CAPTION>
NUMBER OF UNEXERCISED VALUE OF UNEXERCISED
OPTIONS AT IN-THE-MONEY OPTIONS AT
DECEMBER 31, 1995 DECEMBER 31, 1995
NAME EXERCISABLE/UNEXERCISABLE(1) EXERCISABLE/UNEXERCISABLE(2)
- ---- ---------------------------- ----------------------------
<S> <C> <C>
John E. Calaway...... -- --
James D. Calaway..... 48,922/0 $582,661/--
Richard S. Dale...... 48,922/0 $682,951/--
</TABLE>
- --------
(1) Represents the number of shares of Common Stock that may be issued pursuant
to options outstanding at December 31, 1995 that will be assumed by the
Company from Old Edge in connection with the Combination Transactions.
(2) Prior to this Offering, there was no public market for common stock of Old
Edge and, therefore, the value of each unexercised in-the-money stock
option is calculated as the difference between an estimated initial public
offering price of $16.00 per share and the exercise price of the stock
option, as adjusted for the conversion of shares of common stock of Old
Edge into shares of Common Stock. See "--Incentive Plans--Old Edge Plan."

EMPLOYMENT AGREEMENTS

Prior to the completion of this Offering, the Company expects to enter into
employment agreements with each of Mr. John E. Calaway and Mr. James D.
Calaway. The following summary of these agreements, which will be effective on
the closing of this Offering, does not purport to be complete and is qualified
by reference to them, copies of which have been filed as exhibits to the
Registration Statement of which this Prospectus is a part. Each of these
agreements provides for an annual base salary in an amount not less than
$295,000 in the case of Mr. John E. Calaway and $200,000 in the case of Mr.
James D. Calaway and entitles the employee to participate in all the Company's
compensation plans (as defined) in which other executive officers of the
Company participate. The agreement for Mr. John E. Calaway's employment
provides for the award of an annual cash bonus of $55,000 if the Company's
audited annual net cash flow increases by 15% or more relative to the audited
net cash flow of the prior calendar year, which bonus will be increased by
$50,000 to $105,000 if such increase in audited net cash flow is 25% or more.
The agreements of each of Mr. John E. Calaway and Mr. James D. Calaway provide
for restricted stock awards pursuant to the Incentive Plan of (a) 66,823 and
58,470 shares of Common Stock, respectively, that will vest ratably over five
years beginning on the first anniversary of the date of grant and (b) 66,822
and 58,470 shares of Common Stock, respectively (together, the "Performance
Shares"), that will vest on the earlier to occur of ten years or the
achievement of certain performance milestones. If the average closing price per
share for the Common Stock for the month of December for any given year, as
compared with the month of January for that same year (the "Annual Growth"),
has increased by 25% or more, then 20% of the Performance Shares will vest. If
the Annual Growth for a particular year is not at least 25% and as a result
none of the Performance Shares vest for such year (a "Nonachieving Year"), then
a deficit equal to 25% less the Nonachieving Year Annual Growth shall exist. In
the year subsequent to a Nonachieving Year, an additional 20% of the
Performance Shares will vest if the Annual Growth for such subsequent year is
at least 25% plus the deficit of the Nonachieving Year. Upon completion of this
Offering, Mr. John E. Calaway and Mr. James D. Calaway will also each receive
option grants, pursuant to the Incentive Plan, to purchase 133,645 and 116,940
shares of Common Stock, respectively. See "--Incentive Plans--Incentive Plan."
Each of the Employment Agreements has an initial five-year term provided that
beginning at the end of the second year of such initial term and every
anniversary thereafter, the term of each such employment agreement will
automatically be extended for one year, such that the remaining term of the
agreement shall never be less than three years. Each agreement is subject to
the right of the Company and the employee to terminate the employee's
employment at any time. Upon termination of employment on account of death,
disability or if employment is terminated by the Company without cause (as
defined) or by the employee subsequent to a change of control (as defined) or
with good reason (as defined), the employee will be entitled to (i) payment(s)
equal to his annual base salary and, in the case of Mr. John E. Calaway his
cash bonuses (in the case of performance bonuses,

55
<PAGE>

payment shall be made in the amount of the projected bonus for subsequent
periods based on the average of the applicable performance measure for the
prior two years), for the remainder of the term of the applicable agreement,
(ii) continued participation in all the Company's compensation plans (other
than the granting of new awards under the Incentive Plan or any other
performance-based plan) and (iii) the immediate vesting of any stock options or
restricted stock previously granted to such employee and outstanding as of the
time immediately prior to the date of his termination. Each agreement provides
that the Company will provide a $2 million term life insurance policy for the
employee.

The Company has entered into an employment agreement with Mr. Michael Long.
The following summary of that agreement does not purport to be complete and is
qualified by reference to it, a copy of which is filed as an exhibit to the
Registration Statement of which this Prospectus is a part. The agreement
provides for an annual base salary in an amount not less than $125,000 and
entitles Mr. Long to participate in all the Company's incentive, savings,
retirement and welfare benefit plans. Such annual base salary is subject to
increase to $150,000 as of July 1, 1997 if this Offering is completed and
certain specified objectives relating to investor relations, risk management
and employee benefits administration are completed. Mr. Long is entitled to an
annual bonus of up to 50% of his base salary, to be paid approximately 25% in
cash and 75% in shares of Common Stock, which bonus shall be based on the
achievement of the Company's annual performance goals with respect to increases
in per share reserves and audited annual net cash flow per share. The agreement
provides that Mr. Long receive an option for the purchase of 33,411 shares of
Common Stock upon completion of the Offering, pursuant to the Incentive Plan.
See "--Incentive Plans--Incentive Plan." Mr. Long's employment agreement has an
automatically renewing two-year term. The agreement is subject to the right of
the Company and Mr. Long to terminate his employment at any time. Upon
termination of employment on account of disability or if employment is
terminated by the Company without cause (as defined) or by Mr. Long subsequent
to a change of control (as defined) or with good reason (as defined), Mr. Long
will be entitled to (i) payments(s) equal to his annual base salary for the
remainder of the term of the applicable agreement and (ii) the immediate
vesting of any stock options or restricted stock previously granted to him and
outstanding as of the time immediately prior to the date of his termination.
Upon termination on account of death, the Company shall be obligated to pay, in
addition to any accrued benefits, an amount equal to one-half of his annual
base salary.

Each of the employment agreements of Messrs. John E. Calaway, James D.
Calaway and Michael G. Long described above provides that the employee shall
not divulge any of the Company's confidential information, knowledge or data
following the termination of employment. Each agreement provides for a covenant
limiting competition with the Company during employment with the Company, and,
if the employment ends by reason of the employee terminating his employment for
other than good reason or disability, for two years thereafter in the case of
each of Messrs. John E. Calaway and James D. Calaway, and for one year
thereafter in the case of Mr. Long.

Old Edge and Mr. John E. Calaway entered into an employment agreement as of
April 1991 that expired in April 1996. This agreement will be superseded by the
new employment agreement described above. Such agreement provided that Mr. John
E. Calaway was to receive base compensation of at least $295,000 per year,
subject to automatic upward adjustment based on certain price index changes and
discretionary upward adjustment upon the vote of two-thirds of the board of
directors of Old Edge. Pursuant to such agreement, Mr. John E. Calaway was also
entitled to receive a .3% overriding royalty interest in new prospects of Old
Edge or the Joint Venture during the term of the agreement. Such overriding
royalty interest was assigned to Mr. John E. Calaway as described under "--
Other Compensatory Arrangements." The agreement also provides that Old Edge
will provide at its expense a $1 million life insurance policy payable to Mr.
John E. Calaway or his designated beneficiaries.

INCENTIVE PLANS

Incentive Plan. Prior to the completion of this Offering, the Company expects
to adopt the Incentive Plan. The objectives of the Incentive Plan are to (i)
attract and retain the services of key employees, qualified

56
<PAGE>

independent directors and qualified consultants and other independent
contractors and (ii) encourage the sense of proprietorship in and stimulate the
active interest of those persons in the development and financial success of
the Company by making awards ("Awards") designed to provide participants in the
Incentive Plan with proprietary interest in the growth and performance of the
Company.

The Company plans to reserve 1,000,000 shares of Common Stock for use in
connection with the Incentive Plan. Persons eligible for Awards are (i)
employees holding positions of responsibility with the Company or any of its
subsidiaries and whose performance can have a significant effect on the success
of the Company, (ii) Nonemployee Directors and (iii) certain nonemployee
consultants and other independent contractors providing, or who will provide,
services to the Company or any of its subsidiaries.

The Compensation Committee of the Company's Board of Directors (the
"Committee") will administer the Incentive Plan. With respect to Awards to
employees and independent contractors, the Committee has the exclusive power to
administer the Incentive Plan, to take all actions specifically contemplated
thereby or necessary or appropriate in connection with the administration
thereof, to interpret the Incentive Plan and to adopt such rules, regulations
and guidelines for carrying out its purposes as the Committee may deem
necessary or proper in keeping with the objectives of such plan. With respect
to Awards to employees and independent contractors, the Committee may, in its
discretion, among other things, extend or accelerate the exercisability of,
accelerate the vesting of or eliminate or make less restrictive any
restrictions contained in any Award, waive any restriction or other provision
of the Incentive Plan or in any Award or otherwise amend or modify any Award in
any manner that is either (i) not adverse to that participant holding the Award
or (ii) consented to by that participant. The Committee also may delegate to
the chief executive officer and other senior officers of the Company its duties
under the Incentive Plan.

The Board of Directors may amend, modify, suspend or terminate the Incentive
Plan for the purpose of addressing any changes in legal requirements or for any
other lawful purpose, except that (i) no amendment or alteration that would
adversely affect the rights of any participant under any Award previously
granted to such participant shall be made without the consent of such
participant and (ii) no amendment or alteration shall be effective prior to its
approval by the stockholders of the Company to the extent such approval is then
required pursuant to Rule 16b-3 in order to preserve the applicability of any
exemption provided by such rule to any Award then outstanding (unless the
holder of such Award consents) or to the extent stockholder approval is
otherwise required by applicable legal requirements. The Board of Directors may
make certain adjustments in the event of any subdivision, split or
consolidation of outstanding shares of Common Stock, any declaration of a stock
dividend payable in shares of Common Stock, any recapitalization or capital
reorganization of the Company, any consolidation or merger of the Company with
another corporation or entity, any adoption by the Company of any plan of
exchange affecting the Common Stock or any distribution to holders of Common
Stock of securities or property (other than normal cash dividends).

Awards to employees and independent contractors may be in the form of (i)
rights to purchase a specified number of shares of Common Stock at a specified
price ("Options"), (ii) rights to receive a payment, in cash or Common Stock,
equal to the fair market value or other specified value of a number of shares
of Common Stock on the rights exercise date over a specified strike price,
(iii) grants of restricted or unrestricted Common Stock or units denominated in
Common Stock, (iv) grants denominated in cash and (v) grants denominated in
cash, Common Stock, units denominated in Common Stock or any other property
which are made subject to the attainment of one or more performance goals
("Performance Awards"). An Option may be either an incentive stock option
("ISO") that qualifies, or a nonqualified stock option ("NSO") that does not
qualify, with the requirements of Section 422 of the Code; provided, that
independent contractors cannot be awarded ISOs. The Committee will determine
the employees and independent contractors to receive Awards and the terms,
conditions and limitations applicable to each such Award, which conditions may,
but need not, include continuous service with the Company, achievement of
specific business objectives, attainment of specified growth rates, increases
in specified indices or other comparable measures of performance. Performance
Awards may include more than one performance goal, and a performance goal may
be based on one or more business

57
<PAGE>

criteria applicable to the grantee, the Company as a whole or one or more of
the Company's business units and may include any of the following: increased
revenue, net income, stock price, market share, earnings per share, return on
equity or assets or decrease in costs.

On the date this Offering closes, Options under the Incentive Plan will be
granted to approximately 16 employees of the Company to purchase a total of
approximately 350,000 shares of Common Stock at an exercise price per share
equal to the initial public offering price per share set forth on the cover
page of this Prospectus. These awards include options to be granted to Messrs.
John E. Calaway, James D. Calaway, Michael G. Long and Richard S. Dale to
purchase 133,645, 116,940, 33,411 and 16,706 shares of Common Stock,
respectively. All such options will have a term of ten years and become
exercisable in cumulative annual increments of one-fifth of the total number of
shares of Common Stock subject thereto, beginning on the first anniversary of
the date of grant.

On the date this Offering closes, each of the current Nonemployee Directors:
Messrs. Andrews, Benedict, Peterson, Raphael and Sfondrini, automatically will
be granted NSOs (based on years of service) to purchase 8,000, 2,000, 2,000,
8,000 and 8,000 shares of Common Stock, respectively. In addition, on the first
business day following the date on which each annual meeting of the Company's
stockholders is held, each Nonemployee Director then serving will automatically
be granted NSOs to purchase 3,000 shares of Common Stock. Any person who first
becomes a Nonemployee Director on or after the date this Offering closes
automatically will be granted, on the date of his or her election, NSOs to
purchase 5,000 shares of Common Stock. Consequently, on the date this Offering
closes, Mr. Shower will be granted NSOs to purchase 5,000 shares of Common
Stock. Each NSO granted to Nonemployee Directors will (i) have a ten year term,
(ii) have an exercise price per share equal to the fair market value of a
Common Stock share on the date of grant (the initial public offering price in
the case of NSOs granted on the closing of this Offering) and (iii) become
exercisable in cumulative annual increments of one-fifth of the total number of
shares of Common Stock subject thereto, beginning on the first anniversary of
the date of grant. If a Nonemployee Director resigns from the Board without the
consent of a majority of the other directors, such director's NSOs may be
exercised only to the extent they were exercisable on the resignation date.

The foregoing description summarizes the principal terms and conditions of
the Incentive Plan, does not purport to be complete and is qualified in its
entirety by reference to the Incentive Plan, a copy of which has been filed as
an exhibit to the Registration Statement of which this Prospectus is a part.

401(K) Plan. Following the completion of this Offering, the Company expects
to adopt a 401(k) Employee Savings Plan (the "401(k) Plan") for its employees.
The following describes possible terms of such plan; however, the decision to
adopt any such plan and the terms thereof will be in the discretion of the
Compensation Committee and the Board of Directors, and, if adopted, may differ
from that described below. Under the 401(k) Plan, eligible employees will be
permitted to defer receipt of up to 15% of their compensation (subject to
certain limitations imposed under the Internal Revenue Code of 1986, as amended
(the "Code")). The 401(k) Plan is expected to provide that a discretionary
match of employee deferrals may be made by the Company in cash. Pursuant to the
401(k) Plan, the Company currently expects to elect to match 50% of the first
6% of employee deferral, with the Company's contribution not to exceed $9,000,
subject to limitations imposed by the Internal Revenue Service. The amounts
held under the 401(k) Plan are expected to be invested among various investment
funds maintained under the 401(k) Plan in accordance with the directions of
each participant, except that matching contributions are expected to be
invested in securities of the Company. Salary deferral contributions under the
401(k) Plan are expected to be 100% vested. Matching contributions are expected
to vest at the rate of 20% after two years of service and 20% for each year
thereafter. Participants or their beneficiaries are expected to be entitled to
payment of vested benefits upon termination of employment.

Old Edge Plan. Old Edge adopted the Old Edge Plan pursuant to which, in 1994,
all of the options held by Messrs. James D. Calaway and Dale were granted. The
Old Edge Plan was administered by nonemployee members of the Board of Directors
of Old Edge. In connection with the Combination Transactions, such options

58
<PAGE>

will be converted into incentive stock options for the purchase of such number
of shares of Common Stock as each of Messrs. James D. Calaway and Dale would
have received in the Combination Transactions if such options had been
exercised immediately prior to the Combination Transactions. After adjustment
for such conversion, the option exercise price per share of Common Stock will
be approximately $4.09 and $2.04 for Messrs. James D. Calaway and Dale,
respectively.

OTHER COMPENSATORY ARRANGEMENTS

Overriding Royalty Income. Overriding royalty interests are assigned to
certain employees of Old Edge to reward such employees with incentive
compensation based on the results of the oil and natural gas drilling
activities conducted through the Joint Venture. Pursuant to the Joint Venture
Agreement, Old Edge as managing joint venturer has the right to cause the Joint
Venture to grant overriding royalty interests on prospects sold by the Joint
Venture to geologists, scientists or other persons who originate prospects and
to grant up to a .8% overriding royalty interest to any of certain Old Edge
executives. In the past, Old Edge has caused the Joint Venture to assign
overriding royalty interests in certain oil and natural gas leases pursuant to
this arrangement to certain employees employed at the time of the execution of
the lease. The percentage of overriding royalty interest assigned to employees
as a group for a given lease typically has ranged from 2.6% to 3.8% of the
Joint Venture's total interest in such lease. An individual employee's
overriding royalty interest in a lease was determined in the discretion of Old
Edge's management. Employees receiving overriding royalty interests were
entitled to receive revenues immediately upon the assignment thereof, and such
interests were not subject to forfeiture.

Following the completion of this Offering, the Company intends to assign
overriding royalty interests on a more limited basis with respect to leases
entered into by the Joint Venture or otherwise by the Company that are included
in projects not in existence as of December 31, 1996 and subsequent projects
that are not based on 3-D seismic work firmly committed as of such date ("New
Projects"). Only members of the generating geological team for a given lease in
a New Project will receive overriding royalty interests, and the Company
currently does not expect such interests in the aggregate to exceed 1.5% of the
Company's total interest in such lease. The Company expects that the director
of engineering production and the director of land would continue to receive
overriding royalty interests in leases that are not in New Projects.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

Prior to this Offering, the Company expects to establish a Compensation
Committee. In the past, matters with respect to the compensation of executive
officers of Old Edge were determined by the nonemployee members of the Board of
Directors, as a whole.

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<PAGE>

CERTAIN TRANSACTIONS

THE COMBINATION TRANSACTIONS

The Company was incorporated in Delaware in August 1996. In the Combination
Transactions, the Company plans to complete (i) a merger (the "Merger") of Old
Edge with Edge Mergeco, Inc., a wholly owned subsidiary of the Company
organized solely to effect the merger ("Mergeco"), in which the shareholders
of Old Edge will receive Common Stock, (ii) an exchange offer (the "Edge Group
II Exchange Offer") to the general and limited partners of Edge Group II in
which such partners will have the opportunity to exchange their interests in
Edge Group II for Common Stock, (iii) an exchange offer (the "Gulfedge
Exchange Offer" and, together with the Edge Group II Exchange Offer, the
"Limited Partnership Exchange Offers") to the limited partners of Gulfedge, of
which Old Edge is the general partner (Edge Group II and Gulfedge are
collectively referred to as the "Limited Partnerships"), in which such limited
partners will have the opportunity to exchange their interests in Gulfedge for
Common Stock, (iv) an offer to purchase (the "Purchase Offer") from Edge Group
its interest in the Joint Venture, for consideration consisting of Common
Stock and (v) an exchange (the "Calaway Exchange") of interests in certain oil
and natural gas properties held by Mr. James C. Calaway for Common Stock. Upon
consummation of the Combination Transactions, the Company expects to acquire
directly or indirectly substantially all of the interests in the Joint
Venture. The Company does not expect to seek to consummate this Offering
unless both the Merger and the Edge Group II Exchange Offer (with at least a
70% acceptance level) are closed; however, the Company would seek to
consummate this Offering even in the absence of the closing of any or all of
the Calaway Exchange, the Purchase Offer or the Gulfedge Exchange Offer. The
number of shares of Common Stock to be issued in the Combination Transactions
will depend on (i) the number of partners who elect to retain their current
interests in the Limited Partnerships in lieu of receiving Common Stock and
(ii) whether Edge Group accepts the Purchase Offer. The disclosures in this
Prospectus relating to the shares of Common Stock to be issued in connection
with the Combination Transactions are estimated based on the assumptions that
all of the partners will tender their interests in the Limited Partnerships in
exchange for Common Stock and that Edge Group will accept the Purchase Offer.

The following table illustrates the number of shares to be issued in this
Offering and the Combination Transactions assuming all parties accept Common
Stock in the Combination Transactions (excluding any restricted stock and
stock options and assuming that the Underwriters' over-allotment option is not
exercised):

<TABLE>
<CAPTION>
NUMBER OF PERCENTAGE OF
TRANSACTION SHARES ISSUED SHARES ISSUED
----------- ------------- -------------
<S> <C> <C>
Shares to be issued in the Merger............ 2,334,085 34.9%
Shares to be issued in the Edge Group II
Exchange Offer.............................. 2,209,306 33.1
Shares to be issued in the Gulfedge Exchange
Offer....................................... 74,317 1.1
Shares to be issued in the Purchase Offer.... 42,896 0.7
Shares to be issued in the Calaway
Exchange(1)................................. 21,669 0.3
Shares to be issued in this Offering......... 2,000,000 29.9
--------- -----
6,682,273 100.0%
</TABLE>
- --------
(1)Assumes an initial public offering price of $16.00 per share.

Description of Joint Venture. Substantially all of the operations of the
Company are currently conducted through the Joint Venture. The Joint Venture
was formed on April 8, 1991 by Old Edge, Edge Group II, Gulfedge and Edge
Group, with approximately $5.2 million in net assets (on an historical
financial statement basis). On that date the Joint Venture purchased
substantially all of the assets and assumed substantially all of the
liabilities of a related entity, Edge Group Joint Venture, which had been
engaged in oil and natural gas exploration and production operations since
1983. The initial sharing ratio, which determines the allocation of net income
and other items, as well as the allocation of distributable cash, was
approximately 29.1%, 67.3%, 2.3% and 1.3%, respectively. Such sharing ratio is
applicable until the value of cash and carried interests and other property
distributed to each venturer is equal to $5,750,000, $13,324,500, $451,500 and
$258,000, respectively (the

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<PAGE>

"Sharing Ratio Shift A Amounts"), which has not yet occurred. At such time,
the sharing ratio shifts to 50%, 47.5%, 1.6% and 0.9%, respectively, which
continues until the value of cash and carried interests and other property
distributed to each venturer is six times the Sharing Ratio Shift A Amounts
(the "Sharing Ratio Shift B Amounts"). When the Sharing Ratio Shift B Amounts
are met, the applicable sharing ratio for the duration of the Joint Venture
will be 55%, 42.7%, 1.5% and 0.8%, respectively.

The term of the Joint Venture was to have expired on April 8, 1996; however,
the parties to the Joint Venture extended the dissolution date to December 31,
1996. On December 31, 1996, the Joint Venture entered a windup period that
will generally last for two years during which time most of the existing oil
and gas properties of the Joint Venture will continue to be held by the Joint
Venture. By the end of the windup period, the Joint Venture will distribute
substantially all of its assets, including working interests, to the
venturers, in accordance with the applicable sharing ratios or as otherwise
specified in the Joint Venture Agreement. Pursuant to the Joint Venture
Agreement, Old Edge generally owns all 3-D seismic data owned by the Joint
Venture at the date of dissolution, provided that the other venturers have the
right to access and use such data and, provided further that, if such data is
later sold, Old Edge will pay a portion of the proceeds to the other
venturers. Additionally, with respect to Joint Venture projects existing at
the date of dissolution, the Joint Venture Agreement provided for the creation
of areas of mutual interest ("AMIs"), which allow the venturers to acquire a
portion of any interest acquired by any other venturer in such AMI. Initially
following this Offering, substantially all of the Company's activities will
consist of continued operations and will be conducted through the Joint
Venture or with the partners of the Joint Venture. Thereafter, the Company
expects that it will initiate operations outside of and unrelated to those
conducted by the Joint Venture at the time of its dissolution. To the extent
they do not exchange in the Combination Transactions, limited partners and
Edge Group generally will not participate in new prospects or operations
unrelated to the Joint Venture's operations as of December 1996, except as
provided for in the provisions of the Joint Venture Agreement with respect to
150 square miles in the Belco Project Area and another 50 square miles of 3-D
seismic data to be selected. All or portions of each of the areas subject to
the Belco Right, the Fifty Square Mile Right and certain other specified areas
will be developed outside of the Joint Venture.

Old Edge is the managing venturer of the Joint Venture and generally directs
and exercises control over all activities of the Joint Venture. However, Old
Edge is restricted from causing the Joint Venture to acquire leases, purchase
capital assets, adopt a budget, create debt or mortgages on its assets or sell
all or substantially all of its assets without the consent of Edge Group II.
After giving effect to the Combination Transactions, the Company will direct
and exercise full control over all activities of the Joint Venture as its
managing venturer and as the general partner of Edge Group II, subject to its
contractual and fiduciary duties owed to those partners of the Limited
Partnerships who do not exchange their partner interests for shares of Common
Stock. See "Risk Factors--Certain Potential Conflicts of Interest."

Immediately following this Offering, the Company will loan a portion of the
proceeds of this Offering to the Joint Venture to repay indebtedness
outstanding under the Revolving Credit Facility and to repay approximately
$1.3 million outstanding under the Subordinated Loan. See "Use of Proceeds."

The Merger. In the Merger, Mergeco will merge with and into Old Edge.
Mergeco is a wholly owned subsidiary of the Company organized for the purpose
of effecting the Merger. In the Merger, all of the outstanding shares of
common stock of Old Edge will be converted into an aggregate of 2,334,085
shares of Common Stock of the Company, assuming no shareholders of Old Edge
exercise dissenters' rights. Old Edge will survive the Merger as a wholly
owned subsidiary of the Company. As a result of the Merger, the Company will
indirectly control all of the assets of Old Edge, which consist primarily of
its interest in the Joint Venture. The Company's obligation to consummate the
Combination Transactions is conditioned, among other things, on the
consummation of the Merger.

The Limited Partnership Exchange Offers. In the Limited Partnership Exchange
Offers, the Company will offer to exchange shares of Common Stock for the
general and limited partner interests in Edge Group II and for the limited
partner interests in Gulfedge. An aggregate of 2,209,306 shares of Common
Stock will be offered in

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<PAGE>

exchange for all the general and limited partner interests in Edge Group II,
and an aggregate of 74,317 shares of Common Stock will be offered in exchange
for all the limited partner interests in Gulfedge. The number of shares of
Common Stock that will be offered in exchange for the general partner interest
in Edge Group II will be equal to the whole number nearest to the sum of (i)
the GP's 1% Shares (which shares are attributable to the general partners' 1%
interest in distributions before Edge Group II distributes to its partners
$20,188,636 (the "Payout Amount")), (ii) the GP's Management Fee Shares (which
shares are attributable to the general partners' accrued but unpaid and future
cash flow-based management fees) and (iii) the GP's After Payout Shares (which
shares are attributable to the general partners' 25% interest in distributions
after Edge Group II distributes to its partners the Payout Amount) (the shares
referred to in (i), (ii) and (iii) collectively referred to herein as the "GP
Exchange Shares"). The GP's 1% Shares are a number of shares of Common Stock
equal to the quotient of (i) $201,886 (which equals 1% of the Payout Amount)
divided by (ii) the initial public offering price in this Offering per share
of Common Stock (the "IPO Price"). The GP's Management Fee Shares are a number
of shares of Common Stock equal to the quotient of (i) the sum of (A)
$1,598,940 (which equals the general partners' accrued but unpaid management
fees) plus (B) 3% multiplied by 2,209,306 (which equals to total number of
shares of Common Stock allocable to Edge Group II) multiplied by the IPO Price
(which product in (B) is attributable to the general partners' future cash
flow-based management fees) (such sum in (i) is referred to herein as the
"Management Fee Amount") divided by (ii) the IPO Price. The GP's After Payout
Shares are a number of shares of Common Stock equal to the quotient of (i) 25%
of the difference between (A) the product of the IPO Price multiplied by
2,209,306 and (B) the sum of (x) the Payout Amount plus (y) the Management Fee
Amount divided by (ii) the IPO Price. The aggregate number of shares of Common
Stock that will be offered in exchange for the limited partner interest in
Edge Group II will be equal to the difference between 2,209,306 and the GP
Exchange Shares. The Company's obligation to consummate the Combination
Transactions is conditioned, among other things, upon the general partners and
at least 70% of the limited partners of Edge Group II exchanging their partner
interests for shares of Common Stock, but it is not conditioned upon the
exchange by any partner of Gulfedge. The obligation of each partner of the
Limited Partnerships to exchange his interests is conditioned upon, among
other things, the closing of this Offering at an IPO Price of at least $14.50
per share. The partners of each Limited Partnership will have the option of
receiving Common Stock or retaining their partner interest. There can be no
assurance as to the number of such partners, if any, who will tender their
partner interests for shares of Common Stock.

The Calaway Exchange. Effective December 20, 1994, Mr. James C. Calaway
acquired a reversionary working interest (the "Calaway RWI") and an overriding
royalty interest (the "Calaway ORRI," and together with the Calaway RWI, the
"J. C. Calaway Interests") in certain undrilled prospects and subsequently
acquired properties of the Joint Venture pursuant to the Subordinated Loan
Agreement. Pursuant to the Subordinated Loan Agreement, if, as a result of the
termination of the Joint Venture, Old Edge enters into a transaction whereby
the oil and natural gas interests attributable to the limited partner
interests of Edge Group II are acquired by Old Edge or another entity for
stock, Mr. James C. Calaway would similarly have the opportunity to sell the
James C. Calaway Interests on the same valuation basis as the limited partners
of Edge Group II. See "--Subordinated Loan Agreement." Pursuant to a Purchase
Agreement dated as of December 2, 1996, Mr. James C. Calaway agreed to
exchange the portion of the James C. Calaway Interests consisting of producing
properties for that number of shares of Common Stock equal to the higher of
(i) the quotient of (a) $346,697 (which is the estimated future net revenues
as of September 30, 1996 attributable to the J.C. Calaway Interests being
exchanged as determined by Ryder Scott Company) divided by (b) the IPO price
(such quotient in (i) is referred to herein as the "1996 Valuation Shares")
and (ii) the quotient of (a) the estimated future net reserves attributable to
the J.C. Calaway Interests being exchanged as determined by Ryder Scott
Company in a reserve report as of a date subsequent to September 30, 1996 but
prior to the closing of the Purchase Agreement (such date is hereinafter
referred to as the "1997 Determination Date") and for which the results of
such reserve report are included in the final prospectus for this Offering and
(b) the IPO price (such quotient in (ii) is referred to herein as the "1997
Valuation Shares"). Assuming an IPO price of $16.00 per share and that the
1996 Valuation Shares are higher in number than the 1997 Valuation Shares, Mr.
James C. Calaway would be entitled to receive 21,669 shares of Common Stock.
Mr. James C. Calaway has also agreed to pay the Company the dollar amount of
any revenues attributable to the J.C. Calaway Interests received by him for
income for production after either September 30,

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<PAGE>

1996 (if the 1996 Valuation Shares are higher in number) or the 1997
Determination Date (if the 1997 Valuation Shares are higher in number) and
prior to the closing of the Purchase Agreement. In addition, because of the
difficulties involved in valuing the portion of the J. C. Calaway Interests
consisting of exploratory properties, Mr. James C. Calaway agreed that he
would retain these interests and waived his rights under the Subordinated Loan
Agreement to exchange such interests for shares of Common Stock.

The Edge Group Purchase. In the Purchase Offer, the Company will offer to
purchase the interest in the Joint Venture held by Edge Group in exchange for
shares of Common Stock. Such purchase will occur only with the consent of each
of the partners of Edge Group. Neither the closing of this Offering nor the
Company's obligation to consummate the Combination Transactions will be
conditioned on the Company's purchase of the interest in the Joint Venture
held by Edge Group. The obligation of Edge Group to sell its interest in the
Joint Venture to the Company will be conditioned upon, among other things, the
closing of this Offering at an IPO Price of $14.50 per share. In addition, the
sale of Edge Group's interest in the Joint Venture to the Company requires the
consent of the other venturers--Old Edge, Edge Group II and Gulfedge--which
has already been obtained.

Effect of the Combination Transactions. Upon the closing of the Combination
Transactions and this Offering and assuming the issuance of Common Stock to
all parties to the Combination Transactions (i.e., each offeree elects to
exchange its interests for shares of Common Stock), (i) the Company will
become an independent, publicly held company, (ii) holders of Old Edge common
stock will become stockholders of the Company rather than of Old Edge, (iii)
the partners who exchange their interests in the Limited Partnerships in
exchange for shares of Common Stock will become stockholders of the Company
rather than partners of the Limited Partnerships, (iv) the Company will become
the general partner of Edge Group II, and will own all of the partner
interests in Edge Group II and Gulfedge, (v) Edge Group will become a
stockholder of the Company and (vi) direct and indirect ownership of all the
interests in the Joint Venture will be combined in the Company. In the event
that any limited partner does not exchange his or her interests in the Limited
Partner Exchange Offers, such limited partner and the Company will continue as
the limited partners of such partnership. In the event that the Edge Group
Purchase is not consummated, Edge Group will continue as a general partner of
the Joint Venture. The Joint Venture will continue in existence following this
Offering until its final liquidation. It is currently expected that most of
the Joint Venture's assets will be distributed to its partners during the two-
year windup period, which began December 31, 1996; however, certain assets may
be retained in the Joint Venture over a longer term. Initially following this
Offering, substantially all of the Company's activities will consist of
continued operations and will be conducted through the Joint Venture or with
the partners in the Joint Venture. The Company expects that it will initiate
new operations outside of and unrelated to those conducted by the Joint
Venture at the time of its dissolution.

TRANSFER OF EDGE GROUP II GENERAL PARTNER INTERESTS

In exchange for the general partner interests of Mr. Sfondrini and Napamco,
a corporation wholly owned by Mr. Sfondrini. Mr. Sfondrini and Napamco will
receive the number of shares of Common Stock equivalent to the GP Exchange
Shares. The Combination Transactions will allow the general partners of Edge
Group II to receive Common Stock in respect of both management fees that have
been deferred to date because no cash was available for payment, as well as
the estimated value of future management fees that have not been earned to
date. Pursuant to certain prior personal loan agreements, Mr. Sfondrini and
Napamco assigned a portion of their management fee with respect to Edge Group
II and the right to a percentage of their distributions as its general
partners, to, among others, Mr. James C. Calaway, who is the father of both
the Chief Executive Officer and the President of the Company, Ms. Marlin
Geiger, the mother of both such persons and to Mr. David Benedict who is a
director of the Company. As a result, Mr. James C. Calaway, Ms. Geiger and Mr.
Benedict will receive 12,830, 995 and 2,122 shares, respectively, of Common
Stock that is distributable to Mr. Sfondrini pursuant to the Edge Group II
Exchange Offer. In the absence of the Combination Transactions and this
Offering, it is unlikely that any of the accrued management fees or
distributions would be paid in the near term.

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<PAGE>

Following the consummation of this Offering, Mr. Sfondrini expects to enter
into a margin loan arrangement described in "Underwriting." Mr. Sfondrini
expects to use a portion of the proceeds of such borrowings to repay the
indebtedness under the above described loan agreements.

CERTAIN AFFILIATE RELATIONSHIPS

The Joint Venture is owned by Old Edge, Edge Group II, Gulfedge and Edge
Group, as described above. John Sfondrini and Napamco, a company Mr. Sfondrini
owns and is the President of, are the general partners of Edge Group II and
each of the three limited partnerships that are the general partners in Edge
Group. Mr. Sfondrini and Napamco are also the general partners of Edge Holding
Company, which owns, prior to the Combination Transactions, approximately 37%
of the common stock of Old Edge. In the case of Edge Group II, in the event of
the death, incapacity or withdrawal of Mr. Sfondrini from his position as
general partner, Mr. Andrews would, if he so chose, serve as a general partner
of Edge Group II. Old Edge is the general partner of Gulfedge. Napamco is the
general partner of each of Essex Royalty Limited Partnership ("Essex I L.P.")
and Essex Royalty Limited Partnership II ("Essex II L.P."). Resource Investors
Management Company Limited Partnership ("RIMCO") is the general partner of
each of two limited partnerships (the "RIMCO Partnerships") that, in the
aggregate own, prior to the Combination Transactions, approximately 5% of the
common stock of Old Edge.

Mr. James D. Calaway and Mr. John E. Calaway are twin brothers and their
father is Mr. James C. Calaway.

ESSEX ROYALTY JOINT VENTURES

In April 1992, the Joint Venture and Essex I L.P. entered into a Joint
Venture Agreement (the "Essex I Joint Venture") with respect to the purchase
of certain royalty interests in oil and natural gas properties. The initial
term of the Essex I Joint Venture was four years, but by consent of both
parties to such agreement, it has been extended until April 1997. Under the
terms of the Essex I Joint Venture Agreement, Essex I L.P. made capital
contributions aggregating $3 million and the Joint Venture made no capital
contributions. The Essex I Joint Venture Agreement provides that quarterly
distributions of cash be made, in accordance with the sharing ratios, in an
amount, subject to certain adjustments, not less than that equal to revenues
received from royalties less the management fee paid to the Joint Venture, as
managing venturer. Initially, Essex I L.P. receives 100% of all cash
distributions pursuant to the sharing ratios. At such time as the cash and
value of property distributed to Essex I L.P. is equal to 110% of its capital
contribution, the sharing ratio shifts to 40% for the Joint Venture and 60%
for Essex I L.P. Such 40% is to be allocated directly to the venturers of the
Joint Venture, and does not affect the sharing ratio calculations with respect
to the Joint Venture. As managing venturer of the Essex I Joint Venture, the
Joint Venture receives reimbursement for costs incurred to acquire royalty
interests, certain administrative costs, a portion of the payroll costs
attributable to the Essex II Joint Venture and, prior to the sharing ratio
shift, a management fee (allocated directly to Old Edge) equal to 1% of the
capital contributions of Essex I L.P.

In May 1994, the Joint Venture and Essex II L.P. entered into a Joint
Venture Agreement (the "Essex II Joint Venture") effective until December 1997
and similar in nature to the Essex I Joint Venture. Essex II L.P. made capital
contributions aggregating approximately $2.8 million and the Joint Venture
made no capital contributions. Initially, Essex II L.P. receives 100% of all
cash distributions pursuant to the sharing ratios. At such time as the cash
and property distributed to Essex II L.P. is equivalent to 111.3% of its
capital contribution, the Joint Venture will thereafter receive 25% of
distributions. Provisions with respect to mandatory distributions and
dissolution are similar to those described for the Essex I Joint Venture. As
managing venturer of the Essex II Joint Venture, the Joint Venture receives
reimbursement for costs incurred to acquire royalty interests, certain
administrative costs, a portion of the payroll costs attributable to the Essex
II Joint Venture and, prior to the earlier of the expenditure by the Essex II
Joint Venture of its capital or the sharing ratio shift, a management fee
(allocated directly to Old Edge) of $30,000 every six months.

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<PAGE>

The management fees earned by Old Edge pursuant to the Essex I and II Joint
Ventures (combined), in 1995, 1994 and 1993 were $120,000, $80,000 and
$60,000, respectively. Old Edge invoiced the Essex I and II Joint Ventures
(combined) for reimbursement for expenses in 1995, 1994 and 1993 in the
amounts of $40,250, $18,750 and $36,750, respectively. At December 31, 1995
and 1994, Old Edge had accrued receivables for such management fees and
reimbursements of $115,000 and $63,600, respectively.

In May 1993, the Joint Venture received a short-term $1 million loan from
the Essex I Joint Venture secured by the Joint Venture's interests in certain
prospects. In addition to interest of 10% per annum, the loan agreement
provided for an assignment to the Essex I Joint Venture of overriding royalty
interests in the collateral. In October 1993, the Joint Venture borrowed
$125,000 on a short-term basis from the Essex I Joint Venture. Such note
carried interest of 11% per year and was unsecured. In August 1994, the Joint
Venture borrowed $125,000 on a short-term basis from the Essex II Joint
Venture at an interest rate of 10% per year. In December 1993, the Essex I
Joint Venture borrowed $30,000 on a short-term basis from the Joint Venture.
Such note carried interest of 11% per year and was unsecured. In May 1994, the
Joint Venture loaned, on a short-term basis, $46,800 to the Essex II Joint
Venture. No loans between the Joint Venture and either of the Essex I Joint
Venture or the Essex II Joint Venture are presently outstanding.

RIMCO INTERESTS

In April 1991, the Joint Venture borrowed, in the aggregate, $4,500,000 from
the RIMCO Partnerships and another partnership of which RIMCO is the general
partner, at an annual interest rate of 15.5% (the "RIMCO Note"). The Joint
Venture and such partnerships agreed to reduce the interest rate of the RIMCO
Note from 15.5% to 10% for the period from October 1, 1993 through September
30, 1995. Pursuant to such agreement, the Joint Venture conveyed to such
partnerships a 0.4% after-payout royalty interest, in the aggregate, in all
prospects sold by the Joint Venture during such period. The RIMCO Note was
repaid in March 1995.

SUBORDINATED LOAN AGREEMENT

In December 1994, the Joint Venture and Mr. James C. Calaway entered into
the Subordinated Loan Agreement, which has since been amended as described
below. A portion of the proceeds from this Offering will be used to pay the
amounts outstanding on such loan, which will be terminated. The Subordinated
Loan Agreement provides for a $1 million term loan and a $1 million line of
credit. At September 30, 1996, the aggregate amount outstanding under the
Subordinated Loan was $1.3 million, which includes $300,000 outstanding under
the line of credit. The principal is due, unless earlier retired by the Joint
Venture, upon the earlier of April 8, 1998 or the conclusion of the Joint
Venture's windup period. Interest at 10% per annum is due monthly. Mr. James
C. Calaway also has the option, pursuant to the Subordinated Loan, to
participate in certain future debt financing of the Joint Venture to the
extent of the amount outstanding under the Subordinated Loan. The Subordinated
Loan is secured by certain oil and natural gas properties, equipment and other
assets of the Joint Venture, but is subordinated to the Revolving Credit
Facility. The mortgage and security agreement restricts the transfer of
properties, creation of liens and other matters. The Subordinated Loan is
without recourse to the venturers.

The Subordinated Loan provides that Mr. James C. Calaway will receive, with
respect to prospects of the Joint Venture which were undrilled as of December
20, 1994 and any acquisition subsequent to such date by the Joint Venture of
interests in existing production or proven reserves, (i) a Calaway RWI of 1%
and (ii) on all prospects that had not been marketed as of such date, a
Calaway ORRI of .2%, each of which is subject to proportionate reduction under
certain circumstances. The Calaway ORRI is reduced to .1% with respect to any
well located in certain specified 3-D areas that is proposed after August 1,
1996 but prior to the later of the repayment in full of the Subordinated Loan
or the dissolution of the Joint Venture (the "Change of Interest Date").
Effective upon the Change of Interest Date AMIs will be created consisting of
all acreage in which the Joint Venture has, as of such date, shot or acquired
or has a commitment to shoot or acquire 3-D geophysical data. The Calaway ORRI
and the Calaway RWI will be reduced to .1% and .05%, respectively, with
respect to

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<PAGE>

each well and lease proposed after the Change of Interest Date located within
such an AMI. After the Change of Interest Date, Mr. Calaway is not entitled to
receive any additional interests in any Joint Venture prospects or 3-D areas
other than those situated within such AMIs or as provided for originally in the
Subordinated Loan Agreement.

The Subordinated Loan Agreement provides for certain rights, on the part of
Mr. James C. Calaway, to exchange the Calaway Interests for Common Stock.
Accordingly, the portion of the Calaway Interests consisting of producing
properties is being purchased by the Company pursuant to the Calaway Exchange
by valuing such interests at $346,697. See "--The Combination Transactions--The
Calaway Exchange."

A portion of the Subordinated Loan replaced an unsecured loan in the
aggregate principal amount of $400,000 made by Mr. James C. Calaway to the
Joint Venture in June 1994. Interest at 10% per annum was due monthly. As
additional consideration for such loan, Mr. James C. Calaway received a .5% RWI
and a .05% ORRI in five prospects generated by the Joint Venture subsequent to
the date of such note. Prior to the loan of June 1994, Mr. James C. Calaway had
made loans of $350,000 and $400,000 to the Joint Venture, which were repaid in
1994 and 1993, respectively. Each of such loans provided for an interest rate
of 10% and the granting of interests in certain specified oil and natural gas
properties to Mr. James C. Calaway.

JAMES C. CALAWAY CONSULTING AGREEMENT

The Company is obligated to pay Mr. James C. Calaway $40,000 annually for the
remainder of his natural life pursuant to a March 1989 consulting agreement.
Under the terms of such agreement, Mr. James C. Calaway is obligated to provide
consulting services as and to the extent mutually agreed upon.

SALES OF PROSPECTS TO AFFILIATES

In 1993 and 1994, the Joint Venture sold certain drilling prospects to
partnerships owned by Mr. James D. Calaway for $32,095 and $241,395,
respectively, and, in 1994, to an affiliate of the RIMCO Partnerships for
$60,000. No sales of prospects to affiliates of the Company took place in 1995.
The cost to develop such prospects was $16,652, $153,520 and $39,593,
respectively. The purchase price was based on the amounts paid for interests in
such prospects by energy industry participants.

Napamco and another corporation of which Mr. Andrews is an officer, are the
general partners of each of two limited partnerships that have invested, on the
same basis as outside parties, in two wells that the Company acts as operator
for. Such partnerships, in the aggregate, have a working interest of 7.5% in a
well in the Barnett Project Area and a working interest of approximately 30% in
a well in the Tyler Project Area. The partnerships have paid to the Company, in
the aggregate, approximately $105,000 with respect to the Barnett Project Area
well and $600,000 with respect to the Tyler Project Area well, which
represents, in the aggregate such partnerships' share of the costs to develop
each such well proportionate to their relative working interests therein.

REGISTRATION RIGHTS AGREEMENT OF EDGE HOLDING COMPANY LIMITED PARTNERSHIP

In connection with this Offering, the Company will enter into a registration
rights agreement with Edge Holding Company (the "Registration Rights
Agreement"). The Registration Rights Agreement will provide that, upon the
request of Edge Holding Company, the Company will file a registration statement
under the Securities Act to register the Common Stock being issued to Edge
Holding Company pursuant to the Merger for distribution to the partners of Edge
Holding Company. Such request may not be made before six months after the
closing of this Offering. The Registration Rights Agreement will terminate on
December 31, 1998, or earlier in certain circumstances. An aggregate of 858,853
outstanding shares of Common Stock will be subject to the Registration Rights
Agreement.

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The Company is required to pay all costs associated with such registration
other than underwriting commissions and transfer taxes attributable to the
shares distributed. The Company will indemnify Edge Holding Company, and Edge
Holding Company will indemnify the Company, against certain liabilities in
respect of any registration statement or offering covered by the Registration
Rights Agreement.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information with respect to beneficial
ownership of the Common Stock both after giving effect to the Combination
Transactions but before giving effect to this Offering and after giving effect
to the Combination Transactions and this Offering by: (i) all persons,
assuming 100% conversion of the interests in the Limited Partnerships, who
will be the beneficial owner of 5% or more of the outstanding Common Stock;
(ii) each director or nominee for director; (iii) each executive officer of
the Company; and (iv) all officers and directors of the Company as a group,
assuming in each case, the issuance of Common Stock to all parties to the
Combination Transactions and an initial public offering price of $16.00 per
share.

<TABLE>
<CAPTION>
COMMON STOCK
BENEFICIALLY OWNED PERCENT OF COMMON STOCK
AS A RESULT OF THE BENEFICIALLY OWNED
COMBINATION AS A RESULT OF THE
TRANSACTIONS COMBINATION TRANSACTIONS
------------------ ------------------------
PRIOR TO THIS AFTER THIS
NAME(1) NUMBER OF SHARES OFFERING OFFERING
------- ------------------ ------------- ----------
<S> <C> <C> <C>
John E. Calaway(2)........... 481,541 10.28% 8.87%
James D. Calaway(3).......... 195,498 4.13% 4.48%
Michael G. Long.............. -- -- --
Richard S. Dale(4)........... 48,922 1.03% *
Vincent Andrews(5)........... 206,814 4.42% 2.98%
David B. Benedict(6)......... 36,338 * *
Nils Peterson(7)............. 14,664 * *
Stanley S. Raphael(8)........ 274,853 5.87% 3.96%
John Sfondrini(9)............ 1,254,110 26.78% 18.09%
Robert W. Shower............. -- -- --
Edge Holding Company......... 858,853 18.34% 12.39%
36 Catoonah St., #16
Ridgefield, Connecticut 06877
All directors and executive
officers as a group (10
persons)(1)(10)............. 2,512,740 53.66% 39.30%
</TABLE>
- --------
* Less than one percent.
(1) Except as otherwise noted, each stockholder has sole voting and investment
power with respect to the shares beneficially owned.
(2) Shares shown represent (i) 364,938 shares of Common Stock that could be
acquired through the Merger by Calaway Oil and Gas Corporation ("COG"), a
company wholly owned by Mr. John E. Calaway and his wife, (ii) 116,603
shares that could be acquired through the Merger by Calaway Partners, a
Texas general partnership of which COG is a partner and, in the case of
After this Offering, (iii) 133,645 shares of restricted Common Stock to be
issued concurrent with this Offering. Pursuant to the partnership
agreement for Calaway Partners, COG has the exclusive right to vote such
116,603 shares.
(3) Shares shown include (i) 118,366 shares of Common Stock that could be
acquired through the Merger by KPC Interests, Inc., a company owned by Mr.
James D. Calaway, (ii) 48,922 shares of Common Stock that could be
acquired pursuant to immediately exercisable stock options and, in the
case of After this Offering, (iii) 116,940 shares of restricted Common
Stock to be issued concurrent with this Offering.
(4) Shares shown represent 48,922 shares of Common Stock that could be
acquired pursuant to immediately exercisable stock options.

68
<PAGE>

(5) Shares shown represent 146,757 shares of Common Stock that could be
acquired through the Merger by Bama Edge Limited Partnership, the general
partner of which is Andex Energy Corp., a company owned by members of Mr.
Andrews' family and of which Mr. Andrews is an officer; 45,598 shares of
Common Stock that could be acquired through the Merger by Texedge Energy
Corporation, of which Mr. Andrews is an officer; and 14,460 shares that
could be acquired through the Edge Group II Exchange Offer by a
partnership owned in part by Mr. Andrews' wife. Mr. Andrews may be deemed
the beneficial owner of the shares of Common Stock held by Bama Edge
Limited Partnership, Texedge Energy Corporation and the shares that may be
acquired through the Edge Group II Exchange Offer. Mr. Andrews disclaims
such beneficial ownership.
(6) Shares shown represent shares of Common Stock that could be acquired
through the Edge Group II Exchange Offer.

(7) Shares shown represent shares of Common Stock that could be acquired
through the Edge Group II Exchange Offer.

(8) Shares shown represent 147,673 shares of Common Stock (of which 19,552
could be acquired through the Edge Group II Exchange Offer and the
remainder through the Merger) owned by the Trade Consultants, Inc. Pension
Plan, of which Mr. Raphael is the trustee, 43,060 shares of Common Stock
that could be acquired by Mr. Raphael's wife (of which 19,552 could be
acquired through the Edge Group II Exchange Offer and the remainder
through the Merger), and 84,120 shares that could be acquired directly by
Mr. Raphael (of which 19,552 shares could be acquired through the Edge
Group II Exchange Offer and the remainder through the Merger). Mr. Raphael
may be deemed the beneficial owner of shares of Common Stock held by the
Trade Consultants, Inc. Pension Plan and his wife. Mr. Raphael disclaims
such beneficial ownership.

(9) Shares shown represent (i) 858,853 shares of Common Stock that could be
acquired through the Merger by Edge Holding Company, a limited partnership
of which Mr. Sfondrini and Napamco are the general partners, (ii) 42,896
shares of stock which could be acquired in the Purchase Offer by Edge
Group, whose partners are certain limited partnerships, each of which Mr.
Sfondrini and Napamco are the general partners of and (iii) 352,361 shares
which could be acquired pursuant to the Edge Group II Exchange Offer. Mr.
Sfondrini may be deemed the beneficial owner of the shares which could be
acquired by Edge Holding Company and Edge Group. Mr. Sfondrini disclaims
such beneficial ownership. Mr. Sfondrini's address is the same as for Edge
Holding Company.

(10) Shares shown include 97,844 shares of Common Stock that may be acquired
pursuant to immediately exercisable stock options.

69
<PAGE>

SHARES ELIGIBLE FOR FUTURE SALE

Upon consummation of the Combination Transactions and this Offering,
approximately 6,682,000 shares of Common Stock will be outstanding. The shares
of Common Stock sold in this Offering and received in the Combination
Transactions will be registered under the Securities Act and will be freely
tradeable without restriction or further registration under the Securities
Act, except for certain manner of sale, volume limitations and other
restrictions with respect to any shares (i) purchased in this Offering or
received in connection with the Combination Transactions by an affiliate of
the Company (a "Company Affiliate"), which will be subject to the resale
limitations of Rule 144 (not including the holding period requirement) under
the Securities Act, and (ii) received in the Merger by any affiliates of Old
Edge or the Company (the "Prior Affiliates"), which may be resold by them only
pursuant to an effective registration statement under the Securities Act
covering such securities or in transactions permitted by the resale provisions
of Rule 145(d) under the Securities Act or as otherwise permitted under the
Securities Act. Under Rule 144 under the Securities Act, a person is an
affiliate of an entity if such person directly or indirectly controls or is
controlled by or is under common control with such entity and may include
certain officers and directors, principal shareholders and certain other
shareholders with special relationships. This Prospectus may not be used by
Company Affiliates or Prior Affiliates in connection with any resale of shares
of Common Stock acquired in the manner described in (i) and (ii) above.

In general, under Rule 144 as currently in effect, if a minimum of two years
has elapsed since the later of the date of acquisition of the restricted
securities from the issuer or from an affiliate of the issuer, a person (or
persons whose shares of Common Stock are aggregated), including persons who
may be deemed "affiliates" of the Company, would be entitled to sell within
any three-month period a number of shares of Common Stock that does not exceed
the greater of (i) 1% of the then-outstanding shares of Common Stock (i.e.,
66,820 shares immediately after consummation of this Offering) and (ii) the
average weekly trading volume during the four calendar weeks preceding the
date on which notice of the sale is filed with the Commission. Sales under
Rule 144 are also subject to certain provisions as to the manner of sale,
notice requirements and the availability of current public information about
the Company. In addition, under Rule 144(k), if a period of at least three
years has elapsed since the later of the date restricted securities were
acquired from the Company or the date they were acquired from an affiliate of
the Company, a stockholder who is not an affiliate of the Company at the time
of sale and who has not been an affiliate for at least three months prior to
the sale would be entitled to sell shares of Common Stock in the public market
immediately without compliance with the foregoing requirements under Rule 144.
Rule 144 does not require the same person to have held the securities for the
applicable periods. The foregoing summary of Rule 144 is not intended to be a
complete description thereof. The Commission has proposed an amendment to Rule
144 that would shorten the three- and two-year holding periods described above
to two years and one year, respectively.

Rule 145 requires that, in a resale of securities acquired in the Merger,
Prior Affiliates comply with a volume restriction and other restrictions on
the manner of sale and that certain information about the Company be currently
available to the public. The volume restriction limits the number of shares
that an affiliate may transfer, in the aggregate, within any three-month
period to the greater of (i) 1% of the outstanding Common Stock or (ii) the
average weekly reported trading volume in the Common Stock during the
preceding four calendar weeks. A Prior Affiliate may sell its shares of Common
Stock without regard to the volume restrictions and restrictions on the manner
of sale if it has owned the shares for at least two years, certain information
about the Company is currently available to the public and the Prior Affiliate
is not then a Company Affiliate. A Prior Affiliate may also sell its shares of
Common Stock without regard to the foregoing restrictions (including the
requirement that certain information about the Company is currently available
to the public) if it has held its shares of Common Stock for a period of at
least three years and such person has not been a Company Affiliate for at
least three months. A Prior Affiliate who is also a Company Affiliate may sell
its shares of Common Stock, subject to the volume restrictions and
restrictions on the manner of sale, if it has held the shares of Common Stock
for a period of at least two years and certain information about the Company
is currently available to the public.

The Company intends to file a registration statement on Form S-8 under the
Securities Act to register the shares of Common Stock reserved or to be
available for issuance pursuant to the Long-Term Incentive Plan.

70
<PAGE>

Shares of Common Stock issued pursuant to such plan generally will be
available for sale in the open market by holders who are not Company
Affiliates and, subject to the volume and other limitations of Rule 144, by
holders who are Company Affiliates.

The Company has also agreed with the Underwriters that it will not offer for
sale or otherwise voluntarily dispose of any shares of Common Stock or any
securities convertible into or exercisable for shares of Common Stock for a
period of 180 days after the date of this Prospectus without the prior written
consent of Raymond James & Associates, Inc., as representative of the
Underwriters, with certain exceptions. Additionally, the Company's Bylaws
restrict the sale of substantially all of the shares issued in the Combination
Transactions for a period of 180 days after the date of this Prospectus
without the prior consent of the Company and the Underwriters, subject to
certain exceptions. See "Underwriting."

Prior to this Offering, there has been no public market for the Common Stock
(or any equity interest for which the Common Stock will be issued in the
Combination Transactions), and no prediction can be made of the effect, if
any, that sales of Common Stock or the availability of shares for sale will
have on the market price prevailing from time to time. Following this
Offering, sales of substantial amounts of Common Stock in the public market or
otherwise, or the perception that such sales could occur, could adversely
affect the prevailing market price for the Common Stock.

71
<PAGE>

DESCRIPTION OF CAPITAL STOCK

The Company's authorized capital stock consists of 40,000,000 shares of
Common Stock and 10,000,000 shares of Preferred Stock. Following consummation
of this Offering and the Combination Transactions there will be approximately
6,682,000 shares of Common Stock outstanding (assuming the over-allotment
option is not exercised and that all parties accept shares of Common Stock in
the Combination Transactions), and no shares of Preferred Stock will be
outstanding. The following summary does not purport to be complete, and
reference is made to the more detailed provisions of the Company's Restated
Certificate of Incorporation (the "Certificate of Incorporation") and Bylaws,
which are filed as exhibits to the registration statement of which this
Prospectus is a part.

COMMON STOCK

The Common Stock possesses ordinary voting rights for the election of
directors and in respect of other corporate matters, each share being entitled
to one vote. There are no cumulative voting rights, meaning that the holders
of a majority of the shares voting for the election of directors can elect all
the directors if they choose to do so. The Common Stock carries no preemptive
rights and is not convertible, redeemable or assessable, or entitled to the
benefits of any sinking fund. The holders of Common Stock are entitled to
dividends in such amounts and at such times as may be declared by the Board of
Directors out of funds legally available therefor. See "Dividend Policy" for
information regarding dividend policy.

PREFERRED STOCK

The Board of Directors of the Company is empowered, without approval of the
stockholders, to cause shares of Preferred Stock to be issued in one or more
series, with the numbers of shares of each series to be determined by it. The
Board of Directors is authorized to fix and determine the powers,
designations, preferences and relative, participating, optional or other
rights (including, without limitation, voting powers, full or limited,
preferential rights to receive dividends or assets upon liquidation, rights of
conversion or exchange into Common Stock, Preferred Stock of any Series or
other securities, redemption provisions and sinking fund provisions) between
series and between the Preferred Stock or any series thereof and the Common
Stock, and the qualifications, limitations or restrictions of such rights.

Although the Company has no present intention to issue shares of Preferred
Stock, the issuance of shares of Preferred Stock, or the issuance of rights to
purchase such shares, could be used to discourage an unsolicited acquisition
proposal. For instance, the issuance of a series of Preferred Stock might
impede a business combination by including class voting rights that would
enable the holders to block such a transaction; or such issuance might
facilitate a business combination by including voting rights that would
provide a required percentage vote of the stockholders. In addition, under
certain circumstances, the issuance of Preferred Stock could adversely affect
the voting power of the holders of the Common Stock. Although the Board of
Directors is required to make any determination to issue such stock based on
its judgment as to the best interests of the stockholders of the Company, the
Board of Directors could act in a manner that would discourage an acquisition
attempt or other transaction that some or a majority of the stockholders might
believe to be in their best interests or in which stockholders might receive a
premium for their stock over the then market price of such stock. The Board of
Directors does not at present intend to seek stockholder approval prior to any
issuance of currently authorized stock, unless otherwise required by law or
the rules of any market on which the Company's securities are traded.

OTHER MATTERS

Delaware law authorizes corporations to limit or eliminate the personal
liability of directors to corporations and their stockholders for monetary
damages for breach of directors' fiduciary duty of care. The duty of care
requires that, when acting on behalf of the corporation, directors must
exercise an informed business judgment

72
<PAGE>

based on all material information reasonably available to them. Absent the
limitations authorized by Delaware law, directors are accountable to
corporations and their stockholders for monetary damages for conduct
constituting gross negligence in the exercise of their duty of care. Delaware
law enables corporations to limit available relief to equitable remedies such
as injunction or rescission. The Certificate of Incorporation limits the
liability of directors of the Company to the Company or its stockholders to
the fullest extent permitted by Delaware law. Specifically, directors of the
Company will not be personally liable for monetary damages for breach of a
director's fiduciary duty as a director, except for liability (i) for any
breach of the director's 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 law, (iii) for unlawful payments of
dividends or unlawful stock repurchases or redemptions as provided in Section
174 of the Delaware General Corporation Law or (iv) for any transaction from
which the director derived an improper personal benefit.

The inclusion of this provision in the Certificate of Incorporation may have
the effect of reducing the likelihood of derivative litigation against
directors, and may discourage or deter stockholders or management from
bringing a lawsuit against directors for breach of their duty of care, even
though such an action, if successful, might otherwise have benefited the
Company and its stockholders. The Company's Bylaws provide indemnification to
the Company's officers and directors and certain other persons with respect to
certain matters, and the Company has entered into agreements with each of its
directors providing for indemnification with respect to certain matters.

The Certificate of Incorporation provides that stockholders may act only at
an annual or special meeting of stockholders and may not act by written
consent. The Bylaws provide that special meetings of the stockholders can be
called only by the Chairman of the Board, the President or a majority of the
Board of Directors of the Company.

The Certificate of Incorporation provides that the Board of Directors shall
consist of three classes of directors serving for staggered three-year terms.
As a result, approximately one-third of the Company's Board of Directors will
be elected each year. The classified board provision could prevent a party who
acquires control of a majority of the outstanding voting stock of the Company
from obtaining control of the Board of Directors until the second annual
stockholders' meeting following the date the acquiror obtains the controlling
interest. See "Management."

The Certificate of Incorporation provides that the number of directors will
be no greater than 12 and no less than three. The Certificate of Incorporation
further provides that directors may be removed only for cause (as defined in
the Certificate of Incorporation), and then only by the affirmative vote of
the holders of at least a majority of all outstanding voting stock entitled to
vote. This provision, in conjunction with the provisions of the Certificate of
Incorporation authorizing the Board of Directors to fill vacant directorships,
will prevent stockholders from removing incumbent directors without cause and
filling the resulting vacancies with their own nominees. The Company's Bylaws
also provide that the Board of Directors will include at least a majority of
directors who are not employees of the Company. In addition, the Bylaws
provide that the Compensation Committee will consist solely of members who are
not employees of the Company and the Audit Committee will include at least a
majority of members who are not employees of the Company.

The Company is a Delaware corporation and is subject to Section 203 of the
Delaware General Corporation Law. In general, Section 203 prevents an
"interested stockholder" (defined generally as a person owning 15% or more of
a corporation's outstanding voting stock) 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 the transaction in which the interested stockholder
became an interested stockholder or approved the business combination; (ii)
upon consummation of the transaction that resulted in the interested
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

73
<PAGE>

the corporation and by employee stock plans that do not provide employees with
the right to determine confidentially whether shares held subject to the plan
will be tendered in a tender or exchange offer); or (iii) following the
transaction in which such person became an interested stockholder, the
business combination was 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, if such extraordinary transaction is approved or not
opposed by a majority of the directors who were directors prior to any person
becoming an interested stockholder during the previous three years or were
recommended for election or elected to succeed such directors by a majority of
such directors. No stockholder will be subject to the restrictions of Section
203 with respect to the Common Stock as a result of the Combination
Transactions.

STOCKHOLDER PROPOSALS

The Company's Bylaws contain provisions requiring that advance notice be
delivered to the Company of any business to be brought by a stockholder before
an annual meeting of stockholders, and providing for certain procedures to be
followed by stockholders in nominating persons for election to the Board of
Directors of the Company. Generally, such advance notice provisions provide
that written notice must be given to the Secretary of the Company by a
stockholder (i) in the event of business to be brought by a stockholder before
an annual meeting, not less than 45 days prior to the anniversary date of the
immediately preceding annual meeting of stockholders of the Company (with
certain exceptions if the date of the annual meeting is different by more than
specified amounts from the anniversary date) and (ii) in the event of
nominations of persons for election to the Board of Directors by any
stockholder, (a) with respect to an election to be held at the annual meeting
of stockholders, not less than 45 days prior to the anniversary date of the
immediately preceding annual meeting of stockholders of the Company (with
certain exceptions if the date of the annual meeting is different by more than
specified amounts from the anniversary date) and (b) with respect to an
election to be held at a special meeting of stockholders for the election of
directors, not later than the close of business on the tenth day following the
day on which notice of the date of the special meeting was mailed to
stockholders or public disclosure of the date of the special meeting was made,
whichever first occurs. Such notice must set forth specific information
regarding such stockholder and such business or director nominee, as described
in the Company's Bylaws.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for the Common Stock is American Securities
Transfer & Trust, Inc.

74
<PAGE>

UNDERWRITING

Subject to the terms and conditions set forth in the Underwriting Agreement
(the "Underwriting Agreement"), the Company has agreed to sell to each of the
Underwriters named below (the "Underwriters") and each of the Underwriters
named below, for whom Raymond James & Associates, Inc., Jefferies & Company,
Inc. and Principal Financial Securities, Inc. are acting as Representatives
(the "Representatives"), has severally agreed to purchase from the Company the
respective number of shares set forth opposite their names below:

<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITER SHARES
----------- ----------
<S> <C>
Raymond James & Associates, Inc. ..............................
Jefferies & Company, Inc. .....................................
Principal Financial Securities, Inc. ..........................

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

The Underwriting Agreement provides that the obligations of the several
Underwriters to pay for and accept delivery of the shares of Common Stock are
subject to certain conditions precedent. The nature of the Underwriters'
obligations under the Underwriting Agreement is such that they are obligated
to purchase all of the shares of Common Stock offered hereby (other than the
shares subject to the over-allotment option described below) if any are
purchased. In the event of a failure by any Underwriter to purchase its
portion of the Common Stock, the Underwriting Agreement provides, depending
upon the total number of shares of Common Stock involved in the default, that
the purchase commitments of the other Underwriters may be increased or that
the Underwriting Agreement may be terminated, without prejudice to the right
of any party as against any defaulting Underwriter.

The Underwriters propose to offer part of the Common Stock directly to the
public at the price set forth on the cover page of this Prospectus. The
Underwriters may allow a concession to selected dealers who are members of the
National Association of Securities Dealers, Inc. (the "NASD") not in excess of
$. per share, and the Underwriters may allow and such dealers may reallow
to members of the NASD a concession not to exceed $. per share. After this
Offering, the public offering price and other selling terms may be varied by
the Representatives. The Underwriters do not intend to confirm sales to any
account over which they exercise discretionary authority.

The Company has granted the Underwriters an option, exercisable during the
30-day period immediately following the date of this Prospectus, to purchase
at the public offering price, less the underwriting discounts and commissions,
up to 300,000 additional shares of Common Stock, solely to cover over-
allotments, if any, in the sale of the shares that the Underwriters have
agreed to purchase. In such event, the Underwriters have severally agreed,
subject to certain conditions, to each purchase a percentage of the over-
allotment shares approximately equal to the percentage of the initial shares
purchased by the Underwriters.

The Company has agreed to indemnify the Underwriters and certain related
persons against certain civil liabilities relating to this Offering, including
liabilities under the Securities Act.

75
<PAGE>

The Company, may not, without the prior written consent of the
Representatives, offer, sell, contract to sell or otherwise dispose of any
shares of Common Stock or rights, to purchase shares of Common Stock or any
other securities convertible into or exercisable or exchangeable for shares of
Common Stock (other than employee options and options pursuant to the
Company's Long-Term Incentive Plan or options pursuant to acquisitions in
which the shares issued remain subject to a lock-up agreement) for a period of
180 days from the date of this Prospectus. Additionally, under the Company's
Bylaws the holders of the shares of Common Stock issued in the Combination
Transactions (who will beneficially own an aggregate of approximately
4,682,000 shares of Common Stock upon the completion of this Offering, may not
sell such shares for a period of 180 days from the date of this Prospectus,
other than certain private transfers in which the transferee assumes such
transfer restrictions. Following the consummation of this Offering, Mr.
Sfondrini expects to enter into a margin loan arrangement with one of the
Representatives. Under this arrangement, Mr. Sfondrini expects to make
borrowings in an approximate amount of at least $650,000 at an interest rate
equal to a published prime rate. The loan will be secured by Common Stock with
an initial market value of $1.5 million (valued at the initial public offering
price).

Prior to this Offering, there has been no public market for the Common
Stock. The initial public offering price of the Common Stock will be
negotiated between the Company and the representatives of the Underwriters.
Among the factors to be considered in determining the initial public offering
price of the Common Stock, in addition to prevailing market conditions, will
be the cash flow and earnings of the Company and comparable companies in
recent periods, the Company's business potential and cash flow and earning
prospects, current and historical natural gas and oil prices, current and
prospective conditions in the supply and demand for natural gas and oil,
reserve and production quantities for the Company's natural gas and oil
properties, the history of, and prospects for, the industry in which the
Company operates, and the price earnings multiples of publicly traded common
stocks of comparable companies.

LEGAL MATTERS

Certain legal matters in connection with the shares of Common Stock offered
hereby are being passed upon for the Company by Baker & Botts, L.L.P.,
Houston, Texas, and for the Underwriters by Vinson & Elkins L.L.P., Houston,
Texas.

EXPERTS

The Combined Financial Statements of Old Edge, affiliates and direct
interests as of September 30, 1996, December 31, 1995 and 1994, for the nine
month period ended September 30, 1996 and for each of the three years in the
period ended December 31, 1995 and the Balance Sheet of the Company as of
December 3, 1996, included in this Prospectus, have been audited by Deloitte &
Touche llp, independent auditors, as stated in their reports appearing herein,
and have been so included in reliance upon the reports of such firm given upon
their authority as experts in accounting and auditing.

The letter report of Ryder Scott included as Annex A to this Prospectus and
certain information with respect to the Company's oil and natural gas reserves
derived therefrom have been included herein in reliance upon such firm as
experts with respect to such matters.

76
<PAGE>

ADDITIONAL INFORMATION

The Company has not previously been subject to the reporting requirements of
the Exchange Act. The Company has filed a Registration Statement on Form S-1
(the "Form S-1 Registration Statement") under the Securities Act with the
Commission with respect to this Offering. The Company has also filed a
Registration Statement on Form S-4 (the "Form S-4 Registration Statement")
under the Securities Act with the Commission with respect to the Combination
Transactions. This Prospectus, filed as a part of the Form S-1 Registration
Statement, does not contain all of the information set forth in the Form S-1
Registration Statement or the exhibits and schedules thereto in accordance
with the rules and regulations of the Commission, and reference is hereby made
to such omitted information. Statements made in this Prospectus concerning any
document filed as an exhibit to the Form S-1 Registration Statement are not
necessarily complete, and in each instance reference is made to such exhibit
for a complete statement of its provisions. The Form S-1 Registration
Statement, the Form S-4 Registration Statement and the exhibits and schedules
thereto may be inspected, without charge, at the public reference facilities
of the Commission at its principal office at Judiciary Plaza, 450 Fifth
Street, N.W., Room 1024, Washington, D.C. 20549, and its regional offices at
Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661,
and at 7 World Trade Center, 13th Floor, New York, New York 10048. Copies of
all or any portion of the Form S-1 Registration Statement and the Form S-4
Registration Statement can be obtained at prescribed rates from the Public
Reference Section of the Commission at its principal office at Judiciary
Plaza, 450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549. The
Commission maintains an Internet web site that contains reports, proxy and
information statements and other information regarding registrants that file
electronically with the Commission (http://www.sec.gov).

77
<PAGE>

GLOSSARY OF CERTAIN INDUSTRY TERMS

The definitions set forth below shall apply to the indicated terms as used
in this Prospectus. All volumes of natural gas referred to herein are stated
at the legal pressure base of the state or area where the reserves exist and
at 60 degrees Fahrenheit and in most instances are rounded to the nearest
major multiple.

After payout. With respect to an oil or gas interest in a property, refers
to the time period after which the costs to drill and equip a well have been
recovered.

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

Bbls/d. Stock tank barrels per day.

Bcf. Billion cubic feet.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Before payout. With respect to an oil or gas interest in a property, refers
to the time period before which the costs to drill and equip a well have been
recovered.

Completion. The installation of permanent equipment for the production of
oil or gas or, in the case of a dry hole, the reporting of abandonment to the
appropriate agency.

Developed acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.

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

Dry hole or well. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.

Exploratory well. A well drilled to find and produce oil or gas reserves not
classified as proved, 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.

Farm-in or farm-out. An agreement whereunder the owner of a working interest
in an oil and natural gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage.
Generally, the assignee is required to drill one or more wells in order to
earn its interest in the acreage. The assignor usually retains a royalty or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out."

Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.

Finding costs. Costs associated with acquiring and developing proved oil and
natural gas reserves which are capitalized by the Company pursuant to
generally accepted accounting principles, including all costs involved in
acquiring acreage, geological and geophysical work and the cost of drilling
and completing wells.

Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.

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

78
<PAGE>

MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per
day.

Mcf. One thousand cubic feet.

Mcf/d. One thousand cubic feet per day.

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

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

MMcf. One million cubic feet.

MMcf/d. One million cubic feet per day.

MMcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids,
which approximates the relative energy content of crude oil, condensate and
natural gas liquids as compared to natural gas. Prices have historically been
higher or substantially higher for crude oil than natural gas on an energy
equivalent basis.

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

Normally pressured reservoirs. Reservoirs with a formation-fluid pressure
equivalent to 0.465 psi per foot of depth from the surface. For example, if
the formation pressure is 4,650 psi at 10,000 feet, then the pressure is
considered to be normal.

Over-pressured reservoirs. Reservoirs subject to abnormally high pressure as
a result of certain types of subsurface formations.

Petrophysical study. Study of rock and fluid properties based on well log
and core analysis.

Present value. When used with respect to oil and natural gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using
prices and costs in effect as of the date indicated, without giving effect to
nonproperty-related expenses such as general and administrative expenses, debt
service and future income tax expense or to depreciation, depletion and
amortization, discounted using an annual discount rate of 10%.

Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

Proved developed nonproducing reserves. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.

Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.

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

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

79
<PAGE>

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

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

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

Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible oil and/or gas that is confined by impermeable rock
or water barriers and is individual and separate from other reservoirs.

Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or gas production free of costs of production.

3-D seismic. Advanced technology method of detecting accumulations of
hydrocarbons identified through a three-dimensional picture of the subsurface
created by the collection and measurement of the intensity and timing of sound
waves transmitted into the earth as they reflect back to the surface.

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 natural gas regardless of whether such acreage contains proved
reserves.

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

Workover. Operations on a producing well to restore or increase production.

80
<PAGE>

INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
EDGE PETROLEUM CORPORATION UNAUDITED PRO FORMA COMBINED FINANCIAL
STATEMENTS:
Pro Forma Combined Balance Sheet (Unaudited), September 30, 1996........ F-3
Notes to Unaudited Pro Forma Combined Financial Statements.............. F-5
EDGE PETROLEUM CORPORATION (A DELAWARE CORPORATION):
Independent Auditors' Report............................................ F-8
Balance Sheet, December 3, 1996......................................... F-9
Notes to Balance Sheet.................................................. F-10
EDGE PETROLEUM CORPORATION (A TEXAS CORPORATION), AFFILIATED ENTITIES AND
DIRECT INTERESTS:
Independent Auditors' Report............................................ F-11
Combined Balance Sheets, September 30, 1996, December 31, 1995 and 1994. F-12
Combined Statements of Operations for the Nine Month Period Ended
September 30, 1996 and 1995 (unaudited) and the Years Ended December
31, 1995, 1994 and 1993................................................ F-13
Combined Statements of Equity for the Nine Month Period Ended September
30, 1996 and the Years Ended December 31, 1995, 1994 and 1993.......... F-14
Combined Statements of Cash Flows for the Nine Month Period Ended
September 30, 1996 and 1995 (unaudited) and the Years Ended December
31, 1995, 1994 and 1993................................................ F-15
Notes to Combined Financial Statements.................................. F-16
</TABLE>

F-1
<PAGE>

EDGE PETROLEUM CORPORATION
(A RECENTLY FORMED DELAWARE CORPORATION)

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

The following unaudited Pro Forma Combined Balance Sheet and notes to
unaudited Pro Forma Combined Financial Statements are presented to show the
pro forma effects of the proposed Combination (as defined in Note 2) hereto
and Offering in which Edge Petroleum Corporation, a recently formed Delaware
corporation (the "Company"), will issue up to 4,682,273 shares of its common
stock for the combined net assets of Edge Petroleum Corporation (a Texas
corporation) ("Old Edge"), affiliated entities and direct interests and will
issue 2,000,000 shares of previously unissued common stock in a public
offering of shares. For a more complete description of these transactions see
Note 2 hereto.

Pro forma data are based on assumptions and include adjustments as explained
in the notes to the unaudited Pro Forma Combined Financial Statements. The
unaudited Pro Forma Combined Balance Sheet of the Company was prepared
utilizing the combined historical financial statements of the combined
predecessor entities as described in Note 2 hereto. Note 3 to the unaudited
Pro Forma Combined Financial Statements discloses the pro forma effects of the
Combination and the Offering on the historical income statement of the
combined predecessor entities. The unaudited Pro Forma Combined Financial
Statements are not necessarily indicative of the results of future operations
of the Company and should be read in conjunction with the historical combined
financial statements of Old Edge, affiliated entities and direct interests
appearing elsewhere in this Prospectus.

F-2
<PAGE>

EDGE PETROLEUM CORPORATION
(A RECENTLY FORMED DELAWARE CORPORATION)

PRO FORMA COMBINED BALANCE SHEET (UNAUDITED)

SEPTEMBER 30, 1996

<TABLE>
<CAPTION>
EDGE
PETROLEUM
CORPORATION COMBINED PRO FORMA PRO FORMA
DECEMBER 3, PREDECESSOR PRO FORMA FOR THE PRO FORMA FOR THE
ASSETS 1996 ENTITIES ADJUSTMENTS COMBINATION ADJUSTMENTS OFFERING
------ ----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
CURRENT ASSETS:
Cash and cash
equivalents.......... $1,000 $ 930,581 $ 931,581 $19,560,010 (4) $20,491,591
Accounts receivable,
trade................ 1,649,557 1,649,557 1,649,557
Accounts receivable,
joint interest
owners............... 2,375,953 2,375,953 2,375,953
Receivables from
related parties...... 183,288 183,288 183,288
Other current assets.. 134,967 134,967 134,967
Advance to
stockholder.......... 3,371 3,371 3,371
------ ----------- ------- ----------- ----------- -----------
Total current assets. 1,000 5,277,717 5,278,717 19,560,010 24,838,727
PROPERTY AND EQUIPMENT,
Net--full cost method
of accounting for oil
and gas property..... 12,384,029 12,384,029 12,384,029
DEFERRED OFFERING COSTS. 750,000 750,000 (750,000)(3)
OTHER ASSETS............ 23,751 23,751 23,751
------ ----------- ------- ----------- ----------- -----------
TOTAL ASSETS............ $1,000 $18,435,497 $18,436,497 $18,810,010 $37,246,507
====== =========== ======= =========== =========== ===========
</TABLE>

F-3
<PAGE>

EDGE PETROLEUM CORPORATION
(A RECENTLY FORMED DELAWARE CORPORATION)

PRO FORMA COMBINED BALANCE SHEET (UNAUDITED)--(CONTINUED)

SEPTEMBER 30, 1996

<TABLE>
<CAPTION>
EDGE
PETROLEUM
CORPORATION COMBINED PRO FORMA PRO FORMA
LIABILITIES AND DECEMBER 3, PREDECESSOR PRO FORMA FOR THE PRO FORMA FOR THE
STOCKHOLDERS' EQUITY 1996 ENTITIES ADJUSTMENTS COMBINATION ADJUSTMENTS OFFERING
-------------------- ----------- ----------- ------------ ----------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
CURRENT LIABILITIES:
Accounts payable,
trade................ $2,459,510 $2,459,510 $2,459,510
Accounts payable to
related party........ 1,372,450 $(1,332,450) (2) 40,000 40,000
Accrued interest
payable.............. 62,625 62,625 62,625
Accrued liabilities... 342,652 342,652 $ (250,041)(4) 92,611
Accounts payable,
joint interest
owners............... 2,325,342 2,325,342 2,325,342
Current portion of
notes payable........ 316,030 316,030 316,030
------ ----------- ------------ ----------- ----------- -----------
Total current
liabilities......... 6,878,609 (1,332,450) 5,546,159 (250,041) 5,296,118
NOTES PAYABLE........... 10,132,919 10,132,919 (9,949,949)(4) 182,970
LONG-TERM LIABILITY..... 11,462 11,462 11,462
------ ----------- ------------ ----------- ----------- -----------
Total liabilities.... 17,022,990 (1,332,450) 15,690,540 (10,199,990) 5,490,550
Common stock, $.01 par
value; 40,000,000
shares authorized;
4,682,273 shares
issued and
outstanding pro forma
for the combination;
6,682,000 shares
issued outstanding
pro forma for the
offering............. $ 10 46,820 (1) 46,830 20,000 (4) 66,830
Additional paid-in
capital.............. 990 1,365,687 (1) 2,699,127 29,740,000 (4) 31,689,127
1,332,450 (2) (750,000)(3)
Retained earnings.....
Combined equity of
predecessor entities. 1,412,507 (1,412,507)(1)
------ ----------- ------------ ----------- ----------- -----------
Total stockholders'
equity.............. 1,000 1,412,507 1,332,450 2,745,957 29,010,000 31,755,957
------ ----------- ------------ ----------- ----------- -----------
TOTAL LIABILITIES AND
STOCKHOLDERS' EQUITY... $1,000 $18,435,497 $ 0 $18,436,497 $18,810,010 $37,246,507
====== =========== ============ =========== =========== ===========
</TABLE>

See notes to unaudited pro forma combined financial statements.

F-4
<PAGE>

EDGE PETROLEUM CORPORATION
(A RECENTLY FORMED DELAWARE CORPORATION)

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

1. BASIS OF PRESENTATION

The Combination will be accounted for as a reorganization of entities under
common control because of the high degree of common control of the stockholders
of the Company and by virtue of their direct ownership of the entities and
interests exchanged. Accordingly, the net assets acquired in the exchange
transactions will be recorded at the historical cost basis of the affiliate
predecessor owners.

2. BALANCE SHEET PRO FORMA ADJUSTMENTS

The Pro Forma Combined Balance Sheet is based on the unaudited combined
balance sheet of Edge Petroleum Corporation, a Texas corporation, affiliated
entities and direct interests (collectively, the "Combined Predecessor
Entities") as of September 30, 1996, and gives effect to the consummation of
the Combination and the Offering as if such transactions had occurred on
September 30, 1996 reflecting the adjustments and assumptions described below:

(1) Reflects the proposed issuance of up to 4,682,273 shares of common
stock of the Company in connection with the exchange offer, merger and
acquisition transactions for the combined net assets of the Combined
Predecessor Entities (the "Combination"). Accordingly, the combined equity
of the Combined Predecessor Entities was reclassified to common stock and
additional paid-in capital.

(2) Reflects the satisfaction of an accrued administrative fee due the
General Partner of Edge Group II, a Combined Predecessor Entity, which will
be purchased with common stock of the Company, as a component of the
exchange offer transactions.

(3) Reflects the elimination of deferred offering costs accrued by the
Predecessor Affiliated Entities which will be reimbursed by the Company
from proceeds received from the Offering.

(4) Reflects the receipt of the net proceeds from the Offering and the
application thereof to repay approximately $8.6 million of indebtedness
incurred on the revolving credit facility, approximately $1.3 million of
subordinated indebtedness and approximately $250,000 of accrued offering
costs. It is assumed the remaining proceeds will be used to increase
working capital until used for oil and gas exploration activities.

F-5
<PAGE>

EDGE PETROLEUM CORPORATION
(A RECENTLY FORMED DELAWARE CORPORATION)

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS--(CONTINUED)

3. INCOME STATEMENT PRO FORMA ADJUSTMENTS

The net proceeds to the Company from this Offering at an assumed initial
public offering price of $16.00 per share are estimated to be approximately
$29.0 million ($33.8 million if the Underwriters' over allotment option is
exercised in full). The Company intends to use a portion of the net proceeds
to lend funds to the Joint Venture to be used to repay approximately $8.6
million of indebtedness incurred under the Revolving Credit Facility that
currently bears interest at 8% and matures on June 1, 1998 and approximately
$1.3 million of subordinated indebtedness that currently bears interest at 10%
and matures on April 8, 1998. The remainder of the net proceeds will be used
to provide working capital to the Company and for general corporate purposes,
including funding the Company's exploration, development and acquisition
activities. Following application of the proceeds of this Offering, the
Company anticipates that its only long-term indebtedness will consist of an
aggregate of approximately $441,000 principal amount of equipment loans.
Assuming this Offering had been completed at the beginning of the respective
periods, interest expense would have been reduced by $320,506 and $674,949 for
the year ended December 31, 1995 and the nine month period ended September 30,
1996. As a result, pro forma net income and earnings per share would have been
$1,399,286 and $0.26, respectively, for the year ended December 31, 1995 and
$1,072,614 and $0.20, respectively, for the nine month period ended September
30, 1996.

4. ACCEPTANCE OF THE OFFER

The following table shows the Pro Forma Combined Balance Sheet and Statement
of Operations amounts assuming varying levels of acceptance of the exchange
offer by limited partnership unit holders in Edge Group II:

PRO FORMA COMBINED BALANCE SHEET, SEPTEMBER 30, 1996

<TABLE>
<CAPTION>
ASSETS 70% 80% 90%
------ ----------- ----------- -----------
<S> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................ $ 836,269 $ 862,971 $ 889,673
Accounts receivable, trade............... 1,275,543 1,386,709 1,497,875
Accounts receivable, joint interest
owners.................................. 2,099,530 2,172,528 2,245,526
Accounts receivable from related parties. 183,063 183,138 183,138
Advances to stockholders................. 3,371 3,371 3,371
Other current assets..................... 108,153 115,744 123,334
----------- ----------- -----------
Total current assets................... 4,505,929 4,724,461 4,942,917
PROPERTY AND EQUIPMENT, Net--full cost
method of accounting for oil and gas
property.................................. 9,440,070 10,273,528 11,106,950
DEFERRED OFFERING COSTS.................... 571,568 622,080 672,593
OTHER ASSETS............................... 21,680 22,678 23,676
----------- ----------- -----------
TOTAL...................................... $14,539,247 $15,642,747 $16,746,136
=========== =========== ===========
<CAPTION>
LIABILITIES AND EQUITY
----------------------
<S> <C> <C> <C>
CURRENT LIABILITIES:
Accounts payable, trade.................. $ 1,893,866 $ 2,054,295 $ 2,214,649
Accounts payable, joint interests owners. 2,325,342 2,325,342 2,325,342
Accounts payable to related party........ 797,142 980,592 1,164,042
Accrued interest payable................. 18,201 18,201 18,201
Accrued liabilities...................... 317,990 346,948 375,906
Current portion of notes payable......... 240,843 262,128 283,412
----------- ----------- -----------
Total current liabilities.............. 5,593,384 5,987,506 6,381,552
NOTES PAYABLE.............................. 7,722,196 8,404,648 9,087,100
LONG-TERM LIABILITY........................ 11,462 11,462 11,462
COMMITMENTS AND CONTINGENCIES.............. -- -- --
----------- ----------- -----------
Total liabilities...................... 13,327,042 14,403,616 15,480,114
EQUITY..................................... 1,212,205 1,239,131 1,266,022
----------- ----------- -----------
TOTAL...................................... $14,539,247 $15,642,747 $16,746,136
=========== =========== ===========
</TABLE>

F-6
<PAGE>

EDGE PETROLEUM CORPORATION
(A RECENTLY FORMED DELAWARE CORPORATION)

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS--(CONTINUED)
<TABLE>
<S> <C> <C> <C>
PRO FORMA COMBINED STATEMENT OF
OPERATIONS FOR THE NINE MONTH PERIOD
ENDED SEPTEMBER 30, 1996
<CAPTION>
70% 80% 90%
---------- ---------- -----------
<S> <C> <C> <C>
Oil and natural gas sales.............. $3,895,526 $4,237,938 $4,580,351
---------- ---------- -----------
Operating expenses:
Oil and natural gas operating
expenses............................ 542,577 590,378 638,179
Depreciation, depletion and
amortization........................ 925,684 1,006,946 1,088,208
General and administrative........... 1,643,711 1,801,940 1,960,169
---------- ---------- -----------
Total operating expenses 3,111,972 3,399,264 3,686,556
---------- ---------- -----------
Net income............................. 783,554 838,674 893,795
Pro forma provision in lieu of taxes...
---------- ---------- -----------
Pro forma net income................... $ 783,554 $ 838,674 $ 893,795
========== ========== ===========
Net income per share................... $0.20 $0.20 $0.21
========== ========== ===========
Average common share outstanding (in
thousands)............................ 3,881 4,102 4,322
========== ========== ===========

PRO FORMA COMBINED STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31, 1995

<CAPTION>
70% 80% 90%
---------- ---------- -----------
<S> <C> <C> <C>
Oil and natural gas sales.............. $1,560,765 $1,696,558 $1,832,351
Operating Expenses:
Oil and natural gas operating
expenses............................ 523,871 569,892 615,914
Depreciation, depletion and
amortization........................ 624,864 678,238 731,611
General and administrative........... 1,808,008 1,985,016 2,162,023
---------- ---------- -----------
Total operating expenses........... 2,956,743 3,233,146 3,509,548
Loss from operations................... (1,395,978) (1,536,588) (1,677,197)
Other income and expenses:.............
Gain on sale of oil and gas property. 2,543,152 2,767,905 2,992,657
---------- ---------- -----------
Net income............................. 1,147,174 1,231,317 1,315,460
Pro forma provision in lieu of income
taxes.................................
---------- ---------- -----------
Pro forma net income................... $1,147,174 $1,231,317 $1,315,460
========== ========== ===========
Net income per share................... $0.30 $0.30 $0.30
========== ========== ===========
Average common shares outstanding (in
thousands)............................ 3,881 4,102 4,322
========== ========== ===========
</TABLE>

The amounts shown above assume consummation of the merger transaction with
Old Edge and do not include any amounts attributable to Gulfedge, Edge Group
or the Calaway Interests, which collectively do not materially affect the
results. Holders of at least 70% of the outstanding Edge Group II limited
partnership units must tender their interests for the Combination to occur.

F-7
<PAGE>

INDEPENDENT AUDITORS' REPORT

To Edge Petroleum Corporation:

We have audited the accompanying balance sheet of Edge Petroleum Corporation,
a recently formed Delaware corporation (the "Company"), as of December 3, 1996.
This financial statement is the responsibility of the Company's management. Our
responsibility is to express an opinion on this financial statement based on
our audit.

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

In our opinion, the balance sheet referred to above presents fairly, in all
material respects, the financial position of Edge Petroleum Corporation as of
December 3, 1996, in conformity with generally accepted accounting principles.

DELOITTE & TOUCHE LLP

Houston, Texas

December 3, 1996

F-8
<PAGE>

EDGE PETROLEUM CORPORATION
(A RECENTLY FORMED DELAWARE CORPORATION)

BALANCE SHEET

<TABLE>
<CAPTION>
DECEMBER 3,
ASSETS 1996
- ------ -----------
<S> <C>
Cash............................................................... $1,000
======
<CAPTION>
STOCKHOLDERS' EQUITY
- --------------------
<S> <C>
Preferred stock; $.01 par value, 10,000,000 shares authorized; no
shares issued and outstanding..................................... $ --
Common stock; $.01 par value, 40,000,000 shares authorized; 1,000
shares issued and outstanding..................................... 10
Additional paid-in capital......................................... 990
------
Total stockholders' equity....................................... $1,000
======
</TABLE>

The accompanying notes are an integral part of this balance sheet.

F-9
<PAGE>

EDGE PETROLEUM CORPORATION
(A RECENTLY FORMED DELAWARE CORPORATION)

NOTES TO BALANCE SHEET

1. ORGANIZATION

Edge Petroleum Corporation (the "Company") was organized as a Delaware
corporation in August 1996 in connection with a pending combination of certain
properties and businesses (the "Combined Assets") in anticipation of the
closing of its proposed initial public offering of common stock. The Combined
Assets will consist of ownership interests in certain entities (the
"Predecessor Entities") and direct interests in oil and gas properties
currently held by Edge Joint Venture II (the "Joint Venture"). In the
"Combination Transactions," the Company plans to complete (i) a merger (the
"Merger") of Old Edge with Edge Mergeco, Inc. ("Mergeco"), a wholly owned
subsidiary of the Company organized for this purpose, in which the shareholders
of Old Edge will receive common stock, (ii) an exchange offer (the "Edge Group
II Exchange Offer") to the general and limited partners of Edge Group II
Limited Partnership ("Edge Group II") in which such partners will have the
opportunity to exchange their interests in Edge Group II for common stock,
(iii) an exchange offer (the "Gulfedge Exchange Offer" and, together with the
Edge Group II Exchange Offer, the "Limited Partnership Exchange Offers") to the
limited partners of Gulfedge Limited Partnership, of which Old Edge is the
general partner ("Gulfedge" and, together with Edge Group II, the "Limited
Partnerships"), in which such limited partners will have the opportunity to
exchange their interests in Gulfedge for common stock; (iv) an offer to
purchase (the "Purchase Offer") from Edge Group Partnership ("Edge Group") its
interest in the Joint Venture, for consideration consisting of common stock;
and (v) an exchange (the "Calaway Exchange") of interests in certain oil and
gas properties held by Mr. James C. Calaway ("Mr. J.C. Calaway") for common
stock. Upon consummation of the Combination Transactions, the Company expects
to acquire directly or indirectly substantially all of the interests in the
Joint Venture.

2. PREFERRED STOCK

The Board of Directors of the Company is empowered, without approval of the
stockholders, to cause shares of preferred stock to be issued in one or more
series, with the number of shares of each series to be determined by the Board.
The Board of Directors is authorized to fix and determine variations in the
voting power designations, preferences, and relative, participating, optional
or other special rights (including, without limitation, special voting rights,
rights to receive dividends or assets upon liquidation, rights of conversion
into common stock or other securities, redemption provisions and sinking fund
provisions) between series and between the preferred stock and common stock.

F-10
<PAGE>

INDEPENDENT AUDITORS' REPORT

To the Stockholders of
Edge Petroleum Corporation,
a Texas corporation

We have audited the accompanying combined balance sheets of Edge Petroleum
Corporation, a Texas corporation ("Old Edge"), affiliated entities and direct
interests (collectively, the "Company") as of December 31, 1994 and, 1995 and
September 30, 1996, and the related combined statements of operations, equity
(deficit) and cash flows for each of the three years in the period ended
December 31, 1995 and the nine month period ended September 30, 1996. These
financial statements are the responsibility of the entities' management. Our
responsibility is to express an opinion on these 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, such financial statements present fairly, in all material
respects, the combined financial position of the Company at December 31, 1994
and, 1995 and September 30, 1996, and the combined results of their operations
and cash flows for each of the three years in the period ended December 31,
1995 and the nine month period ended September 30, 1996, in conformity with
generally accepted accounting principles.

DELOITTE & TOUCHE LLP

Houston, Texas

January 13, 1997

F-11
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

COMBINED BALANCE SHEETS

<TABLE>
<CAPTION>
DECEMBER 31,
---------------------- SEPTEMBER 30,
ASSETS 1994 1995 1996
------ ---------- ---------- -------------
<S> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents............... $ 348,919 $ 200,831 $ 930,581
Accounts receivable, trade.............. 1,228,018 1,167,920 1,649,535
Accounts receivable, joint interest
owners................................. 120,252 333,552 2,375,953
Accounts receivable from related
parties................................ 95,035 118,515 183,288
Advances to stockholders................ 30,982 30,826 3,371
Other current assets.................... 53,732 36,954 134,967
---------- ---------- -----------
Total current assets.................. 1,876,938 1,888,598 5,277,717
PROPERTY AND EQUIPMENT, Net--full cost
method of accounting for oil and gas
property................................. 4,135,959 7,911,068 12,384,029
DEFERRED OFFERING COSTS................... 750,000
OTHER ASSETS.............................. 115,041 58,541 23,751
---------- ---------- -----------
TOTAL..................................... $6,127,938 $9,858,207 $18,435,497
========== ========== ===========
<CAPTION>
LIABILITIES AND EQUITY
----------------------
<S> <C> <C> <C>
CURRENT LIABILITIES:
Accounts payable, trade................. $ 724,151 $1,144,408 $ 2,459,510
Accounts payable, joint interests
owners................................. 2,325,342
Accounts payable to related party....... 1,039,337 1,305,827 1,372,450
Accrued interest payable................ 33,422 46,418 62,625
Accrued liabilities..................... 109,675 160,493 342,652
Current portion of notes payable........ 943,767 178,898 316,030
---------- ---------- -----------
Total current liabilities............. 2,850,352 2,836,044 6,878,609
NOTES PAYABLE............................. 3,233,722 5,945,076 10,132,919
LONG-TERM LIABILITY....................... 77,802 46,245 11,462
COMMITMENTS AND CONTINGENCIES............. -- -- --
---------- ---------- -----------
Total liabilities..................... 6,161,876 8,827,365 17,022,990
EQUITY (DEFICIT).......................... (33,938) 1,030,842 1,412,507
---------- ---------- -----------
TOTAL..................................... $6,127,938 $9,858,207 $18,435,497
========== ========== ===========
</TABLE>

See notes to combined financial statements.

F-12
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

COMBINED STATEMENTS OF OPERATIONS

<TABLE>
<CAPTION>
NINE MONTH
PERIOD ENDED
DECEMBER 31, SEPTEMBER 30,
------------------------------------- -----------------------
1993 1994 1995 1995 1996
------------ ---------- ----------- ----------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
OIL AND NATURAL GAS
SALES.................. $ 1,455,438 $1,993,796 $ 2,040,446 $1,376,905 $5,105,079
------------ ---------- ----------- ---------- ----------
OPERATING EXPENSES:
Oil and natural gas
operating expenses... 166,817 304,627 686,438 502,289 711,430
Depreciation,
depletion and
amortization......... 441,710 593,398 813,402 525,111 1,212,738
General and
administrative....... 1,733,949 2,026,499 2,483,560 2,069,763 2,125,827
------------ ---------- ----------- ---------- ----------
Total operating
expenses........... 2,342,476 2,924,524 3,983,400 3,097,163 4,049,995
------------ ---------- ----------- ---------- ----------
OPERATING INCOME (LOSS). (887,038) (930,728) (1,942,954) (1,720,258) 1,055,084
OTHER INCOME AND
EXPENSES:
Interest expense...... (635,538) (384,927) (315,342) (195,100) (657,419)
Gain on sale of oil
and gas property..... 247,321 2,284,419 3,337,076 3,134,287
------------ ---------- ----------- ---------- ----------
NET INCOME (LOSS)....... (1,275,255) 968,764 1,078,780 1,218,929 397,665
PRO FORMA PROVISION IN
LIEU OF INCOME TAXES
(UNAUDITED)(Note 5)....
------------ ---------- ----------- ---------- ----------
PRO FORMA NET INCOME
(LOSS) (UNAUDITED)..... ($1,275,255) $ 968,764 $ 1,078,780 $1,218,929 $ 397,665
============ ========== =========== ========== ==========
</TABLE>

See notes to combined financial statements.

F-13
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

COMBINED STATEMENTS OF EQUITY

<TABLE>
<S> <C>
BALANCE, JANUARY 1, 1993........................................... $ 284,553
Net loss......................................................... (1,275,255)
-----------
BALANCE, DECEMBER 31, 1993......................................... (990,702)
Net income....................................................... 968,764
Treasury stock acquired.......................................... (24,000)
Treasury stock reissued.......................................... 12,000
-----------
BALANCE, DECEMBER 31, 1994......................................... (33,938)
Net income....................................................... 1,078,780
Treasury stock acquired.......................................... (28,000)
Treasury stock reissued.......................................... 14,000
-----------
BALANCE, DECEMBER 31, 1995......................................... 1,030,842
Net income....................................................... 397,665
Treasury stock acquired.......................................... (32,000)
Treasury stock reissued.......................................... 16,000
-----------
BALANCE, SEPTEMBER 30, 1996........................................ $ 1,412,507
===========
</TABLE>

See notes to combined financial statements.

F-14
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

COMBINED STATEMENTS OF CASH FLOWS

<TABLE>
<CAPTION>
NINE MONTHS ENDED
DECEMBER 31, SEPTEMBER 30,
----------------------------------- -----------------------
1993 1994 1995 1995 1996
----------- ---------- ---------- ----------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM
OPERATING ACTIVITIES:
Net income (loss)..... $(1,275,255) $ 968,764 $1,078,780 $ 1,218,929 $ 397,665
Adjustments to
reconcile net income
(loss) to net cash
provided (used) by
operating activities:
Depreciation,
depletion and
amortization........ 441,710 593,398 813,402 525,111 1,212,738
Gain on sale of oil
and gas property.... (247,321) (2,284,419) (3,337,076) (3,134,287)
Changes in assets and
liabilities:
Accounts receivable,
trade............... (323,787) (268,785) 60,098 619,957 (481,637)
Accounts receivable,
working interest
owners.............. (104,821) 54,302 (213,300) (683,838) (2,042,401)
Accounts receivable
from related
parties............. (17,185) (62,196) (23,480) (66,698) (64,773)
Advance to
stockholders........ (13,500) (14,111) 156 11,194 27,455
Other current assets. 3,621 (4,724) 16,778 (14,124) (98,012)
Refundable federal
income taxes........ 10,429
Other assets......... (41,133) (41,129)
Accounts payable,
trade............... 135,954 145,424 420,257 1,270,405 1,315,102
Accounts payable,
working interest
owners.............. 2,325,342
Accounts payable to
related parties..... 291,104 258,066 266,490 199,868 66,623
Accrued interest
payable............. (23,551) 32,199 12,996 (30,290) 16,207
Accrued liabilities.. 53,524 (32,345) 50,818 24,924 182,159
Deferred management
fee revenues........ 1,400 (20,000)
Long-term liability.. 21,226 30,413 (31,557) (24,240) (34,783)
----------- ---------- ---------- ----------- ----------
Net cash provided
(used) by operating
activities.......... (1,046,452) (604,014) (926,771) (124,218) 2,821,685
----------- ---------- ---------- ----------- ----------
CASH FLOWS FROM
INVESTING ACTIVITIES:
Oil and gas property
and equipment
purchases............ (3,660,054) (6,809,437) (8,511,991) (5,406,978) (7,880,777)
Proceeds from the sale
of oil and gas
properties........... 3,403,067 7,071,025 7,358,189 6,673,240 2,229,868
Proceeds from notes
receivable........... 154,250
Issue of notes
receivable........... (30,000) (125,000)
Certificate of
deposit, redemption.. 15,000
----------- ---------- ---------- ----------- ----------
Net cash (used)
provided by
investing
activities.......... (271,987) 290,838 (1,153,802) 1,266,262 (5,650,909)
----------- ---------- ---------- ----------- ----------
CASH FLOWS FROM
FINANCING ACTIVITIES:
Proceeds from notes
payable.............. 495,000 105,000 313,131 2,383,101 4,487,000
Payment on notes
payable.............. (475,000) (475,000) (83,691) (3,650,296) (162,026)
Proceeds from long-
term notes payable... 590,000 5,300,000
Payment on long-term
notes payable........ (422,769) (652,696) (3,582,955)
Accounts receivable,
subscriptions........ 1,823,917 20,000
Net treasury stock
transactions......... (12,000) (14,000) (14,000) (16,000)
Deferred offering
costs................ (750,000)
----------- ---------- ---------- ----------- ----------
Net cash (used)
provided by
financing
activities.......... 1,421,148 (424,696) 1,932,485 (1,281,195) 3,558,974
----------- ---------- ---------- ----------- ----------
NET INCREASE (DECREASE)
IN CASH AND CASH
EQUIVALENTS............ 102,709 (737,872) (148,088) (139,151) 729,750
CASH AND CASH
EQUIVALENTS, BEGINNING
OF YEAR................ 984,082 1,086,791 348,919 348,919 200,831
----------- ---------- ---------- ----------- ----------
CASH AND CASH
EQUIVALENTS, END OF
PERIOD................. $ 1,086,791 $ 348,919 $ 200,831 $ 209,768 $ 930,581
=========== ========== ========== =========== ==========
SUPPLEMENTAL CASH FLOW
DISCLOSURES--Cash paid
for interest........... $ 669,116 $ 381,833 $ 307,510 $ 230,099 $ 658,763
</TABLE>

See notes to combined financial statements.

F-15
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

NOTES TO COMBINED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

THE COMBINATION TRANSACTIONS--Edge Petroleum Corporation, a recently formed
Delaware corporation ("New Edge"), was incorporated in August 1996. In the
"Combination Transactions," New Edge plans to complete (i) a merger (the
"Merger") of Edge Petroleum Corporation, a Texas corporation ("Old Edge"),
with Edge Mergeco, Inc. ("Mergeco"), a wholly owned subsidiary of New Edge
organized for this purpose, in which the shareholders of Old Edge will receive
common stock of New Edge, (ii) an exchange offer (the "Edge Group II Exchange
Offer") to the general and limited partners of Edge Group II Limited
Partnership ("Edge Group II") in which such partners will have the opportunity
to exchange their interests in Edge Group II for common stock (iii) an
exchange offer (the "Gulfedge Exchange Offer") and, together with the Edge
Group II Exchange Offer (the "Limited Partnership Exchange Offers") to the
limited partners of Gulfedge Limited Partnership, of which Old Edge is the
general partner ("Gulfedge" and, together with Edge Group II, the "Limited
Partnerships"), in which such limited partners will have the opportunity to
exchange their interests in Gulfedge for common stock, (iv) an offer to
purchase (the "Purchase Offer") from Edge Group Partnership ("Edge Group") its
interest in the Edge Joint Venture II (the "Joint Venture"), for consideration
consisting of common stock and (v) an exchange (the "Calaway Exchange") of
interests in certain oil and gas properties held by Mr. James C. Calaway ("Mr.
J.C. Calaway") for common stock. Upon consummation of the Combination
Transactions, New Edge expects to acquire directly or indirectly substantially
all of the interest in the Joint Venture.

PRINCIPLES OF COMBINATION--The accompanying combined financial statements
include the accounts of Old Edge and the combined affiliated interests of the
limited partnerships in the Joint Venture all of which share common ownership
and management (collectively, the "Company"). The Combination Transactions
allows Limited Partnership holders and Edge Group the option to "stand pat";
therefore, all of the interests may not be acquired in the Combination
Transaction. Consequently, these financial statements may not reflect the
financial results or financial condition of the Company. The Combination will
be accounted for as a reorganization of entities under common control because
of the high degree of common control of the stockholders of the Company and by
virtue of their direct ownership of the entities and interest exchanged.
Accordingly, the combined accounts are prepared using the historical costs and
results of operations of the affiliated entities as if such entities had
always been combined. All intercompany balances have been eliminated.

INTERIM FINANCIAL STATEMENTS--In the opinion of management, the unaudited
consolidated financial statements include all adjustments (consisting solely
of normal recurring adjustments) necessary for a fair presentation of the
results of operations and cash flows for the nine-month period ended September
30, 1995. Although management believes the disclosures in the financial
statements are adequate to make the information presented not misleading,
certain information and footnote disclosures normally included in annual
financial statements prepared in accordance with generally accepted accounting
principles have been condensed or omitted for the nine months ended September
30, 1995 pursuant to the rules and regulations of the Securities and Exchange
Commission. The results of operations and cash flows for the nine-month period
ended September 30, 1996 are not necessarily indicative of the results to be
expected for the full year.

NATURE OF OPERATIONS--The Company is an independent oil and gas exploration
and production company with operations primarily along the onshore United
States Gulf Coast. In its exploration efforts the Company emphasizes an
integrated geologic interpretation method incorporating 3-D seismic technology
and advanced visualization and data analysis techniques utilizing state-of-
the-art computer hardware and software. The Company is focusing a majority of
its resources toward the development of its South Texas projects.

The term of the Joint Venture was to have expired on April 8, 1996 according
to the Joint Venture Agreement; however, the venturers extended the
dissolution date to December 31, 1996. The Joint Venture will

F-16
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)

continue to operate under the terms of the original Joint Venture Agreement,
as amended, until the dissolution is completed.

REVENUE RECOGNITION. The Company recognizes oil and gas revenue from its
interests in producing wells as oil and gas is produced and sold from those
wells. Oil and gas sold in production operations is not significantly
different from the Company's share of production.

OIL AND GAS PROPERTY--During 1996, the Company changed its method of
accounting from the successful efforts method to the full cost method of
accounting for oil and gas property and adjusted all historical periods to
reflect the change in accounting. Management believes that the full cost
method of accounting better reflects the results of its oil and natural gas
exploration activities.

Investments in oil and gas properties are accounted for using the full cost
method of accounting. All costs associated with the acquisition, exploration
and development of oil and gas properties are capitalized.

Oil and gas properties are amortized on the unit-of-production method using
estimates of proved reserve quantities. Investments in unproved properties are
not amortized until proved reserves associated with the projects can be
determined or until impairment occurs. If the results of an assessment
indicate that the properties are impaired, the amount of impairment is added
to the proved oil and gas property costs to be amortized. The amortizable base
includes estimated future development costs and, where significant,
dismantlement, restoration and abandonment costs, net of estimated salvage
values. The depletion rate per Mcfe for the years ended December 31, 1993,
1994 and 1995 and the nine month period ended September 30, 1996 was $0.43,
$0.42, $0.49 and $0.51, respectively.

Sales of proved and unproved properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and
proved reserves. Abandonments of properties are accounted for as adjustments
of capitalized costs with no loss recognized.

In addition, the capitalized costs of oil and gas properties are subject to
a "ceiling test," which limits such costs to the estimated present value,
discounted at a 10% interest rate, of future net cash flows from proved
reserves, based on current economic and operating conditions, plus the cost of
unproved prospects. If capitalized costs exceed this limit, the excess is
charged to depreciation, depletion and amortization. For the nine month period
ended September 30, 1996 and for the years ended December 31, 1995, 1994 and
1993, no write-down of the Company's oil and gas assets was necessary.

Depreciation of other property and equipment is provided using the straight-
line method based on estimated useful lives ranging from five to ten years.

DEFERRED LOAN AND ORGANIZATION COSTS--Deferred loan costs are capitalized as
deferred assets and amortized over five years or the term of the loan.
Organization costs have been capitalized and are amortized on a straight-line
basis over five years.

HEDGING ACTIVITIES--The Company periodically uses derivative financial
instruments to manage price risk related to natural gas sales and not for
speculative purposes. For book purposes, gains and losses related to the
hedging of anticipated transactions are recognized in income when the hedged
transaction occurs. The natural gas swap agreements generally provide for the
Company to receive or make counterparty payments on the differential between a
fixed price and a variable indexed price for natural gas. Total MCF's of
natural gas purchased and sold under swap arrangements during the nine month
period ended September 30, 1996 and the

F-17
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)

year ended December 31, 1995 were 182,000 MCF and 62,000 MCF, respectively.
Gains (losses) realized by the Company under such swap arrangements were $5,270
and $(15,720) for the nine month period ended September 30, 1996 and the year
ended December 31, 1995, respectively. There was no hedging activity during the
years ended December 31, 1994 and 1993. Outstanding hedges at December 31, 1995
were not material and the Company had no exiting hedging positions as of
September 30, 1996.

STATEMENTS OF CASH FLOWS--The statements of cash flows are presented using
the indirect method and consider all highly liquid investments with original
maturities of three months or less to be cash equivalents.

FINANCIAL INSTRUMENTS--The Company's financial instruments consist of cash,
receivables, payables, long-term debt and natural gas commodity hedges. The
carrying amount of cash, receivables and payables approximates fair value
because of the short-term nature of these items. The carrying amount of long-
term debt approximates fair value as the individual borrowings were negotiated
or renegotiated during or after 1993 and/or bear interest at floating market
interest rates. The carrying amount of natural gas commodity hedges
approximates fair value based on the expected settlement amounts of these
transactions in 1996.

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 revenue and expenses during the
reporting periods. Actual results could differ from these estimates.
Significant estimates include depreciation, depletion and amortization of
proved producing oil and gas properties; estimates of proved oil and gas
reserve volumes; and discounted future net cash flows (see Note 8).

CONCENTRATION OF CREDIT RISK--Substantially all of the Company's accounts
receivable result from oil and natural gas sales or joint interest billings to
third parties in the oil and gas industry. This concentration of customers and
joint interest owners may impact the Company's overall credit risk in that
these entities may be similarly affected by changes in economic and other
conditions. Historically, the Company has not experienced credit losses on such
receivables.

2. PROPERTY AND EQUIPMENT

At December 31, 1994 and 1995 and September 30, 1996 property and equipment
consisted of the following:

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------ SEPTEMBER 30,
1994 1995 1996
----------- ----------- -------------
<S> <C> <C> <C>
Oil and gas property................... $ 4,934,737 $ 9,029,777 $13,900, 491
Computer equipment..................... 601,183 1,004,509 1,784,721
Other property and equipment........... 166,523 184,018 184,018
----------- ----------- ------------
Total property and equipment........... 5,702,443 10,218,304 15,869,230
Accumulated depreciation, depletion and
amortization.......................... (1,566,484) (2,307,236) (3,485,201)
----------- ----------- ------------
Property and equipment, net............ $ 4,135,959 $ 7,911,068 $ 12,384,029
=========== =========== ============
</TABLE>

Oil and natural gas properties not subject to amortization consist of the
cost of undeveloped leaseholds, exploratory and developmental wells in
progress, and secondary recovery projects before the assignment of proved
reserves. These costs are reviewed periodically by management for impairment,
with the impairment provision included in the cost of oil and natural gas
properties subject to amortization. Factors considered by management in its
impairment assessment include drilling results by the Company and other
operators, the terms of oil and gas leases not held by production, production
response to secondary recovery activities and available

F-18
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)
funds for exploration and development. The following table summarizes the cost
of the properties not subject to amortization by year the cost was incurred.

<TABLE>
<CAPTION>
DECEMBER 31,
--------------------- SEPTEMBER 30,
1994 1995 1996
---------- ---------- -------------
<S> <C> <C> <C>
Year cost incurred:
Remainder.............................. $ 280,335 $ 226,979 $ 207,651
1993................................... 341,445 276,411 235,463
1994................................... 1,214,255 744,744 476,243
1995................................... -- 696,677 469,125
1996................................... 1,635,330
---------- ---------- ----------
$1,836,035 $1,944,811 $3,023,812
========== ========== ==========
</TABLE>

During 1994 the Joint Venture issued a note payable for $91,695 to the seller
of certain seismic data. Subsequently, the Joint Venture entered into a sales
agreement with the same entity to sell the Joint Venture's interest in an
undeveloped oil and gas property for $1,491,695 resulting in a gain of
$1,288,363. As a component of the sales agreement, the note payable was used to
reduce the proceeds from the sale.

3. LONG-TERM DEBT

During July 1995, the Joint Venture entered into a revolving credit facility
(the "Revolving Credit Facility") with a bank to finance temporary working
capital requirements. The Revolving Credit Facility provides up to $20,000,000
in available borrowings limited by a borrowing base (as defined by the
Revolving Credit Facility) which was $4,500,000 and $10,225,000 at December 31,
1995 and September 30, 1996, respectively. At December 31, 1995 and September
30, 1996, borrowings outstanding under the Revolving Credit Facility totaled
$4,500,000 and $8,650,000, respectively. The Revolving Credit Facility provides
for interest at the lender's prime rate plus 0.75% (9.25% and 9.0% at December
31, 1995 and September 30, 1996, respectively). The borrowing base is subject
to review by the bank on a quarterly basis and may be adjusted subject to the
provisions of the Revolving Credit Facility.

In January 1995, the Joint Venture entered into a Subordinated Loan Agreement
(the "Subordinated Loan") with a shareholder of Old Edge. Such agreement
provides for a $1 million term loan and a $1 million line of credit. Drawdowns
under the line of credit require 30 days' notice. At December 31, 1994 and 1995
and September 30, 1996, the aggregate amount outstanding under the Subordinated
Loan was $500,000, $1.3 million and $1.3 million, respectively, including $0.3
million outstanding under the line of credit. The principal is due, unless
earlier retired by the Joint Venture, upon the earlier of April 8, 1998 or the
conclusion of the Joint Venture's wind-up period. Interest at 10% per annum is
due monthly. The Subordinated Loan is secured by certain oil and gas
properties, equipment and other assets of the Joint Venture, but is subordinate
to the Revolving Credit Facility. The mortgage and security agreement restricts
the transfer of properties, creation of liens and other matters. The
Subordinated Loan is without recourse to the venturers. Under the Subordinated
Loan Agreement, the shareholder has a right to receive specified reversionary
and overriding royalty interests on prospects of the Joint Venture and certain
rights to convert such interests into common stock which is triggered by the
execution of certain transactions by the Joint Venture as defined within the
Subordinated Loan Agreement.

F-19
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)

At December 31, 1994 and 1995, notes payable and long-term debt consisted of
the following:

<TABLE>
<CAPTION>
DECEMBER 31,
---------------------- SEPTEMBER 30,
1994 1995 1996
---------- ---------- ------------- ---
<S> <C> <C> <C> <C>
Revolving credit facility, lenders'
prime rate plus 0.75%, interest
payable monthly, maturing June 1,
1998.............................. $4,500,000 $ 8,650,000
RIMCO note payable, 10% interest,
interest payable monthly, repaid
in 1995........................... $3,300,000
RIMCO deferred interest notes
payable, 10% interest, interest
payable quarterly, repaid in 1995. 282,955
Note payable to bank, lenders'
prime rate plus 0.75%, payable in
monthly principal installments of
$7,500 plus accrued interest,
matures March 1, 1997............. 180,000 112,500
Note payable to bank, lenders'
prime rate plus 1.5%, payable in
monthly principal installments of
$5,547 plus accrued interest,
matures March 1, 1997............. 83,207 33,283
Note payable, 9% interest, payable
in quarterly installments of
$13,750 plus interest, repaid in
1995.............................. 13,750
Note payable, 10.996% interest,
payable in monthly installments of
principal and interest of $2,326,
matures June 22, 1998............. 80,784 60,767 44,249
Note payable, lenders' prime plus
0.75%, payable in monthly
principal installments of $14,042
plus accrued interest, matures
July 1, 1998...................... 308,917
Subordinated note payable to a
shareholder of Old Edge, 10%
interest, interest payable
monthly, matures April 8, 1998.... 500,000 1,300,000 1,300,000
---------- ---------- ------------
Total.............................. 4,177,489 6,123,974 10,448,949
Current portion.................... (943,767) (178,898) (316,030)
---------- ---------- ------------
Long-term portion.................. $3,233,722 $5,945,076 $10, 132,919
========== ========== ============
</TABLE>

Substantially all of the Joint Venture's property and equipment are pledged
as collateral on certain notes payable.

At September 30, 1996, notes payable require minimum principal payments as
follows:

<TABLE>
<S> <C>
1997.......................................................... $ 316,030
1998.......................................................... 10,132,919
-----------
Total....................................................... $10,448,949
===========
</TABLE>

The Revolving Credit Facility and certain other note agreements provide for
certain financial covenants and restrictions on the Joint Venture including,
but not limited to, limitations on additional borrowings, sales of its oil and
gas properties or other collateral, a prohibition of dividends and certain
distributions of cash or properties, a prohibition on certain liens, a
limitation on annual lease payments, and a requirement to maintain minimum
tangible net worth and other financial ratios. For the quarters ending March
31, 1996 and June 30, 1996 the Joint Venture was not in compliance with the
original cash flow/debt service ratio covenant. The Joint Venture has received
a waiver for such non-compliance, and the provisions of the covenants were
subsequently amended in August 1996 to be less stringent.

4. COMMITMENTS AND CONTINGENCIES

The Company is, from time to time, party to certain lawsuits and claims
arising in the ordinary course of business. While the outcome of lawsuits and
claims cannot be predicted with certainty, management does not

F-20
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)

expect these matters to have a materially adverse effect on the financial
condition, results of operations or cash flows of the Company.

At September 30, 1996, Old Edge was obligated under a noncancelable operating
lease for office space. Following is a schedule of the remaining future minimum
lease payments under this lease:

Rent expense for the years ended December 31, 1993, 1994, and 1995 and the
nine month period ended September 30, 1996 was $156,207, $164,436, $165,317 and
$148,966, respectively.

5.PRO FORMA INCOME TAXES (UNAUDITED)

The following pro forma (provision) benefit in lieu of income tax amounts
have been presented for disclosure purposes only. These amounts represent the
companies' estimated provision for income taxes under the assumption that the
Company has been a taxpaying entity since inception of the Joint Venture (April
8, 1991). The Joint Venture is not a taxpaying entity, and the applicable taxes
are directly taxable to the individual affiliate owners of the Joint Venture.
Old Edge is a taxpaying entity and, accordingly, the applicable taxes were paid
by Old Edge.

Under SFAS No. 109, deferred income taxes are recognized based on the
estimated future tax effect of differences between the financial statement and
tax bases of assets and liabilities given the provisions of enacted laws. At
September 30, 1996, the estimated tax basis of the Company's net assets is
approximately $2.1 million above the recorded financial statement amounts. In
addition, the Company had net operating loss carryforwards of approximately
$2.2 million. Had the combined companies been a tax paying entity a deferred
tax asset of approximately $1.4 million would have been available for future
use to offset future tax liabilities of the Company, subject to any limitations
imposed by the Combination. Upon consummation of the Combination Transactions,
the Company will become a taxable corporation. Due to the uncertainty of future
earnings, a valuation allowance may be used to offset the net tax asset.

The difference between the statutory federal income taxes and the Company's
pro forma effective taxes is summarized as follows:

<TABLE>
<CAPTION>
NINE MONTH
DECEMBER 31, PERIOD ENDED
------------------------------- SEPTEMBER 30,
1993 1994 1995 1996
---------- --------- --------- -------------
<S> <C> <C> <C> <C>
Statutory federal income
taxes.................... $ -- $ 339,067 $ 377,573 $139,183
Recognition of net
operating loss
carryforwards............ -- (339,067) (377,573) (139,183)
---------- --------- --------- --------
Pro forma (provision)
benefit in lieu of income
taxes.................... $ -- $ -- $ -- $ --
========== ========= ========= ========
</TABLE>

The ultimate tax basis and related difference from financial basis cannot be
ultimately determined until consummation of the Combination Transactions and
such basis difference will change depending upon the level and nature of
operations and the amount of taxable income and deductions allocated to the
individual owners, limited partners and interests of the affiliated entities
through the date of the Combination. Such basis differences could vary
materially from the estimate.

F-21
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)

6. EQUITY

In 1991, Old Edge entered into an agreement with a related party to
repurchase 5,263 shares of its outstanding common stock. The repurchase
obligation is effective if holders of such shares demand repurchase between
January 1995 and January 1998. However, Old Edge will have no obligation to
repurchase these shares if it has registered common stock under the Securities
Exchange Act of 1933 prior to demand for repurchase. The amount to be paid for
these shares equals the percentage obtained by dividing 5,263 shares by the
total number of outstanding shares of Old Edge and multiplying this percentage
by the greater of (1) the net cash flow of Old Edge (as defined in the
agreement) or (2) the adjusted net worth of Old Edge (as defined in the
agreement). As of September 30, 1996, this repurchase obligation approximated
$174,000.

During 1994, a third party entered into an agreement to acquire shares of Old
Edge's outstanding common stock from a shareholder. These shares are held in
escrow as security for a nonrecourse promissory note issued to the third party
by the shareholder. The final payment is due January 15, 1997. Upon payment of
each annual principal amount, a proportionate number of shares will be released
by the shareholder from escrow to the third party. A stock repurchase agreement
gives Old Edge the option of participating in these annual principal payments.
Upon participation, Old Edge would take possession of its pro rata share of the
stock acquired. Should Old Edge elect not to participate in a principal
payment, Old Edge shall be deemed to have forfeited the ownership rights in the
stock for which the payment pertains. As of September 30, 1996, approximately
1,264 shares had been repurchased by Old Edge through the agreement.

In 1994, Old Edge adopted the 1994 Incentive Stock Option Plan which provides
for the granting of options to certain key employees to purchase up to 6,000
shares of Old Edge common stock. The recipient, timing and number of shares are
determined by the Board of Directors of Old Edge. The exercise price of any
options granted may not be less than 110% of the fair market value of Old
Edge's stock at the date of grant. In 1994 options to acquire 4,386 shares of
Old Edge common stock were granted and were immediately vested at prices
ranging from $45.60 to $91.20 per share. No options were granted in 1995. The
options expire in April 2004. No options were exercised or forfeited during
1994, 1995 or the nine month period ended September 30, 1996, thus all shares
originally granted remain exercisable at September 30, 1996.

In October 1995, the Financial Accounting Standards Board issued Statement
No. 123 ("SFAS No. 123"). SFAS No. 123 is a new standard of accounting for
stock-based compensation and establishes a fair value method of accounting for
awards granted after December 31, 1995 under stock compensation plans. SFAS No.
123 encourages, but does not require, companies to adopt the fair value method
of accounting in place of the existing method of accounting for stock-based
compensation whereupon compensation costs are recognized only in situations
where stock compensation plans award intrinsic value to recipients at the date
of grant. Companies that do not adopt the fair value method of accounting
prescribed in SFAS No. 123 must, nonetheless, make annual pro forma disclosures
of the estimated effects on net income and earnings per share in their year-end
1996 financial statements as if the fair value method had been used for grants
after December 31, 1994.

7. RELATED PARTY TRANSACTIONS

Edge Group II incurred management fees from the General Partner of $266,490
for each of the three years ended December 31, 1995 and $66,623 for the nine
month period September 30, 1996. Included in accounts payable to related party
at December 31, 1994 and 1995 and September 30, 1996 is $999,337, $1,265,827
and $1,332,450, respectively, representing accrued management fees due the
General Partner.

At December 31, 1994 and 1995 and September 30, 1996, included in advances to
stockholders was $30,987, $27,455 and $24,315, respectively, due from Directors
of Old Edge. At December 31, 1994 and 1995

F-22
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)

and September 30, 1996, an employee owed Old Edge $3,492, which was included in
receivables from related parties. At December 31, 1994, Old Edge owed $2,488 to
one of its directors which was included in payable to related parties.

At December 31, 1994 and 1995 and September 30, 1996, the Joint Venture was
liable to a shareholder of Old Edge for $500,000, $1,300,000 and $1,300,000,
respectively, of notes payable and at December 31, 1994 and 1995, $3,205 and
$11,014 of accrued interest (see Note 3).

Old Edge receives revenue from various related parties for maintaining
certain oil and gas properties. Representation fees amounted to $23,372,
$24,000, $24,000 and $22,500 for the years ended December 31, 1993, 1994 and
1995, and for the nine month period ended September 30, 1996, respectively. At
December 31, 1994 and 1995 and September 30, 1996, included in receivables from
related parties, was $10,492, $3,306 and $7,356, respectively, of
representation fees due Old Edge.

During 1994 the Joint Venture sold $241,395 in undeveloped oil and gas
prospects to a partnership of which an officer of Old Edge is a partner and
sold $60,000 in undeveloped oil and gas prospects to a stockholder of Old Edge.

During 1991, Old Edge entered into a consulting agreement with a stockholder
whereby Old Edge is obligated to pay $40,000 annually for the remainder of this
individual's life in exchange for consulting services.

In May 1992, the Joint Venture became the managing venturer of the Essex
Royalty Joint Venture ("Essex") and Old Edge entered into a management
agreement with Essex. In September 1994, the Joint Venture became the managing
venturer of the Essex Royalty Joint Venture II ("Essex II") and Old Edge
entered into a management agreement with Essex II. During 1993, the Joint
Venture issued a $30,000 note receivable to Essex which was collected in 1994.
During 1994, the Joint Venture loaned $125,000 to Essex II. This loan, plus
accrued interest, was repaid during 1994. Under the management agreements with
Essex and Essex II (collectively, the "Essex Joint Ventures"), Old Edge
receives a monthly management fee for managing oil and gas joint ventures. For
the years ended December 31, 1993, 1994 and 1995, Old Edge recorded management
fee proceeds totaling $60,000, $80,000, $120,000 and $90,000, respectively, and
have netted these amounts within general and administrative expense. In
addition, these agreements stipulate that Old Edge is entitled to be reimbursed
for certain general and administrative expenses. Such expenses invoiced by Old
Edge to the Essex Joint Ventures for the years ended December 31, 1993, 1994
and 1995 amounted to $36,750, $18,750 and $40,250 and $50,250 respectively. At
December 31, 1994 and 1995, Old Edge had a receivable from the Essex Joint
Ventures of $63,600, $115,000 and $147,375, respectively, relating to these
expenses and management fees.

8. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND GAS EXPLORATION, DEVELOPMENT
AND PRODUCTION ACTIVITIES (UNAUDITED)

This footnote provides unaudited information required by SFAS No. 69,
"Disclosures About Oil and Gas Producing Activities."

CAPITALIZED COSTS--Capitalized costs and accumulated depreciation, depletion
and amortization relating to the Company's oil and gas producing activities,
all of which are conducted within the continental United States, are summarized
below:

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER
31,
----------------------- SEPTEMBER 30,
1994 1995 1996
---------- ----------- -------------
<S> <C> <C> <C>
Proved producing oil and gas
properties....................... $3,098,692 $ 7,085,225 $10,876,678
Accumulated depreciation,
depletion and amortization....... (1,178,985) (1,746,643) (2,793,420)
---------- ----------- -----------
Net capitalized costs............. $1,919,707 $ 5,338,582 $ 8,083,258
========== =========== ===========
</TABLE>

F-23
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)

COSTS INCURRED--Costs incurred in oil and gas property acquisition,
exploration and development activities are summarized below:

<TABLE>
<CAPTION>
NINE MONTH
YEAR ENDED DECEMBER 31, PERIOD ENDED
-------------------------------- SEPTEMBER 30,
1993 1994 1995 1996
---------- ---------- ---------- -------------
<S> <C> <C> <C> <C>
Property acquisition
costs:
Unproved.............. $2,914,010 $5,496,613 $3,658,573 $3,308,931
Proved................ 6,873 26,236 91,025 36,386
Exploration cost...... 527,194 670,270 2,642,025 2,040,546
Development costs..... 20,569 238,341 1,149,548 1,714,702
---------- ---------- ---------- ----------
Total costs incurred.. $3,468,646 $6,431,460 $7,541,171 $7,100,565
========== ========== ========== ==========
</TABLE>

RESERVES--Proved reserves are estimated quantities of oil and natural gas
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 developed reserves are proved reserves that
can reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.

Proved oil and natural gas reserve quantities and the related discounted
future net cash flows before income taxes for the periods presented are based
on estimates prepared by Ryder Scott Company, independent petroleum engineers.
Such estimates have been prepared in accordance with guidelines established by
the Securities and Exchange Commission.

The Company's net ownership interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below:

<TABLE>
<CAPTION>
OIL, CONDENSATE AND NATURAL GAS
LIQUIDS (BBLS)
----------------------------------------
NINE MONTH
YEAR ENDED DECEMBER 31, PERIOD ENDED
------------------------- SEPTEMBER 30,
1993 1994 1995 1996
------- ------- ------- -------------
<S> <C> <C> <C> <C>
Proved developed and undeveloped
reserves:
Beginning of year.................. 174,805 169,947 368,160 708,933
Revisions of previous estimates.... (44,269) 27,989 155,908 42,374
Purchases of oil and gas
properties........................ 84,116 6,275
Extensions and discoveries......... 64,771 146,213 278,268 160,787
Sales of oil and gas properties.... (36,572)
Production......................... (25,360) (60,105) (63,106) (80,693)
------- ------- ------- -------
End of year........................ 169,947 368,160 708,933 831,401
======= ======= ======= =======
Proved developed reserves at end of
year................................ 169,947 261,327 652,843 789,440
======= ======= ======= =======
</TABLE>

F-24
<PAGE>

EDGE PETROLEUM CORPORATION, AFFILIATED ENTITIES AND DIRECT INTERESTS

NOTES TO COMBINED FINANCIAL STATEMENTS--(CONTINUED)

<TABLE>
<CAPTION>
NATURAL GAS (MCF)
-----------------------------------------------
NINE MONTH
YEAR ENDED DECEMBER 31, PERIOD ENDED
-------------------------------- SEPTEMBER 30,
1993 1994 1995 1996
--------- --------- ---------- -------------
<S> <C> <C> <C> <C>
Proved developed and
undeveloped reserves:
Beginning of year........... 1,295,911 2,550,000 3,673,000 8,821,000
Revisions of previous
estimates.................. 597,487 1,465,329 271,155 187,972
Purchases of oil and gas
properties................. 37,000 1,047,000
Extensions and discoveries.. 1,108,158 204,000 6,247,000 6,106,000
Sales of oil and gas
properties................. (1,910,962)
Production.................. (451,556) (583,329) (506,193) (1,550,972)
--------- --------- ---------- ----------
End of year................. 2,550,000 3,673,000 8,821,000 13,564,000
========= ========= ========== ==========
Proved developed reserves at
year end..................... 2,550,000 3,548,000 6,992,000 10,985,000
========= ========= ========== ==========
</TABLE>

STANDARDIZED MEASURE--The table of the Standardized Measure of Discounted
Future Net Cash Flows relating to the Company's ownership interests in proved
oil and gas reserves as of period end is shown below:

<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------ SEPTEMBER 30,
1993 1994 1995 1996
---------- ----------- ----------- -------------
<S> <C> <C> <C> <C>
Future cash inflows........ $7,955,845 $13,143,411 $31,011,202 $44,372,060
Future oil and natural gas
operating expenses........ (938,051) (2,417,571) (5,906,519) (8,118,033)
Future development costs... (164,894) (641,475) (972,662)
Future income tax expenses. (933,424) (1,962,963) (5,883,983) (8,945,210)
---------- ----------- ----------- -----------
Future net cash flows...... 6,084,370 8,597,983 18,579,225 26,336,155
10% annual discount for
estimating timing of cash
flows..................... (818,220) (1,725,504) (4,633,593) (6,352,423)
---------- ----------- ----------- -----------
Standardized measure of
discounted future net cash
flows..................... $5,266,150 $ 6,872,479 $13,945,632 $19,983,732
========== =========== =========== ===========
</TABLE>

Future cash flows are computed by applying year end prices of oil and natural
gas to year end quantities of proved oil and natural gas reserves. Future
operating expenses and development costs are computed primarily by the
Company's petroleum engineers by estimating the expenditures to be incurred in
developing and producing the Company's proved oil and natural gas reserves at
the end of the year, based on year end costs and assuming continuation of
existing economic conditions.

Future income taxes are based on year end statutory rates, adjusted for
operating loss carryforwards and tax credits. A discount factor of 10% was used
to reflect the timing of future net cash flows. The standardized measure of
discounted future net cash flows is not intended to represent the replacement
cost or fair market value of the Company's oil and gas properties.

The standardized measure of discounted future net cash flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's oil and natural gas reserves. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs, and a
discount factor more representative of the time value of money, and the risks
inherent in reserve estimates.

F-25
<PAGE>

CHANGE IN STANDARDIZED MEASURE--Changes in standardized measure of future net
cash flows relating to proved oil and gas reserves are summarized below:

<TABLE>
<CAPTION>
NINE MONTH
YEAR ENDED DECEMBER 31, PERIOD ENDED
------------------------------------- SEPTEMBER 30,
1993 1994 1995 1996
----------- ----------- ----------- -------------
<S> <C> <C> <C> <C>
Changes due to current
year operations:
Sales of oil and natural
gas, net of oil and
natural gas operating
expenses............... $(1,288,621) $(1,689,169) $(1,354,008) $(4,393,649)
Sales of oil and gas
properties............. (3,113,415)
Extensions and
discoveries............ 2,474,136 1,612,402 10,194,038 8,917,139
Purchases of oil and gas
properties............. 485,609 540,345
Changes due to revisions
in standardized
variables:
Prices and operating
expenses............... 192,281 (505,924) 408,398 1,664,760
Revisions of previous
quantity estimates..... 553,313 2,060,290 1,935,454 686,576
Estimated future
development costs...... (573) 62,740 (256,121)
Income taxes............ (112,909) (561,999) (2,423,065) (2,175,769)
Accretion of discount... 354,143 577,807 794,640 1,744,261
Production rates
(timing) and other..... (180,370) (372,114) 28,026 (149,097)
----------- ----------- ----------- -----------
Net change................ 1,991,973 1,606,329 7,073,153 6,038,100
----------- ----------- ----------- -----------
Beginning of year......... 3,274,177 5,266,150 6,872,479 13,945,632
----------- ----------- ----------- -----------
End of year............... $ 5,266,150 $ 6,872,479 $13,945,632 $19,983,732
=========== =========== =========== ===========
</TABLE>

Sales of oil and natural gas, net of oil and natural gas operating expenses,
are based on historical pre-tax results. Sales of oil and gas properties,
extensions and discoveries, purchases of minerals in place and the changes due
to revisions in standardized variables are reported on a pre-tax discounted
basis, while the accretion of discount is presented on an after tax basis.

* * * * * *

F-26
<PAGE>

November 27, 1996

Edge Petroleum Corporation
2100 Texaco Heritage Plaza
Houston, Texas 77002

Gentlemen:

At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain combined leasehold and royalty
interests that are sought to be combined in Edge Petroleum Corporation, a
Delaware corporation, and which are currently held by Edge Joint Venture II
(Edge) and James C. Calaway as of September 30, 1996. The subject properties
are located in the states of Alabama, Louisiana, Mississippi, and Texas. The
income data were estimated using the Securities and Exchange Commission (SEC)
guidelines for future cost and price parameters.

The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. September 1996 hydrocarbon prices were used
in the preparation of this report as required by SEC guidelines; however,
actual future prices may vary significantly from these prices. Therefore,
volumes of reserves actually recovered and amounts of income actually received
may differ significantly from the estimated quantities presented in this
report. A summary of the results of this study is shown below.

SEC PARAMETERS
ESTIMATED NET RESERVES AND INCOME DATA
CERTAIN LEASEHOLD AND ROYALTY INTERESTS OF
EDGE JOINT VENTURE II AND JAMES C. CALAWAY
AS OF SEPTEMBER 30, 1996

<TABLE>
<CAPTION>
PROVED
-----------------------------------------------
DEVELOPED
-----------------------
NON- TOTAL
PRODUCING PRODUCING UNDEVELOPED PROVED
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate--Barrels....... 438,829 269,232 41,961 750,022
Plant Products--Barrels....... 71,050 10,329 0 81,379
Gas--MMCF..................... 7,359 3,626 2,579 13,564
INCOME DATA
Future Gross Revenue.......... $23,669,314 $12,193,754 $5,449,802 $41,312,870
Deductions.................... 2,833,691 2,101,502 1,096,312 6,031,505
----------- ----------- ---------- -----------
Future Net Income (FNI)....... $20,835,623 $10,092,252 $4,353,490 $35,281,365
Discounted FNI @ 10%.......... $16,935,423 $ 6,088,764 $2,632,295 $25,656,482
</TABLE>

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

The proved developed non-producing reserves included herein are comprised of
behind-pipe and shut-in categories. A substantial portion of the proved
undeveloped reserves are associated with wells that have been drilled, but
require major expenditures for facilities, pipelines, and completions prior to
production. The various producing status categories are defined in the section
entitled "Definitions of Producing Status Categories" which is attached with
this report.

A-1
<PAGE>

The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells
(including processing fees and ad valorem taxes), recompletion costs and
development costs. The future net income is before the deduction of state and
federal income taxes and general administrative overhead, and has not been
adjusted for outstanding loans that may exist nor does it include any
adjustment for cash on hand or undistributed income. No attempt was made to
quantify or otherwise account for any accumulated gas production imbalances
that may exist. Gas reserves account for approximately 61 percent and liquid
hydrocarbon reserves account for the remaining 39 percent of total future
gross revenue from proved reserves.

RESERVES INCLUDED IN THIS REPORT

The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10(a) as
clarified by subsequent Commission Staff Accounting Bulletins. Our definition
of proved reserves is included in the section entitled "Definitions of
Reserves" which is attached with this report.

ESTIMATES OF RESERVES

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

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

FUTURE PRODUCTION RATES

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

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.

HYDROCARBON PRICES

Edge furnished us with prices in effect at September 30, 1996 and these
prices were held constant except for known and determinable escalations.
Product prices which were actually used for each property reflect

A-2
<PAGE>

adjustment for gravity, quality, local conditions, and/or distance from
market. In accordance with SEC guidelines, changes in liquid and gas prices
subsequent to September 30, 1996 were not taken into account in this report.
Future prices used in this report are discussed in more detail in the section
entitled "Hydrocarbon Pricing Parameters" which is attached with this report.

COSTS

Operating costs for the leases and wells in this report are based on the
operating expense reports of Edge 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 Edge 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 Edge, their estimate of zero net abandonment
costs after salvage value was used in this report. Ryder Scott has not
performed a detailed study of the abandonment cost nor the salvage value and
makes no warranty for Edge'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 that are not
charged directly to the leases or wells.

GENERAL

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

The estimates of reserves presented herein were based upon a detailed study
of the properties in which Edge 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. Edge 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 factual data furnished by Edge were accepted
without independent verification. The estimates presented in this report are
based on data available through September 1996.

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

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

Very truly yours,

RYDER SCOTT COMPANY
PETROLEUM ENGINEERS

/s/ Michael F. Stell
-------------------------------------
Michael F. Stell, P.E.
Petroleum Engineer
MFS/sw

Approved:

/s/ Don P. Roesle
- -------------------------------------
Don P. Roesle, P.E.
Senior Vice President

A-3
<PAGE>

DEFINITIONS OF RESERVES

PROVED RESERVES (SEC DEFINITION)

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

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

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

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

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

A-4
<PAGE>

RESERVE STATUS CATEGORIES

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

PROVED DEVELOPED (SEC DEFINITION)

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

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

Producing

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

Non-Producing

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

PROVED UNDEVELOPED (SEC DEFINITION)

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

A-5
<PAGE>

HYDROCARBON PRICING PARAMETERS

SEC PARAMETERS

OIL AND CONDENSATE

Edge furnished us with oil and condensate prices in effect at September 30,
1996 and these prices were held constant to depletion of the properties. In
accordance with Securities and Exchange Commission guidelines, changes in
liquid prices subsequent to September 30, 1996 were not considered in the
report.

PLANT PRODUCTS

Edge furnished us with plant product prices in effect at September 30, 1996
and these prices were held constant to depletion of the properties.

GAS

Edge furnished us with gas prices in effect at September 30, 1996 and with
its forecasts of future gas prices which take into account SEC guidelines,
current spot 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 make any
allowance for seasonal variations in gas prices which may cause future yearly
average gas prices to differ from September 1996 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.

A-6
<PAGE>

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

NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS
PROSPECTUS IN CONNECTION WITH THIS OFFERING AND, IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN
AUTHORIZED BY THE COMPANY OR THE UNDERWRITERS. THIS PROSPECTUS DOES NOT
CONSTITUTE AN OFFER TO SELL, OR A SOLICITATION OF AN OFFER TO BUY, TO ANY
PERSON IN ANY JURISDICTION IN WHICH SUCH OFFER TO SELL OR SOLICITATION IS NOT
AUTHORIZED, OR IN WHICH THE PERSON MAKING SUCH OFFER OR SOLICITATION IS NOT
QUALIFIED TO DO 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 THE
INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE.

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary........................................................ 3
Risk Factors.............................................................. 11
Use of Proceeds........................................................... 18
Dividend Policy........................................................... 18
Dilution.................................................................. 19
Capitalization............................................................ 20
Selected Historical Combined Financial and Operating Data................. 21
Management's Discussion and Analysis of Financial Condition and Results of
Operations............................................................... 22
Business.................................................................. 30
Management................................................................ 51
Certain Transactions...................................................... 60
Security Ownership of Certain Beneficial Owners and Management............ 68
Shares Eligible for Future Sale........................................... 70
Description of Capital Stock.............................................. 72
Underwriting.............................................................. 75
Legal Matters............................................................. 76
Experts................................................................... 76
Additional Information.................................................... 77
Glossary of Certain Industry Terms........................................ 78
Financial Statements...................................................... F-1
Letter of Ryder Scott..................................................... A-1
</TABLE>

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

UNTIL , 1997 (25 DAYS AFTER THE DATE OF THIS PROSPECTUS), ALL DEALERS
EFFECTING TRANSACTIONS IN THE COMMON STOCK, WHETHER OR NOT PARTICIPATING IN
THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS. THIS IS IN
ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN ACTING AS
UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS.

- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
2,000,000 SHARES

EDGE PETROLEUM
CORPORATION

COMMON STOCK

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

RAYMOND JAMES & ASSOCIATES, INC.

JEFFERIES & COMPANY, INC.

PRINCIPAL FINANCIAL SECURITIES, INC.

, 1997

- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
<PAGE>

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

The following are the estimated expenses (other than underwriting discounts
and commission) of the issuance and distribution of the securities being
registered, all of which shall be paid by the Company:

<TABLE>
<S> <C>
Securities and Exchange Commission Registration Fee.............. $11,849
NASD Filing Fee.................................................. 4,410
Nasdaq National Market Fees...................................... *
Printing Expenses................................................ *
Legal Fees and Expenses.......................................... *
Accountants' Fees and Expenses................................... *
Blue Sky Fees and Expenses....................................... *
Transfer Agent and Registrar Fees................................ *
Miscellaneous Expenses........................................... *
-------
Total $ *
=======
</TABLE>
- --------
* To be provided by amendment.

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS

Delaware General Corporation Law

Section 145(a) of the General Corporation Law of the State of Delaware (the
"DGCL") provides that a corporation may indemnify any person who was or is a
party or is threatened to be made a party to any threatened, pending or
completed action, suit or proceeding, whether civil, criminal, administrative
or investigative (other than an action by or in the right of the corporation)
by reason of the fact that he is or was a director, officer, employee or agent
of the corporation, or is or was serving at the request of the corporation as
a director, officer, employee or agent of another corporation, partnership,
joint venture, trust or other enterprise, against expenses (including
attorneys' fees), judgments, fines and amounts paid in settlement actually and
reasonably incurred by him in connection with such action, suit or proceeding
if he acted in good faith and in a manner he reasonably believed to be in or
not opposed to the best interests of the corporation and, with respect to any
criminal action or proceeding, had no reasonable cause to believe his conduct
was unlawful. The termination of any action, suit or proceeding by judgment,
order, settlement or conviction or upon a plea of nolo contendere or its
equivalent shall not, of itself, create a presumption that the person did not
act in good faith and in a manner which he reasonably believed to be in or not
opposed to the best interests of the corporation and, with respect to any
criminal action or proceeding, had reasonable cause to believe that his
conduct was unlawful.

Section 145(b) of the DGCL states that a corporation may indemnify any
person who was or is a party or is threatened to be made a party to any
threatened, pending or completed action or suit by or in the right of the
corporation to procure a judgment in its favor by reason of the fact that he
is or was a director, officer, employee or agent of the corporation, or is
serving at the request of the corporation as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust or other
enterprise against expenses (including action or suit if he acted in good
faith and in a manner he reasonably believed to be in or not opposed to the
best interests of the corporation and except that no indemnification shall be
made in respect of any claim, issue or matter as to which such person shall
have been adjudged to be liable to the corporation unless and only to the
extent that the Court of Chancery or the court in which such action or suit
was brought shall determine upon application that, despite the adjudication of
liability but in view of all the circumstances of the case, such person is
fairly and reasonably entitled to indemnity for such expenses that the Court
of Chancery or such other court shall deem proper.

II-1
<PAGE>

Section 145(c) of the DGCL provides that to the extent that a director,
officer, employee or agent of a corporation has been successful on the merits
or otherwise in defense of any action, suit or proceeding referred to in
subsections (a) and (b) of Section 145, or in defense of any claim, issue or
matter therein, he shall be indemnified against expenses (including attorneys'
fees) actually and reasonably incurred by him in connection therewith.

Section 145(d) of the DGCL states that any indemnification under subsections
(a) and (b) of Section 145 (unless ordered by a court) shall be made by the
corporation only as authorized in the specific case upon a determination that
indemnification of the director, officer, employee or agent is proper in the
circumstances because he has met the applicable standard of conduct set forth
in subsections (a) and (b). Such determination shall be made (1) by the board
of directors by a majority vote of a quorum consisting of directors who were
not parties to such action, suit or proceeding or (2) if such a quorum is not
obtainable or, even if obtainable, a quorum of disinterested directors so
directs, by independent legal counsel in a written opinion or (3) by the
stockholders.

Section 145(e) of the DGCL provides that expenses (including attorneys'
fees) incurred by an officer or director in defending any civil, criminal,
administrative or investigative action, suit or proceeding may be paid by the
corporation in advance of the final disposition of such action, suit or
proceeding upon receipt of an undertaking by or on behalf of such director or
officer to repay such amount if it ultimately is determined that he is not
entitled to be indemnified by the corporation as authorized in Section 145.
Such expenses (including attorneys' fees) incurred by other employees and
agents may be so paid upon such terms and conditions, if any, as the board of
directors deems appropriate.

Section 145(f) of the DGCL states that the indemnification and advancement
of expenses provided by, or granted pursuant to, the other subsections of
Section 145 shall not be deemed exclusive of any other rights to which those
seeking indemnification or advancement of expenses may be entitled under any
bylaw, agreement, vote of stockholders or disinterested directors or
otherwise, both as to action in this official capacity and as to action in
another capacity while holding such office.

Section 145(g) of the DGCL provides that a corporation shall have the power
to purchase and maintain insurance on behalf of any person who is or was a
director, officer, employee or agent of the corporation, or is or was serving
at the request of the corporation as a director, officer, employee or agent of
another corporation, partnership, joint venture, trust or other enterprise,
against any liability asserted against him and incurred by him in any such
capacity, or arising out of his status as such, whether or not the corporation
would have the power to indemnify him against such liability under the
provisions of Section 145.

Section 145(j) of the DGCL states that the indemnification and advancement
of expenses provided by, or granted pursuant to, Section 145 shall, unless
otherwise provided when authorized or ratified, continue as to a person who
has ceased to be a director, officer, employee or agent and shall inure to the
benefit of the heirs, executors and administrators of such a person.

Certificate of Incorporation

The Certificate of Incorporation of the Company provides that a director of
the Company shall not be personally liable to the Company or its stockholders
for monetary damages for breach of fiduciary duty as a director, except for
liability (i) for any breach of the director's 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 law, (iii) under
Section 174 of the DGCL or (iv) for any transaction from which the director
derived an improper personal benefit. If the DGCL is amended to authorize the
further elimination or limitation of the liability of directors, then the
liability of a director of the Company, in addition to the limitation on
personal liability described above, shall be limited to the fullest extent
permitted by the amended DGCL. Further, any repeal or modification of such
provision of the Restated Certificate of Incorporation by the stockholders of
the Company shall be prospective only, and shall not adversely affect any
limitation on the personal liability of a director of the Company existing at
the time of such repeal or modification.

II-2
<PAGE>

Bylaws

The Bylaws of the Company provide that each person who was or is made a
party or is threatened to be made a party to or is involved in any action,
suit or proceeding, whether civil, criminal, administrative or investigative,
by reason of the fact that he or she, or a person of whom he or she is the
legal representative, is or was or has agreed to become a director or officer
of the Company or is or was serving or has agreed to serve at the request of
the Company as a director, officer, employee or agent of another corporation
or of a partnership, joint venture, trust or other enterprise, including
service with respect to employee benefit plans, whether the basis of such
proceeding is alleged action in an official capacity as a director or officer
or in any other capacity while serving or having agreed to serve as a director
or officer, shall be indemnified and held harmless by the Company to the
fullest extent authorized by the DGCL, as the same exists or may thereafter be
amended (but, in the case of any such amendment, only to the extent that such
amendment permits the Company to provide broader indemnification rights than
said law permitted the Company to provide prior to such amendment) against all
expense, liability and loss (including, without limitation, attorneys' fees,
judgments, fines, ERISA excise taxes or penalties and amounts paid or to be
paid in settlement) reasonably incurred or suffered by such person in
connection therewith and such indemnification shall continue as to a person
who has ceased to serve in the capacity which initially entitled such person
to indemnity thereunder, and shall inure to the benefit of his or her heirs,
executors and administrators; provided, however, that the Company shall
indemnify any such person seeking indemnification in connection with a
proceeding (or part thereof) initiated by such person only if such proceeding
(or part thereof) was authorized by the board of directors of the Company. The
Bylaws further provide that the right to indemnification conferred thereby
shall be a contract right and shall include the right to be paid by the
Company the expenses incurred in defending any such proceeding in advance of
its final disposition; provided, however, that, if the DGCL requires, the
payment of such expenses incurred by a current, former or proposed director or
officer in his or her capacity as a director or officer or proposed director
or officer (and not in any other capacity in which service was or is or has
been agreed to be rendered by such person while a director or officer,
including, without limitation, service to an employee benefit plan) in advance
of the final disposition of a proceeding, shall be made only upon delivery to
the Company of an undertaking, by or on behalf of such indemnified person, to
repay all amounts so advanced if it shall ultimately be determined that such
indemnified person is not entitled to be indemnified under the Bylaws or
otherwise. In addition, the Bylaws provide that the Company may, by action of
its board of directors, provide indemnification to employees and agents of the
Company, individually or as a group, with the same scope and effect as the
indemnification to employees and agents of the Company, individually or as a
group, with the same scope and effect as the indemnification of directors and
officers provided for in the Bylaws.

The Bylaws include related provisions meant to facilitate the indemnitee's
receipt of such benefits. These provisions cover, among other things: (i)
specification of the method of determining entitlement to indemnification and
the selection of independent counsel that will in some cases make such
determination; (ii) specification of certain time periods by which certain
payments or determinations must be made and actions must be taken; and (iii)
the establishment of certain presumptions in favor of an indemnitee. The
benefits of certain of these provisions are available to an indemnitee only if
there has been a change in control (as defined therein).

Indemnification Agreements

The Company expects to enter into Indemnification Agreements with each of
its directors. The Indemnification Agreements will provide that the Company
shall indemnify the director and hold him harmless from any losses and
expenses which, in type or amount, are not insured under the directors and
officers' liability insurance maintained by the Company, and generally
indemnifies the director against losses and expenses as a result of a claim or
claims made against him for any breach of duty, neglect, error, misstatement,
misleading statement, omission or other act done or wrongfully attempted by
the director or any of the foregoing alleged by any claimant or any claim
against the director solely by reason of him being a director or officer of
the Company, subject to certain exclusions. The Indemnification Agreements
will also provide certain procedures regarding the right to indemnification
and for the advancement of expenses.

II-3
<PAGE>

Underwriting Agreement

The Underwriting Agreement provides for the indemnification of the directors
and officers of the Company in certain circumstances.

Insurance

The Company intends to obtain a policy of liability insurance to insure its
officers and directors against losses resulting from certain acts committed by
them in their capacities as officers and directors of the Company.

ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.

Edge Petroleum Corporation, a Delaware corporation, has not sold any
securities, registered or otherwise, within the past three years. Concurrently
with the closing of the Combination Transactions and this Offering, the
Company anticipates selling securities that are not registered with the
Commission as described below.

Pursuant to the Combination Agreement options to purchase an aggregate of
4,386 shares of Old Edge Common Stock granted under the Old Edge Plan to Mr.
Richard Dale and Mr. James D. Calaway on November 4, 1994, will be converted
into options to purchase 97,844 shares of Common Stock. Such transaction is
exempt from the registration requirements of the Securities Act by virtue of
Rule 701 thereunder and as not involving a sale under Section 2(3) thereof.
Such transaction will occur only if the Merger is consummated, which is itself
conditioned on the consummation of this Offering and the Edge Group II
Exchange Offer.

Pursuant to the Purchase Agreement between the Company and James C. Calaway
dated as of December 2, 1996, the Company agreed to purchase certain oil and
natural gas interests from Mr. Calaway in exchange for 21,669 shares of Common
Stock (assuming an initial public offering price of $16.00 per share). The
closing of such purchase is contingent on the consummation of this Offering,
the Merger and the Edge Group II Exchange Offer. Such transaction is exempt
from the registration requirements of the Securities Act by virtue of Section
4(2) thereof as a transaction not involving any public Offering.

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a) Exhibits.

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
*1.1 --Form of Underwriting Agreement.
+2.1 --Amended and Restated Combination Agreement by and among (i) Edge
Group II Limited Partnership, (ii) Gulfedge Limited Partnership,
(iii) Edge Group Partnership, (iv) Edge Petroleum Corporation, (v)
Edge Mergeco, Inc. and (vi) the Company, dated as of January 13,
1997.
*3.1 --Restated Certificate of Incorporation of the Company.
*3.2 --Bylaws of the Company.
*4.1 --Form of certificate representing Common Stock.
+4.2 --Subordinated Promissory Note of Edge Joint Venture II dated January
3, 1995 in the original principal amount of $2,000,000 payable to
James C. Calaway, and related agreement, as amended.
+4.3 --Credit Agreement, as amended, dated as of July 11, 1995, between
Edge Joint Venture II and Compass Bank--Houston, as lender.
+4.4 --Security Agreements, as amended, dated as of July 11, 1995 of Edge
Joint Venture II in favor of Compass Bank--Houston.
--The Company is a party to several debt instruments under which the
total amount of securities authorized does not exceed 10% of the
total assets of the Company and its subsidiaries on a consolidated
basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation
S-K, the Company agrees to furnish a copy of such instruments to the
Commission upon request.
*5.1 --Opinion of Baker & Botts, L.L.P.
</TABLE>

II-4
<PAGE>

<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.1 --Joint Venture Agreement, as amended, dated April 8, 1991 among Edge
Group II Limited Partnership, New Edge Petroleum Corporation,
Gulfedge Limited Partnership and Edge Group Partnership.
+10.2 --Joint Venture Agreement between Edge Joint Venture II and Essex
Royalty Limited Partnership II, dated as of May 10, 1994.
+10.3 --Joint Venture Agreement between Edge Joint Venture II and Essex
Royalty Limited Partnership, dated as of April 11, 1992.
+10.4 --Agreement of Limited Partnership of Edge Group II Limited
Partnership, among John Sfondrini, Napamco, Ltd. and the limited
partners named therein.
+10.5 --Agreement of Limited Partnership of Gulfedge Limited Partnership by
and among Edge Petroleum Corporation, a Texas corporation, as general
partner, and the limited partners named therein, dated as of April 1,
1991.
*10.6 --Registration Rights Agreement between Edge Holding Company Limited
Partnership and the Company.
+10.7 --Form of Indemnification Agreement between the Company and each of
its directors.
+10.8 --Employment Agreement dated April 9, 1991 between Edge Petroleum
Corporation and John E. Calaway.
*10.9 --Employment Agreement between the Company and James D. Calaway.
*10.10 --Employment Agreement between the Company and John E. Calaway.
+10.11 --Purchase Agreement between the Company and James C. Calaway dated as
of December 2, 1996.
+10.12 --Consulting Agreement of James C. Calaway dated March 18, 1989.
+10.13 --Stock Option Plan of Edge Petroleum Corporation, a Texas
corporation.
*10.14 --Incentive Plan of Edge Petroleum Corporation.
*10.15 --Employment Agreement between the Company and Michael G. Long.
*11.1 --Computation of Net Income Per Common and Common Equivalent Share.
*21.1 --Subsidiaries of the Company.
23.1 --Consent of Deloitte & Touche LLP.
+23.2 --Consent of Ryder Scott Company.
*23.3 --Consent of Baker & Botts, L.L.P. (included in Exhibit 5.1).
23.4 --Consent of Robert W. Shower as nominee for director.
+24.1 --Power of Attorney.
*27.1 --Financial Data Schedule.
</TABLE>
- --------
*To be filed by amendment.
+ Incorporated by reference from the exhibit bearing the same number attached
to the Registration Statement on Form S-4 filed by Edge Petroleum
Corporation, a Delaware corporation, on December 4, 1996.

+ Previously filed.

(b) Financial Statement Schedules.

Schedule I--Condensed Financial Information of Registrant

All other schedules are omitted because they are not applicable or because
the required information is contained in the financial statements or notes
thereto included in this Registration Statement.

ITEM 17. UNDERTAKINGS.

The undersigned registrant hereby undertakes to provide to the Underwriters,
at the closing specified in the Purchase Agreement, certificates representing
the shares of Common Stock offered hereby in such denominations and registered
in such names as required by the Underwriters to permit prompt delivery to
each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
registrant pursuant to the foregoing provisions, or otherwise, the registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities
Act and is, therefore, unenforceable. In the event that a

II-5
<PAGE>

claim for indemnification against such liabilities (other than the payment by
the registrant of expenses incurred or paid by a director, officer or
controlling person of the registrant in the successful defense of any action,
suit or proceeding) is asserted by such director, officer or controlling
person in connection with securities being registered, the registrant will,
unless in the opinion of its counsel the matter has been settled by
controlling precedent, submit to a court of appropriate jurisdiction the
question whether such indemnification by it is against public policy as
expressed in the Act and will be governed by the final adjudication of such
issue.

The undersigned registrant hereby undertakes that:

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

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

II-6
<PAGE>

SIGNATURES

PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, THE REGISTRANT
HAS DULY CAUSED THIS AMENDMENT TO THE REGISTRATION STATEMENT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY OF
HOUSTON, STATE OF TEXAS, ON THE 14TH DAY OF JANUARY, 1997.

EDGE PETROLEUM CORPORATION

By: /s/ James D. Calaway
----------------------------------
James D. Calaway
President

PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, THIS AMENDMENT
TO THE REGISTRATION STATEMENT HAS BEEN SIGNED BY THE FOLLOWING PERSONS IN THE
CAPACITIES INDICATED ON JANUARY 14, 1997.

<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----

<S> <C>
/s/ John E. Calaway Chief Executive Officer and
------------------------------------ Director (Principal Executive
John E. Calaway Officer)

/s/ Michael G. Long Chief Financial Officer
------------------------------------ (Principal Financial Officer)
Michael G. Long

/s/ Richard S. Dale Controller, Treasurer and
------------------------------------ Secretary (Principal Accounting
Richard S. Dale Officer)

/s/ James D. Calaway Director
------------------------------------
James D. Calaway

* Director
------------------------------------
Vincent Andrews

* Director
------------------------------------
David B. Benedict

* Director
------------------------------------
Nils Peterson

* Director
------------------------------------
Stanley S. Raphael

* Director
------------------------------------
John Sfondrini
</TABLE>

/s/ James D. Calaway

*By:
----------------------------

(James D. Calaway, Attorney-in-Fact)

II-7

<PAGE>

EXHIBIT 23.1

INDEPENDENT AUDITORS' CONSENT

We consent to the use in this Registration Statement of Edge Petroleum
Corporation, a Delaware corporation, on Amendment No. 1 to Form S-1 of our
report dated January 13, 1997, relating to the combined financial statements
of Edge Petroleum Corporation, a Texas corporation, affiliated entities and
direct interests and our report dated December 3, 1996, relating to the
balance sheet of Edge Petroleum Corporation, a Delaware corporation, appearing
in the Prospectus, which is part of this Registration Statement.

We also consent to the reference to us under the heading "Experts" in such
Prospectus.

DELOITTE & TOUCHE LLP
Houston, Texas

January 14, 1997

<PAGE>

Exhibit 23.4

CONSENT OF PERSON NAMED TO BECOME A DIRECTOR

Pursuant to Rule 438 under the Securities Act of 1933, as amended (the
"Act"), I hereby consent to the use of my name and any references to me as a
person nominated to become a director of Edge Petroleum Corporation, a Delaware
corporation (the "Company"), in each of the Prospectus constituting a part the
Company's Registration Statement on Form S-1 and the Joint Proxy and Consent
Solicitation/Statement constituting a part of the Company's Registration
Statement on Form S-4, each of which has been filed with the Securities and
Exchange Commission pursuant to the Act.

Dated: January 6, 1997

/s/ Robert Shower
______________________________________
Robert Shower