EDGE PETROLEUM CORP - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER: 0-22149
EDGE PETROLEUM CORPORATION
(Exact name of Registrant as specified in its charter)

DELAWARE 76-0511037
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

1301 TRAVIS, SUITE 2000 77002
HOUSTON, TEXAS (Zip code)
(Address of principal executive offices)

713-654-8960
(Registrant's telephone number including area code)
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

NONE

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:

COMMON STOCK, PAR VALUE $.01 PER SHARE
---------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

Indicate by check mark whether the registrant is an accelerated
filer. Yes [ ] No [X]

As of June 30, 2003, the aggregate market value of the voting stock held by
non-affiliates of the registrant was $50.9 million (based on a value of $5.67
per share, the closing price of the Common Stock as quoted by NASDAQ National
Market on such date).

As of March 12, 2004, 12,831,385 shares of Common Stock, par value $.01 per
share, were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the registrant's 2004 Annual
Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III of
this report.

TABLE OF CONTENTS

1

EDGE PETROLEUM CORPORATION

Unless otherwise indicated by the context, references herein to the
"Company" or "Edge" mean Edge Petroleum Corporation, a Delaware corporation, and
its corporate and partnership subsidiaries and predecessors. Certain terms used
herein relating to the oil and natural gas industry are defined in ITEMS 1 AND
2. "BUSINESS AND PROPERTIES -- CERTAIN DEFINITIONS."

FORWARD LOOKING INFORMATION

Certain of the statements contained in all parts of this document
(including the portion, if any, to which this Form 10-K is attached), including,
but not limited to, those relating to our drilling plans (including scheduled
and budgeted wells), the effect of changes in strategy and business discipline,
future tax matters, our 3-D project portfolio, future general and administrative
expenses on a per unit of production basis, changes in wells operated and
reserves, future growth and expansion, future exploration, future seismic data
(including timing and results), expansion of operation, our ability to generate
additional prospects, review of outside generated prospects and acquisitions,
additional reserves and reserve increases, enhancement of visualization and
interpretation strengths, expansion and improvement of capabilities, integration
of new technology into operations, credit facilities, attraction of new members
to the exploration team, future compensation programs, new focus on core areas,
new prospects and drilling locations, new alliances, future capital expenditures
(or funding thereof) and working capital, sufficiency of future working capital,
borrowings and capital resources and liquidity, projected rates of return,
projected cash flows from operations, future gas price environment, expectation
or timing of reaching payout, outcome, effects or timing of any legal
proceedings or contingencies, the number, timing or results of any wells, the
plans for timing, interpretation and results of new or existing seismic surveys
or seismic data, future production or reserves, future acquisition of leases,
lease options or other land rights and any other statements regarding future
operations, financial results, opportunities, growth, business plans and
strategy and other statements that are not historical facts are forward looking
statements. These forward-looking statements reflect our current view of future
events and financial performance. When used in this document, the words
"budgeted," "anticipate," "estimate," "expect," "may," "project," "believe,"
"intend," "plan," "potential," "forecast," "might," "predict," "should" and
similar expressions are intended to be among the statements that identify
forward looking statements. These forward-looking statements speak only as of
their dates and should not be unduly relied upon. We undertake no obligation to
publicly update or revise any forward-looking statement, whether as a result of
new information, future events, or otherwise. Such statements involve risks and
uncertainties, including, but not limited to, those set forth under ITEMS 1 AND
2. "BUSINESS AND PROPERTIES -- RISK FACTORS" and other factors detailed in this
document and our other filings with the Commission. Should one or more of these
risks or uncertainties materialize, or should underlying assumptions prove
incorrect, actual outcomes may vary materially from those indicated. All
subsequent written and oral forward-looking statements attributable to the
Company or to persons acting on its behalf are expressly qualified in their
entirety by reference to these risks and uncertainties.

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

Overview

Edge Petroleum Corporation is an independent oil and natural gas company
engaged in the exploration, development, acquisition and production of crude oil
and natural gas properties in the United States. At year-end 2003, our net
proved reserves were 63.9 Bcfe, comprised of 46.8 billion cubic feet of natural
gas, 1.5 million barrels of oil and 1.4 million barrels of plant products.
Natural gas and natural gas liquids accounted for approximately 86% of those
proved reserves. About 78% of total proved reserves were developed as of
year-end and they were all located onshore, in the United States.

Edge was founded in 1983 as a private company and went public in 1997
through an initial public offering. We have evolved over time from a prospect
generation organization focused on high-risk,

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high-reward exploration projects to a team-driven organization focused on a
balanced program of exploration, exploitation, development and acquisition of
oil and natural gas properties. Following a top-level management change in late
1998, a more disciplined style of business planning and management was
integrated into our technology-driven drilling activities.

We believe these changes in our strategy and business discipline will
result in continued growth in reserves, production and financial strength.

In 2003, we entered into a significant exploration project in Southeastern
("SE") New Mexico and completed three transactions, including the merger with
Miller Exploration Company ("Miller") which was completed in December 2003.

STRATEGY

Our strategy for growth has evolved over the past several years and is
based upon the following main elements:

- reserve growth through the drilling of a balanced portfolio of prospects

- balancing exploration risk with the acquisition and exploitation of
existing properties that we believe have upside potential

- focusing on specific geographic areas where we believe we can add value

- integration of the latest technological advances into our exploration,
drilling, production operations and administration

- maintaining a conservative financial structure and controlling our cost
structure

- using equity ownership and performance-based compensation programs to
attract and retain a high-quality workforce.

DRILLING PROGRAM

During 2003, Edge's drilling program was focused primarily in the state of
Texas. We drilled 36 wells in 2003 with 28 completed as productive for a 78%
apparent success rate. This drilling program, along with three acquisitions,
helped to enable us to replace 285% of our production in 2003 and grow our
year-end reserves by 30%. We expect to drill at least 40 to 45 wells in 2004.

BALANCE

In 2003, 57% of our reserve growth came from our drilling activity and 43%
came from acquisitions and revisions. We seek acquisitions of proven properties
that typically have exploration or exploitation upside potential. We primarily
seek properties in our existing core areas, or as a means to establish new core
areas. We spent considerable effort in 2003 on acquisitions and successfully
closed three transactions. We continue to work diligently to identify and
evaluate acquisition opportunities with the goal of identifying those that we
believe would fit our strategic plan and add shareholder value.

We believe our core drilling program has the potential to replace our
production and to provide moderate reserve growth while our higher-risk drilling
program and acquisitions have the potential to rapidly accelerate our growth as
well as add to future drilling opportunities.

GEOGRAPHIC FOCUS

We believe geographic focus is a critical element of success. Long-term
success requires detailed knowledge of both geologic and geophysical attributes,
as well as operating conditions in our chosen areas. As a result, we focus on a
select number of geographic areas where our experience and strengths can be
applied with a significant influence on the outcome. We believe this focus will
allow us to manage a growing asset base

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while controlling increases in staffing and allow us to add value to additional
properties while controlling incremental costs.

TECHNOLOGY

We use advanced technologies as risk reduction tools in our exploration,
development, drilling and completion activities. Data analysis techniques and
advanced processing techniques combined with our more traditional sub-surface
interpretation techniques allow our team of technical personnel to more easily
identify features, structural details and fluid contacts, that could be
overlooked using less sophisticated data interpretation techniques. As of
December 31, 2003, we had rights to approximately 2,500 square miles of 3D
seismic data. Of that amount, we had approximately 1,588 square miles in Texas,
709 square miles in Louisiana, 55 square miles in Montana, 81 square miles in
Mississippi, 57 square miles in Alabama and 10 square miles in Michigan.

FINANCIAL STRUCTURE

We believe that a conservative financial structure is crucial to
consistent, positive financial results, management of cyclical swings in our
industry and the ability to move quickly to take advantage of acquisitions and
attractive drilling opportunities. At December 31, 2003, our debt to total
capital ratio was 20.4%. We try to fund most of our ongoing capital expenditures
from cash flow from operations, reserving our debt capacity for potential
investment opportunities that we believe can profitably add to our program. Part
of a sound financial structure is constant attention to costs, both operating
and overhead costs. Over the past three years, we have worked diligently to
control our operating costs and overhead costs and instituted a formal,
disciplined capital budgeting process.

EQUITY OWNERSHIP

Following a management change in late 1998, we eliminated the previous
overriding royalty compensation system and replaced it with a system designed to
reward all employees through performance-based compensation that is competitive
with our peers and through equity ownership. As of March 12, 2004, our employees
and directors owned or had options to acquire an aggregate of approximately 15%
of our outstanding common stock.

OIL AND NATURAL GAS RESERVES

The following table sets forth our estimated net proved oil and natural gas
reserves and the present value of estimated future pretax net cash flows related
to such reserves as of December 31, 2003. We engaged Ryder Scott Company ("Ryder
Scott") to estimate our net proved reserves, projected future production,
estimated future net revenue attributable to our proved reserves, and the
present value of such estimated future net revenue as of December 31, 2003.
Ryder Scott's estimates were based upon a review of production histories and
other geologic, economic, ownership and engineering data provided by us. Ryder
Scott has independently evaluated our reserves for the past ten years. In
estimating the reserve quantities that are economically recoverable, Ryder Scott
used year-end oil and natural gas prices in effect at December 31, 2003 and
estimated development and production costs that were in effect during December
2003 without giving effect to hedging activities. In accordance with
requirements of the Securities and Exchange Commission (the "Commission")
regulations, no price or cost escalation or reduction was considered by Ryder
Scott. For further information concerning Ryder Scott's estimate of our proved
reserves at December 31, 2003, see the reserve report included as an exhibit to
this Annual Report on Form 10-K (the "Ryder Scott Report"). 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 us. For further information
concerning the present value of future net revenue from these proved reserves,
see Note 18 to our consolidated financial statements. See ITEMS 1 AND 2.
"BUSINESS AND PROPERTIES -- RISK FACTORS." The

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oil and natural gas reserve data included in or incorporated by reference in
this document are only estimates and may prove to be inaccurate.

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(1) Proved developed reserves are proved reserves that are expected to be
recovered from existing wells with existing equipment and operating methods.

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

(3) Includes plant products.

(4) Estimated future net revenue represents estimated future gross revenue to be
generated from the production of proved reserves, net of estimated future
production and development costs, using year-end oil and natural gas prices
in effect at December 31, 2003, which were $5.97 per Mcf of natural gas and
$32.55 per Bbl of oil.

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 manner, 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 revenue from proved reserves and the present value thereof are based
upon certain assumptions, including current prices, production levels and costs
that may not be what is actually incurred or realized.

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

In accordance with Commission regulations, the Ryder Scott Report used
year-end oil and natural gas prices in effect at December 31, 2003. 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 December 31, 2003. 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.

5

OIL AND NATURAL GAS VOLUMES, PRICES AND OPERATING EXPENSE

The following table sets forth certain information regarding production
volumes, average sales prices and average oil and natural gas operating expense
associated with our sale of oil and natural gas for the periods indicated.

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(1) Includes the effect of hedging activity.

(2) Includes direct lifting costs (labor, repairs and maintenance, materials and
supplies), expensed workover costs and the administrative costs of
production offices, insurance and production and ad valorem taxes.

FINDING AND DEVELOPMENT COSTS

We incurred total exploration, development and acquisition costs of
approximately $35.6 million, including $0.9 million related to asset retirement
costs ("ARC"), for the year ended December 31, 2003 that added 23.1 Bcfe, net to
our interest, of proved reserves. Our average finding and development cost was
$1.54 per Mcfe ($1.50 per Mcfe excluding ARC) for 2003. For the three most
recent years, the total of these costs was $84.4 million ($82.8 excluding ARC)
adding 57.9 Bcfe of proved reserves for an average finding and development cost
of $1.46 per Mcfe ($1.43 per Mcfe excluding the ARC).

EXPLORATION, DEVELOPMENT AND ACQUISITION CAPITAL EXPENDITURES

The following table sets forth certain information regarding the total
costs incurred associated with exploration, development and acquisition
activities.

6

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(1) Excluded from asset retirement costs in 2003 was $640,400 related to the
cumulative effect of the adoption of SFAS No. 143 on January 1, 2003. See
Note 7 to our consolidated financial statements.

Net costs incurred excludes sales of proved oil and natural gas properties
which 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.

DRILLING ACTIVITY

The following table sets forth our drilling activity for the three years
ended December 31, 2003. In the table, "gross" refers to the total wells in
which we have a working interest or back-in working interest after payout and
"net" refers to gross wells multiplied by our working interest therein.

PRODUCTIVE WELLS

The following table sets forth the number of productive oil and natural gas
wells in which we owned an interest as of December 31, 2003.

7

ACREAGE DATA

The following table sets forth certain information regarding our developed
and undeveloped lease acreage as of December 31, 2003. Developed acres refer to
acreage within producing units and undeveloped acres refer to acreage that has
not been placed in producing units.

Leases covering approximately 14,308 gross (6,095 net), 4,114 gross (2,284
net) and 26,924 gross (17,203 net) undeveloped acres are scheduled to expire in
2004, 2005 and 2006, respectively. In general, our leases will continue past
their primary terms if oil and natural gas production in commercial quantities
is being produced from a well on such lease.

The table does not include (i) 80,000 gross (68,000 net) acres that we have
a right to acquire at December 31, 2003 pursuant to an Indian Mineral
Development Agreement with the Blackfeet Indian Nation in North Central Montana
or (ii) 47,000 gross (13,500 net) acres that we have the right to earn in SE New
Mexico pursuant to an Exploration Agreement that we consummated in August 2003.

CORE AREAS OF OPERATION

As of December 31, 2003, 67.6% of our proved reserves were in south Texas,
21.6% in south Louisiana and 9.9% in Mississippi and Alabama. During 2003, we
added reserves and production in Mississippi and Michigan through our merger
with Miller Exploration. We also added a new core area in SE New Mexico. In
total, these three states comprised the remaining 0.9% of our proved reserves.

The table below sets forth the gross and net number of our gas and oil
wells in each of our core areas of operation as of December 31, 2003.

TEXAS

We currently own an interest in 77,960 gross (28,455 net) acres in south
and south-central Texas. Our areas of focus in this region are predominantly in
the Wilcox (Lobo), Queen City, Yegua, Vicksburg and Frio producing trends. As of
December 31, 2003, we operated approximately 81 producing wells, accounting for
about 78% of our total net production in Texas. We drilled 26 wells during 2003
in Texas, 24 of which were

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successfully completed. The majority of our 2003 drilling activity took place at
Gato Creek, Encinitas and in the O'Connor Ranch East Project Area. We drilled
five successful wells at Gato Creek and installed plunger lifts on three wells
to improve production performance. Ten successful wells were drilled in the
Encinitas Field and nine successful wells were drilled at O'Connor Ranch East
during 2003. During 2004, we currently expect to drill 15 to 20 wells in our
core areas in Texas. The majority of these wells are planned in our Encinitas
Field and in various project areas in the Lobo, Queen City, Vicksburg and Frio
trends. We also plan to participate with a 25% working interest in a 13,000'
Vicksburg exploratory test in Jefferson County, Texas.

We made two cash asset acquisitions in our core areas in Texas during 2003.
Both acquisitions added to our existing positions, notably in the Gato Creek
Field area and the Queen City area.

LOUISIANA

We currently own an interest in 5,876 gross (966 net) acres in south
Louisiana. Our operations in this area have been focused in the prolific
gas-producing region covering portions of Acadia, Lafayette, St. Landry and
Vermilion Parishes. As of December 31, 2003, we had an interest in eight wells,
none of which we operate. In 2003, we completed the sidetrack operation of the
Thibodeaux #1 well and re-established production. Two exploratory wells were
also drilled in late 2003, one of which was a dry hole and the other produced
for a short time from a shallow completion. We currently have plans to
participate with a 25% working interest in a 12,000' exploratory test in 2004.
This well will be located in Calcasieu Parish in southwest Louisiana and will
target the Hackberry sands. We also plan to drill a saltwater disposal well to
dispose of produced water from the Thibodeaux #1 ST well and may drill a
development well offsetting the Thibodeaux #1 ST.

MISSISSIPPI

We currently own an interest in 14,936 gross (6,147 net) acres in
Mississippi. We acquired additional reserves and production in the Mississippi
Salt Basin in south central Mississippi as part of the 2003 merger with Miller.
The primary producing horizons in the Mississippi Salt Basin around the Miller
properties include the Hosston, Sligo, Rodessa and James Lime sections. As of
December 31, 2003, we operated eight producing wells, accounting for about 74%
of our total net production in Mississippi. Current plans are to drill one well
in this area in 2004.

MICHIGAN

We currently own an interest in 658 gross (658 net) acres in Michigan. We
acquired acreage and one producing well in south central Michigan as part of the
2003 merger with Miller. This well is operated by Edge and produces from the
Trenton/Black River formation at approximately 3,000 feet. We are currently
assessing opportunities in Michigan, but have no definite plans for additional
activity in 2004 at this time.

NEW MEXICO

We currently own an option on 13,500 net acres in SE New Mexico. We
established a new core area in SE New Mexico through an alliance with two
private companies in 2003. This alliance enables us to earn an interest in
47,000 gross (13,500 net) acres by satisfying a ten well drilling obligation. We
participated in the drilling of two wells in 2003 and have completed the
drilling of an additional three wells in early 2004, all of which have been
successful. During 2004, we anticipate drilling 20 to 25 wells in New Mexico and
we anticipate working to add to our acreage position in this area.

NORTHERN ROCKY MOUNTAINS

We currently own an interest in 108,880 gross (24,392 net) undeveloped
acres in the northern Powder River Basin of Montana and also own an option on
80,000 gross (68,000 net) acres in north central Montana on a portion of the
Blackfeet Indian Nation lands. We drilled five dry holes on the acreage position
in the northern Powder River Basin in 2003 and have no current plans for
additional drilling on this acreage. Our option on the Blackfeet Indian Nation
lands was acquired as part of the 2003 merger with Miller. We anticipate that at
least two wells may be drilled on Blackfeet Indian Nation lands in 2004.

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MARKETING

Our production is marketed to third parties consistent with industry
practices. Typically, oil is sold at the well-head at field-posted prices and
natural gas is sold under contract at a negotiated monthly price based upon
factors normally considered in the industry, such as conditioning or treating to
make gas marketable, distance from the well to the transportation pipeline, well
pressure, estimated reserves, quality of natural gas and prevailing
supply/demand conditions.

Our marketing objective is to receive the highest possible wellhead price
for our product. We are aided by the presence of multiple outlets near our
production on the Gulf Coast. We take 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. We have not experienced any significant
difficulties in marketing our 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.

We market our 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
our production at prices exceeding forecast. All such hedging transactions
provide for financial rather than physical settlement. See ITEM 7. "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -- CRITICAL ACCOUNTING POLICIES AND ESTIMATES -- DERIVATIVES
AND HEDGING ACTIVITIES."

Due to the instability of oil and natural gas prices, we may enter into,
from time to time, price risk management transactions (e.g., swaps, collars and
floors) for a portion of our oil and natural gas production to achieve a more
predictable cash flow, as well as to reduce exposure from price fluctuations.
While the use of these arrangements limits our ability to benefit from increases
in the price of oil and natural gas, it also reduces our potential exposure to
adverse price movements. Our hedging arrangements, to the extent we enter into
any, apply to only a portion of our production and provide only partial price
protection against declines in oil and natural gas prices and limits our
potential gains from future increases in prices. Our management sets all of our
hedging policies, including volumes, types of instruments and counter parties,
on a quarterly basis. These policies are implemented by management through the
execution of trades by the Chief Financial Officer after consultation and
concurrence by the President and Chairman of the Board. Our Board of Directors
reviews our hedge policies and trades. We account for these transactions as
hedging activities and, accordingly, realized gains and losses are included in
oil and natural gas revenue during the period the hedged transactions occur.

Although we take some measures to attempt to control price risk, we remain
subject to price fluctuations for natural gas sold in the spot market due
primarily to seasonality of demand and other factors beyond our control.
Domestic oil prices generally follow worldwide oil prices, which are subject to
price fluctuations resulting from changes in world supply and demand. We
continue to evaluate the potential for reducing these risks by entering into
hedge transactions. Included within natural gas revenue for the years ended

10

December 31, 2003, 2002, and 2001 was approximately $4.5 million, $0.3 million
and $0.9 million, respectively, representing net losses from hedging activity as
shown in the table of settled hedges below.

The table below summarizes the Company's outstanding hedges at December 31,
2003, 2002 and 2001.

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(1) The Company's current hedging activities for natural gas were entered into
on a per MMbtu delivered price basis, with settlement for each calendar
month occurring five business days following the expiration date.

(2) This hedge was entered into at a cost of $686,250.

The table below summarizes the Company's hedging activities entered into
after December 31, 2003.

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(1) The Company's current hedging activities for natural gas were entered into
on a per MMbtu delivered price basis, Houston Ship Channel Index, with
settlement for each calendar month occurring five business days following
the expiration date.

(2) The Company's current hedging activities for crude oil were entered into on
a per Bbl delivered price basis, West Texas Intermediate Index, with
settlement for each calendar month occurring five business days following
the expiration date.

COMPETITION

We encounter competition from other oil and natural gas companies in all
areas of our operations, including the acquisition of exploratory prospects and
proven properties. Our competitors include major integrated oil and natural gas
companies and numerous independent oil and natural gas companies, individuals

11

and drilling and income programs. Many of our competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than ours and which, in many instances, have been
engaged in the oil and natural gas business for a much longer time than us. Such
companies may be able to pay more for exploratory prospects and productive oil
and natural gas properties and may be able to define, evaluate, bid for and
purchase a greater number of properties and prospects than our financial or
human resources permit. In addition, such companies may be able to expend
greater resources on the existing and changing technologies that we believe are
and will be increasingly important to the current and future success of oil and
natural gas companies. Our ability to explore for oil and natural gas reserves
and to acquire additional properties in the future will be dependent upon our
ability to conduct our operations, to evaluate and select suitable properties
and to consummate transactions in this highly competitive environment. We
believe that our technological expertise, our exploration, land, drilling and
production capabilities and the experience of our management generally enable us
to compete effectively. Many of our competitors, however, have financial
resources and exploration and development budgets that are substantially greater
than ours, which may adversely affect our ability to compete with these
companies.

INDUSTRY REGULATIONS

The availability of a ready market for oil and natural gas production
depends upon numerous factors beyond our control. These factors include
regulation of oil and natural gas 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 oil and natural gas
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 we may conduct operations. State and federal regulations
generally are intended to prevent waste of oil and natural gas, protect rights
to produce oil and natural gas between owners in a common reservoir, control the
amount of oil and natural gas 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. We are also
subject to changing and extensive tax laws, the effects of which cannot be
predicted. The following discussion summarizes the regulation of the United
States oil and natural gas industry. We believe that we are in substantial
compliance with the various statutes, rules, regulations and governmental orders
to which our operations may be subject, although there can be no assurance that
this is or will remain the case. Moreover, such statutes, rules, regulations and
government orders may be changed or reinterpreted from time to time in response
to economic or political conditions, and there can be no assurance that such
changes or reinterpretations will not materially adversely affect our results of
operations and financial condition. The following discussion is not intended to
constitute a complete discussion of the various statutes, rules, regulations and
governmental orders to which our operations may be subject.

Regulation of Oil and Natural Gas Exploration and Production. Our
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, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. Our operations are also subject to various conservation laws
and regulations. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells that may be drilled in
and the unitization or pooling of oil and natural 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 we can produce
from our wells and may limit the number of wells or the locations at which we
can drill. The regulatory burden on the oil and natural gas industry increases
our costs of doing business and, consequently, affects our

12

profitability. Inasmuch as such laws and regulations are frequently expanded,
amended and reinterpreted, we are unable to predict the future cost or impact of
complying with such regulations.

Regulation of Sales and Transportation of Natural Gas. Federal legislation
and regulatory controls have historically affected the price of natural gas
produced by us, and the manner in which such production is transported and
marketed. Under the Natural Gas Act ("NGA") of 1938, the Federal Energy
Regulatory Commission (the "FERC") regulates the interstate transportation and
the sale in interstate commerce for resale of natural gas. Effective January 1,
1993, the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated
natural gas prices for all "first sales" of natural gas, including all sales by
us of our own production. As a result, all of our domestically produced natural
gas may now be sold at market prices, subject to the terms of any private
contracts that may be in effect. However, the Decontrol Act did not affect the
FERC's jurisdiction over natural gas transportation.

Our natural gas sales are affected by intrastate and interstate gas
transportation regulation. Following the Congressional passage of the NGPA, the
FERC adopted a series of regulatory changes that have significantly altered the
transportation and marketing of natural gas. Beginning with the adoption of
Order No. 436, issued in October 1985, the FERC has implemented a series of
major restructuring orders that have required pipelines, among other things, to
perform "open access" transportation of gas for others, "unbundle" their sales
and transportation functions, and allow shippers to release their unneeded
capacity temporarily and permanently to other shippers. As a result of these
changes, sellers and buyers of gas have gained direct access to the particular
pipeline services they need and are better able to conduct business with a
larger number of counterparties. We believe these changes generally have
improved our access to markets while, at the same time, substantially increasing
competition in the natural gas marketplace. It remains to be seen, however, what
effect the FERC's other activities will have on access to markets, the fostering
of competition and the cost of doing business. We cannot predict what new or
different regulations the FERC and other regulatory agencies may adopt, or what
effect subsequent regulations may have on our activities. We do not believe that
we will be affected by any such new or different regulations materially
differently than any other seller of natural gas with which we compete.

In the past, Congress has been very active in the area of gas regulation.
However, as discussed above, the more recent trend has been in favor of
deregulation, or "lighter handed" regulation, and the promotion of competition
in the gas industry. There regularly are other legislative proposals pending in
the Federal and state legislatures that, if enacted, would significantly affect
the petroleum industry. At the present time, it is impossible to predict what
proposals, if any, might actually be enacted by Congress or the various state
legislatures and what effect, if any, such proposals might have on us.
Similarly, and despite the trend toward federal deregulation of the natural gas
industry, whether or to what extent that trend will continue, or what the
ultimate effect will be on our sales of gas, cannot be predicted. Again, we do
not believe that we will be affected by any such new legislative proposals
materially differently than any other seller of natural gas with which we
compete.

We own certain natural gas pipelines that we believe meet the standards the
FERC has used to establish a pipeline's status as a gatherer not subject to FERC
jurisdiction under the NGA. State regulation of gathering facilities generally
includes various safety, environmental, and in some circumstances,
nondiscriminatory take requirements, but does not generally entail rate
regulation. Natural gas gathering may receive greater regulatory scrutiny at
both state and federal levels in the post-restructuring environment.

Oil Price Controls and Transportation Rates. Sales of crude oil,
condensate and gas liquids by us are not currently regulated and are made at
market prices. The price we receive from the sale of these products may be
affected by the cost of transporting the products to market. Much of the
transportation is through interstate common carrier pipelines. Effective as of
January 1, 1995, the FERC implemented regulations generally grandfathering all
previously approved interstate transportation rates and establishing an indexing
system for those rates by which adjustments are made annually based on the rate
of inflation, subject to certain conditions and limitations. These regulations
have generally been approved on judicial review. Every five years, the FERC must
examine the relationship between the annual change in the applicable index and
the actual cost changes experienced in the oil pipeline industry. The first such
review was completed in 2000, and on

13

December 14, 2000, FERC reaffirmed the current index. The FERC's regulation of
oil transportation rates may tend to increase the cost of transporting oil and
natural gas liquids by interstate pipelines, although the annual adjustments may
result in decreased rates in a given year. Following a successful court
challenge of these orders by an association of oil pipelines on February 24,
2003, the FERC acting on remand increased the index slightly for the current
five-year period, effective July 2001. We are not able at this time to predict
the effects of these regulations, if any, on the transportation costs associated
with oil production from our oil producing operations.

Environmental Regulations. Our operations are subject to numerous federal,
state and local laws and regulations governing the discharge of materials into
the environment or otherwise relating to environmental protection. These laws
and regulations may require the acquisition of a permit before drilling
commences, restrict the types, quantities and concentration of various
substances that can be released into the environment in connection with drilling
and production activities, limit or prohibit drilling activities on certain
lands within wilderness, wetlands and other protected areas, require remedial
measures to mitigate pollution from former operations, such as pit closure and
plugging abandoned wells, and impose substantial liabilities for pollution
resulting from production and drilling operations. 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
applied to the oil and natural gas industry could continue, resulting in
increased costs of doing business and consequently affecting profitability. To
the extent laws are enacted or other governmental action is taken that restricts
drilling or imposes more stringent and costly waste handling, disposal and
cleanup requirements, our business and prospects could be adversely affected.

We generate wastes that may be subject to the federal Resource Conservation
and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental
Protection Agency ("EPA") and various state agencies have limited the approved
methods of disposal for certain hazardous and nonhazardous wastes. Furthermore,
certain wastes generated by our 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.

We currently own or lease numerous properties that for many years have been
used for the exploration and production of oil and natural gas. Although we
believe that we have used good operating and waste disposal practices, prior
owners and operators of these properties may not have used similar practices,
and hydrocarbons or other wastes may have been disposed of or released on or
under the properties owned or leased by us 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 our control. These properties and the
wastes disposed thereon may be subject to the Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state
laws as well as state laws governing the management of oil and natural gas
wastes. Under such laws, we 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.

Our 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 have resulted in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. The EPA and states developed and continue to develop regulations to
implement these requirements. We 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 emission-related issues. However, we do not believe our
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 Edge, to prepare and implement spill
prevention, control, countermeasure ("SPCC") and response plans relating to the
possible discharge of oil into surface waters. SPCC plans at certain of our
properties were developed and implemented in 1999. The Oil Pollution Act of 1990
("OPA") contains numerous require-

14

ments 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. Noncompliance with OPA may
result in varying civil and criminal penalties and liabilities. Our operations
are also subject to the federal Clean Water Act ("CWA") and analogous state
laws. In accordance with the CWA, the state of Louisiana has issued regulations
prohibiting discharges of produced water in state coastal waters effective July
1, 1997. Pursuant to other requirements of the CWA, the EPA has 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 general permit. While certain of our properties
may require permits for discharges of storm water runoff, we believe that we
will be able to obtain, or be included under, such permits, where necessary, and
make minor modifications to existing facilities and operations that would not
have a material effect on us. Like OPA, the CWA and analogous state laws
relating to the control of water pollution provide varying civil and criminal
penalties and liabilities for releases of petroleum or its derivatives into
surface waters or into the ground.

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, for damages to natural resources and for the
costs of certain health studies, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment.

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

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,
natural gas leaks, ruptures and discharges of toxic gases, the occurrence of any
of which could result in substantial losses to us 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, we maintain insurance
against some, but not all, of the risks described above. Our insurance does not
cover business interruption or protect against loss of revenue. There can be no
assurance that any insurance obtained by us will be adequate to cover any losses
or liabilities. We 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 our financial condition and operations.

TITLE TO PROPERTIES

We believe we have satisfactory title to all of our producing properties in
accordance with standards generally accepted in the oil and natural gas
industry. Our properties are subject to customary royalty interests, liens
incident to operating agreements, liens for current taxes and other burdens,
which we believe 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

15

a preliminary review of local records). Investigations, including a title
opinion of local counsel, are made before commencement of drilling operations.

We have granted mortgage liens, on substantially all of our properties in
favor of Union Bank of California, as agent, to secure our credit facility.
These mortgages and the credit facility contain substantial restrictions and
operating covenants that are customarily found in loan agreements of this type.
See ITEM 7. "MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS -- LIQUIDITY AND CAPITAL RESOURCES -- CREDIT FACILITY" and
Note 9 to our consolidated financial statements.

EMPLOYEES

At December 31, 2003, we had 35 full-time employees. We believe that our
relationships with our employees are good. None of our employees are covered by
a collective bargaining agreement. From time to time, we utilize 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.

OFFICE AND EQUIPMENT

Late in 2002, we negotiated a lease for new offices at 1301 Travis Street,
Suite 2000, Houston, Texas. We moved into our new space, covering 20,500 square
feet (compared to 28,200 square feet under our previous lease), during the first
week of February 2003.

RISK FACTORS

OIL AND GAS DRILLING IS A SPECULATIVE ACTIVITY AND INVOLVES NUMEROUS RISKS AND
SUBSTANTIAL AND UNCERTAIN COSTS WHICH COULD ADVERSELY AFFECT US.

Our growth will be materially dependent upon the success of our future
drilling program. Drilling for oil and gas involves numerous risks, including
the risk that no commercially productive oil or natural gas reservoirs will be
encountered. The cost of drilling, completing and operating wells is substantial
and uncertain, and drilling operations may be curtailed, delayed or cancelled as
a result of a variety of factors beyond our control, 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 or
crews and the delivery of equipment. Our future drilling activities may not be
successful and, if unsuccessful, such failure will have an adverse effect on our
future results of operations and financial condition. Our overall drilling
success rate or our drilling success rate for activity within a particular
geographic area may decline. We may ultimately not be able to lease or drill
identified or budgeted prospects within our expected time frame, or at all. We
may not be able to lease or drill a particular prospect because, in some cases,
we identify a prospect or drilling location before seeking an option or lease
rights in the prospect or location. Similarly, our drilling schedule may vary
from our capital budget. 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 to us 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) our financial resources and
results and (vi) the availability of leases and permits on reasonable terms for
the prospects. These projects may not be successfully developed and the wells,
if drilled, may not encounter reservoirs of commercially productive oil or
natural gas. See ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS -- INDUSTRY AND ECONOMIC FACTORS" and ITEMS
1 AND 2. "BUSINESS AND PROPERTIES -- CORE AREAS OF OPERATION."

16

OIL AND NATURAL GAS PRICES ARE HIGHLY VOLATILE IN GENERAL AND LOW PRICES
NEGATIVELY AFFECT OUR FINANCIAL RESULTS.

Our revenue, profitability, cash flow, future growth and ability to borrow
funds or obtain additional capital, as well as the carrying value of our
properties, are substantially dependent upon prevailing prices of oil and
natural gas. Our reserves are predominantly natural gas, therefore changes in
natural gas prices may have a particularly large impact on our financial
results. Lower oil and natural gas prices also may reduce the amount of oil and
natural gas that we can produce economically. Historically, the markets for oil
and natural gas have been volatile, and such markets are likely to continue to
be volatile in the future. Prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond our control. 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, the foreign
supply of oil and natural gas, the price of foreign imports and overall economic
conditions. Declines in oil and natural gas prices may materially adversely
affect our financial condition, liquidity, and ability to finance planned
capital expenditures and results of operations. See ITEM 7. "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -- DERIVATIVES AND HEDGING ACTIVITIES" and ITEMS 1 AND 2. "BUSINESS
AND PROPERTIES -- OIL AND NATURAL GAS RESERVES" and "-- MARKETING."

We have in the past and may in the future be required to write down the
carrying value of our oil and natural gas properties when oil and natural gas
prices are depressed or unusually volatile. Whether we will be required to take
such a charge will depend on the prices for oil and natural gas at the end of
any quarter and the effect of reserve additions or revisions and capital
expenditures during such quarter. If a write down is required, it would result
in a charge to earnings and would not impact cash flow from operating
activities.

WE HAVE HEDGED AND MAY CONTINUE TO HEDGE A PORTION OF OUR PRODUCTION, WHICH
MAY RESULT IN OUR MAKING CASH PAYMENTS OR PREVENT US FROM RECEIVING THE FULL
BENEFIT OF INCREASES IN PRICES FOR OIL AND GAS.

In order to reduce our exposure to short-term fluctuations in the price of
oil and natural gas, we periodically enter into hedging arrangements. Our
hedging arrangements apply to only a portion of our production and provide only
partial price protection against declines in oil and natural gas prices. Such
hedging arrangements may expose us to risk of financial loss in certain
circumstances, including instances where production is less than expected, our
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, our hedging arrangements may limit the benefit to us of increases in
the price of oil and natural gas. See ITEM 7. "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- DERIVATIVES AND
HEDGING ACTIVITIES" and ITEMS 1 AND 2. "BUSINESS AND PROPERTIES -- MARKETING."

WE DEPEND ON SUCCESSFUL EXPLORATION, DEVELOPMENT AND ACQUISITIONS TO MAINTAIN
RESERVES AND REVENUE IN THE FUTURE.

In general, the volume of production from oil and natural gas properties
declines as reserves are depleted, with the rate of decline depending on
reservoir characteristics. Except to the extent we acquire properties containing
proved reserves or conduct successful exploration and development activities, or
both, our proved reserves will decline. Our future oil and natural gas
production is, therefore, highly dependent upon our level of success in finding
or acquiring additional reserves. In addition, we are dependent on finding
partners for our exploratory activity. To the extent that others in the industry
do not have the financial resources or choose not to participate in our
exploration activities, we will be adversely affected.

WE ARE SUBJECT TO SUBSTANTIAL OPERATING RISKS THAT MAY ADVERSELY AFFECT THE
RESULTS OF OUR OPERATIONS.

The oil and natural gas business involves certain operating hazards such as
well blowouts, mechanical failures, explosions, uncontrollable flows of oil,
natural gas or well fluids, fires, formations with abnormal

17

pressures, pollution, releases of toxic gas and other environmental hazards and
risks. We could suffer substantial losses as a result of any of these events. We
are not fully insured against all risks incident to our business.

We are not the operator of some of our wells. As a result, our operating
risks for those wells and our ability to influence the operations for these
wells are less subject to our control. Operators of these wells may act in ways
that are not in our best interests. See ITEMS 1 AND 2. "BUSINESS AND
PROPERTIES -- OPERATING HAZARDS AND INSURANCE."

WE CANNOT CONTROL THE ACTIVITIES ON PROPERTIES WE DO NOT OPERATE AND ARE
UNABLE TO ENSURE THEIR PROPER OPERATION AND PROFITABILITY.

We do not operate all of the properties in which we have an interest. As a
result, we have limited ability to exercise influence over, and control the
risks associated with, operations of these properties. The failure of an
operator of our wells to adequately perform operations, an operator's breach of
the applicable agreements or an operator's failure to act in ways that are in
our best interest could reduce our production and revenues. The success and
timing of our drilling and development activities on properties operated by
others therefore depend upon a number of factors outside of our control,
including the operator's

- timing and amount of capital expenditures;

- expertise and financial resources;

- inclusion of other participants in drilling wells; and

- use of technology.

THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT US.

We depend to a large extent on the services of certain key management
personnel, including our executive officers and other key employees, the loss of
any of which could have a material adverse effect on our operations. We do not
maintain key-man life insurance with respect to any of our employees. We believe
that our success is also dependent upon our ability to continue to employ and
retain skilled technical personnel. See ITEMS 1 AND 2. "BUSINESS AND
PROPERTIES -- TECHNOLOGY."

OUR OPERATIONS HAVE SIGNIFICANT CAPITAL REQUIREMENTS WHICH, IF NOT MET, WILL
HINDER OPERATIONS.

We have experienced and expect to continue to experience substantial
working capital needs due to our active exploration, development and acquisition
programs. Additional financing may be required in the future to fund our growth.
We may not be able to obtain such additional financing and financing under
existing or new credit facilities may not be available in the future. In the
event such capital resources are not available to us, our drilling and other
activities may be curtailed. See ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- LIQUIDITY AND CAPITAL
RESOURCES."

GOVERNMENT REGULATION AND LIABILITY FOR ENVIRONMENTAL MATTERS MAY ADVERSELY
AFFECT OUR BUSINESS AND RESULTS OF OPERATIONS.

Oil and natural gas operations are subject to various federal, state and
local government regulations, which may be changed from time to time. 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. There are federal, state and
local laws and regulations primarily relating to protection of human health and
the environment applicable to 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. In addition, we may be liable

18

for environmental damages caused by previous owners of property we purchase or
lease. As a result, we may incur substantial liabilities to third parties or
governmental entities. We are also subject to changing and extensive tax laws,
the effects of which cannot be predicted. The implementation of new, or the
modification of existing, laws or regulations could have a material adverse
effect on us. See ITEMS 1 AND 2. "BUSINESS AND PROPERTIES -- INDUSTRY
REGULATIONS."

WE MAY HAVE DIFFICULTY MANAGING ANY FUTURE GROWTH AND THE RELATED DEMANDS ON
OUR RESOURCES AND MAY HAVE DIFFICULTY IN ACHIEVING FUTURE GROWTH.

We have experienced growth in the past through the expansion of our
drilling program and, more recently, acquisitions. This expansion was curtailed
in 1998 and 1999, but resumed in 2000 and increased in subsequent years. Further
expansion is anticipated in 2004 both through increased drilling efforts and
possible acquisitions. Any future growth may place a significant strain on our
financial, technical, operational and administrative resources. Our ability to
grow will depend upon a number of factors, including our ability to identify and
acquire new exploratory prospects, our ability to develop existing prospects,
our ability to continue to retain and attract skilled personnel, the results of
our drilling program and acquisition efforts, hydrocarbon prices and access to
capital. We may not be successful in achieving or managing growth and any such
failure could have a material adverse effect on us.

WE FACE STRONG COMPETITION FROM LARGER OIL AND NATURAL GAS COMPANIES.

Our 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 our competitors are large, well-established companies
with substantially larger operating staffs and greater capital resources than
us. We may not be able to successfully conduct our operations, evaluate and
select suitable properties and consummate transactions in this highly
competitive environment. Specifically, these larger competitors may be able to
pay more for exploratory prospects and productive oil and natural gas properties
and may be able to define, evaluate, bid for and purchase a greater number of
properties and prospects than our financial or human resources permit. In
addition, such companies may be able to expend greater resources on the existing
and changing technologies that we believe are and will be increasingly important
to attaining success in the industry. See ITEMS 1 AND 2. "BUSINESS AND
PROPERTIES -- COMPETITION."

THE OIL AND NATURAL GAS RESERVE DATA INCLUDED IN OR INCORPORATED BY REFERENCE
IN THIS DOCUMENT ARE ESTIMATES BASED ON ASSUMPTIONS THAT MAY BE INACCURATE AND
EXISTING ECONOMIC AND OPERATING CONDITIONS THAT MAY DIFFER FROM FUTURE
ECONOMIC AND OPERATING CONDITIONS.

Reservoir engineering is a subjective and inexact process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact manner and is based upon assumptions that may vary considerably from
actual results. Accordingly, reserve estimates may be subject to downward or
upward adjustment. Actual production, revenue and expenditures with respect to
our reserves will likely vary from estimates, and such variances may be
material. The information regarding discounted future net cash flows included in
this report should not be considered as the current market value of the
estimated oil and natural gas reserves attributable to our properties. As
required by the Commission, the estimated discounted future net cash flows from
proved reserves are based on prices and costs as of the date of the estimate,
while actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by factors such as the amount and
timing of actual production, supply and demand for oil and natural gas,
increases or decreases in consumption, and changes in governmental regulations
or taxation. In addition, the 10% discount factor, which is required by
Financial Accounting Standards Board in Statement of Financial Accounting
Standards No. 69, "Disclosures About Oil and Natural Gas Producing Activities"
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 us or the
oil and natural gas industry in general. See ITEMS 1 AND 2. "BUSINESS AND
PROPERTIES -- OIL AND NATURAL GAS RESERVES."

19

OUR CREDIT FACILITY HAS SUBSTANTIAL OPERATING RESTRICTIONS AND FINANCIAL
COVENANTS AND WE MAY HAVE DIFFICULTY OBTAINING ADDITIONAL CREDIT WHICH COULD
ADVERSELY AFFECT OPERATIONS.

Over the past few years, increases in commodity prices, in proved reserve
amounts and the resultant increase in estimated discounted future net revenue,
has allowed us to increase our available borrowing amounts. In the future,
commodity prices may decline, we may increase our borrowings or our borrowing
base may be adjusted downward. Our credit facility is secured by a pledge of
substantially all of our assets and has covenants that limit additional
borrowings, sales of assets and the distributions of cash or properties and that
prohibit the payment of dividends and the incurrence of liens. The revolving
credit facility also requires that specified financial ratios be maintained. The
restrictions of our credit facility and the difficulty in obtaining additional
debt financing may have adverse consequences on our operations and financial
results, including our ability to obtain financing for working capital, capital
expenditures, our drilling program, purchases of new technology or other
purposes. In addition, such financing may be on terms unfavorable to us and we
may be required to use a substantial portion of our cash flow to make debt
service payments, which will reduce the funds that would otherwise be available
for operations and future business opportunities. Further, a substantial
decrease in our operating cash flow or an increase in our expenses could make it
difficult for us to meet debt service requirements and require us to modify
operations and we may become more vulnerable to downturns in our business or the
economy generally.

Our ability to obtain and service indebtedness will depend on our future
performance, including our ability to manage cash flow and working capital,
which are in turn subject to a variety of factors beyond our control. Our
business may not generate cash flow at or above anticipated levels or we may not
be able to borrow funds in amounts sufficient to enable us to service
indebtedness, make anticipated capital expenditures or finance our drilling
program. If we are unable to generate sufficient cash flow from operations or to
borrow sufficient funds in the future to service our debt, we may be required to
curtail portions of our drilling program, sell assets, reduce capital
expenditures, refinance all or a portion of our existing debt or obtain
additional financing. We may not be able to refinance our debt or obtain
additional financing, particularly in view of current industry conditions, the
restrictions on our ability to incur debt under our existing debt arrangements,
and the fact that substantially all of our assets are currently pledged to
secure obligations under our bank credit facility. See ITEM 7. "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -- LIQUIDITY AND CAPITAL RESOURCES" and "-- CREDIT FACILITY."

WE MAY NOT HAVE ENOUGH INSURANCE TO COVER ALL OF THE RISKS WE FACE.

In accordance with customary industry practices, we maintain insurance
coverage against some, but not all, potential losses in order to protect against
the risks we face. We do not carry business interruption insurance. We may elect
not to carry insurance if our management believes that the cast of available
insurance is excessive relative to the risks presented. In addition, we cannot
insure fully against pollution and environmental risks. The occurrence of an
event not fully covered by insurance could have a material adverse effect on our
financial condition and results of operations.

OUR ACQUISITION PROGRAM MAY BE UNSUCCESSFUL, PARTICULARLY IN LIGHT OF OUR
LIMITED ACQUISITION EXPERIENCE.

Because we have not typically purchased properties, we may not be in as
good a position as our more experienced competitors to execute a successful
acquisition program. The successful acquisition 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, even when performed by experienced personnel, are
necessarily inexact and their accuracy inherently uncertain. Our review of
subject properties will not reveal all existing or potential problems,
deficiencies and capabilities. We may not always perform inspections on every
well, and may not be able to observe structural and environmental problems even
when we undertake an inspection. Even when problems are identified, the seller
may be unwilling or unable to provide effective contractual protection against
all or part of such problems. Any acquisition of property interests by us may
not be successful and, if unsuccessful, such failure may have an adverse effect
on our future results of operations and financial condition.

20

THE FAILURE TO SUCCESSFULLY INTEGRATE MILLER EXPLORATION COMPANY INTO EDGE MAY
RESULT IN OUR NOT BEING ABLE TO ACHIEVE THE ANTICIPATED POTENTIAL BENEFITS OF
THE MERGER.

Before the merger, Edge and Miller operated as separate companies. Our
management had not previously managed the business of Miller. We may not be able
to integrate the operations of Miller effectively. Integration requires
substantial management attention and could detract attention away from our
day-to-day business. We could encounter difficulties in the integration process,
such as the unexpected loss of employees, customers or suppliers. In addition,
if we cannot integrate the businesses successfully, we may fail to realize the
operating efficiencies, synergies, cost savings or other benefits from the
merger. Any unexpected costs or delays incurred in connection with the
integration could have an adverse effect on our business, results of operations
or financial condition. We have incurred charges to earnings relating to
restructuring and related expenses in connection with the merger in the amount
of $279,400 and expect to incur additional charges of approximately $225,000,
although the actual amount cannot be predicted with certainty and could be
higher or lower.

WE DO NOT INTEND TO PAY DIVIDENDS AND OUR ABILITY TO PAY DIVIDENDS IS
RESTRICTED.

We currently intend to retain any earnings for the future operation and
development of our business and do not currently anticipate paying any dividends
in the foreseeable future. Any future dividends also may be restricted by our
then-existing loan agreements. See ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- LIQUIDITY AND CAPITAL
RESOURCES" and Note 9 to our consolidated financial statements.

OUR RELIANCE ON THIRD PARTIES FOR GATHERING AND DISTRIBUTING COULD CURTAIL
FUTURE EXPLORATION AND PRODUCTION ACTIVITIES.

The marketability of our production depends upon the proximity of our
reserves to, and the capacity of, facilities and third party services, including
oil and natural gas gathering systems, pipelines, trucking or terminal
facilities, and processing facilities. The unavailability or lack of capacity of
such services and facilities could result in the shut-in of producing wells or
the delay or discontinuance of development plans for properties. A shut-in or
delay or discontinuance could adversely affect our financial condition. In
addition, federal and state regulation of oil and natural gas production and
transportation affect our ability to produce and market our oil and natural gas
on a profitable basis.

PROVISIONS OF DELAWARE LAW AND OUR CHARTER AND BYLAWS MAY DELAY OR PREVENT
TRANSACTIONS THAT WOULD BENEFIT STOCKHOLDERS.

Our 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,
authorize the Board of Directors to set the terms of Preferred Stock, and
restrict our ability to engage in transactions with 15% stockholders.

Because of these provisions, persons considering unsolicited tender offers
or other unilateral takeover proposals may be more likely to negotiate with our
board of directors rather than pursue non-negotiated takeover attempts. As a
result, these provisions may make it more difficult for our stockholders to
benefit from transactions that are opposed by an incumbent board of directors.

CERTAIN DEFINITIONS

The definitions set forth below shall apply to the indicated terms as used
in this Form 10-K. 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 natural gas interest in a
property, refers to the time period after which the costs to drill and equip a
well have been recovered.

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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 and natural 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 natural 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
natural 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 the related oil and natural gas operating expenses and taxes.

Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural 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 and/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 us pursuant to generally
accepted accounting principles in the United States, including all costs
involved in acquiring acreage, geological and geophysical work and the cost of
drilling and completing wells, excluding those costs attributable to unproved
property.

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.

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,
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 although there have been periods in which they have been lower
or substantially lower.

MMcf. One million cubic feet.

22

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.

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

NGL's. Natural gas liquids measured in barrels.

NRI or Net Revenue Interests. The share of production after satisfaction
of all royalty, overriding royalty, oil payments and other nonoperating
interests.

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.

Plant Products. Liquids generated by a plant facility and include propane,
iso-butane, normal butane, pentane and ethane.

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 depletion, depreciation, 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 exceeds 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.

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 natural 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 natural gas production free of costs of
production.

23

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 or WI. 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.

ITEM 3. LEGAL PROCEEDINGS

From time to time we are a party to various legal proceedings arising in
the ordinary course of business. While the outcome of lawsuits cannot be
predicted with certainty, we are not currently a party to any proceeding that we
believe, if determined in a manner adverse to us, could have a potential
material adverse effect on our financial condition, results of operations or
cash flows.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Our stockholders voted on the following matters at the Special Meeting of
Shareholders on December 4, 2003:

EXECUTIVE OFFICERS OF THE REGISTRANT

Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General
Instruction G (3) to Form 10-K the following information is included in Part I
of this Form 10-K.

John W. Elias has served as the Chief Executive Officer and Chairman of the
Board of the Company since November 1998. From April 1993 to September 30, 1998,
he served in various senior management positions, including Executive Vice
President, of Seagull Energy Corporation, a company engaged in oil and natural
gas exploration, development and production and pipeline marketing. Prior to
April 1993, Mr. Elias served in various positions for more than 30 years,
including senior management positions with Amoco Corporation, a major integrated
oil and gas company. Mr. Elias has more than 40 years of experience in the oil
and natural gas exploration and production business. He is 63 years old.

Michael G. Long has served as Senior Vice President and Chief Financial
Officer of the Company since December 1996. Mr. Long served as Vice
President -- Finance of W&T Offshore, Inc., an oil and natural 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.

24

Mr. Long received a B.A. in Political Science and a M.S. in Economics from the
University of Illinois. Mr. Long is 51 years old.

John O. Tugwell has served as Senior Vice President Production since
December 2001 and prior to that served as Vice President of Production for the
Company since March 1997. He served as Senior Petroleum Engineer of the
Company's predecessor corporation 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. Mr. Tugwell is 40 years
old.

SIGNIFICANT EMPLOYEES

Mark J. Gabrisch has served as the Vice President of Land for the Company
since March 1997. From November 1994 to March 1997, he served in a similar
capacity with the Company's predecessor corporation. From 1985 to October 1994,
he was a landman, most recently a Senior Landman, for Shell Oil Company. Mr.
Gabrisch holds a B.S. in Petroleum Land Management from the University of
Houston. Mr. Gabrisch is 43 years old.

John O. Hastings, Jr. has served as the Vice President of Exploration for
the Company since March 1997 and prior thereto served in a similar capacity with
the Company's predecessor corporation 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 a M.S. in Geology from Texas A&M University. He is 44 years
old.

Kirsten A. Hink has served as Vice President & Controller of the Company
since October 1, 2003 and as Controller of the Company since December 31, 2000.
Prior to that time she served as Assistant Controller from June 2000 to December
2000. Before joining Edge, she served as Controller of Benz Energy Inc., an oil
and gas exploration company, from June 1998 to June 2000. Mrs. Hink received a
B.S. in Accounting from Trinity University. Mrs. Hink is a Certified Public
Accountant in the State of Texas. She is 37 years old.

C.W. MacLeod has served as the Vice President Business Development and
Planning for the Company since January 2002. From November 1999 to December
2001, he was Vice President -- Investment Banking with Raymond James and
Associates, Inc. From February 1990 to October 1999, Mr. MacLeod was a principal
with Kirkpatrick Energy Associates, Inc., whose principal business was merger
and acquisition services, capital arrangement and analytical services for the
oil and gas producing industry. Mr. MacLeod was responsible for originating
corporate finance and research products for energy clients. His previous
experience includes positions as an independent petroleum geologist, a manager
of exploration and production for an independent oil and gas producer and
geologic positions with Ladd Petroleum Corporation and Resource Sciences
Corporation. Mr. MacLeod graduated from Eastern Michigan University with a B.S.
in Geology and earned his M.B.A. from the University of Tulsa. Mr. MacLeod is a
registered professional geologist in the state of Wyoming. He is 53 years old.

Robert C. Thomas has served as Vice President, General Counsel and
Corporate Secretary since March 1997. From February 1991 to March 1997, he
served in similar capacities for the Company's corporate predecessor. From 1988
to January 1991, he was associate and acting general counsel for Mesa Limited
Partnership in Amarillo, Texas. Mr. Thomas holds a B.S. degree in Finance and a
J.D. degree in Law from the University of Texas at Austin. He is 50 years old.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

MARKET PRICE OF AND DIVIDENDS ON COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.

As of March 12, 2004, we estimate there were approximately 6,525 beneficial
holders of our Common Stock. Our Common Stock is listed on the NASDAQ National
Market ("NASDAQ") and traded under the

25

symbol "EPEX". As of March 12, 2004, we had 12,831,385 shares outstanding and
our closing price on NASDAQ was $13.30 per share. The following table sets
forth, for the periods indicated, the high and low closing sales prices for our
Common Stock as listed on NASDAQ.

We have never paid a dividend, cash or otherwise, and do not intend to in
the foreseeable future. In addition, our current credit facility contains
restrictions and limitations on paying cash dividends on our Common Stock. The
payment of future dividends, if any, will be determined by our Board of
Directors in light of conditions then existing, including our earnings,
financial condition, capital requirements, restrictions in financing agreements,
business conditions and other factors. See ITEMS 1 AND 2. "BUSINESS AND
PROPERTIES -- RISK FACTORS -- We do not intend to pay dividends and our ability
to pay dividends is restricted."

RECENT SALES OF UNREGISTERED SECURITIES

On November 14, 2003, we issued 204,300 shares of our Common Stock in
connection with the exercise of warrants, which had originally been granted in
May of 1999 to The Private Investment Fund. The aggregate purchase price for the
shares of Common Stock issued to The Private Investment Fund was $1,093,005. On
November 17, 2003, we issued 5,700 shares of our Common Stock in connection with
the exercise of warrants, which had originally been granted in May of 1999 to
Mark G. Egan. The aggregate purchase price for the shares of Common Stock issued
to Mr. Egan was $30,495. On December 17, 2003, we issued 68,448 shares, 18,000
shares and 6,200 shares of our Common Stock in connection with the exercise of
warrants which had originally been granted in May of 1999 to each of Special
Situations Private Equity Fund, L.P., Special Situations Fund III, L.P. and
Special Situations Cayman Fund, L.P., respectively. The aggregate purchase price
for the shares of Common Stock issued to each of Special Situations Private
Equity Fund, L.P., Special Situations Fund III, L.P. and Special Situations
Cayman Fund, L.P., was $366,197, $96,300 and $33,170, respectively. On December
19, 2003, we issued 54,414 shares and 17,938 shares of our common stock in
connection with the exercise of warrants which had originally been granted in
May of 1999 to each of Special Situations Fund III, L.P. and Special Situations
Cayman Fund, L.P., respectively. The aggregate purchase price for the shares of
common stock issued to each of Special Situations Fund III, L.P. and Special
Situations Cayman Fund, L.P. was $291,115 and $95,968, respectively. The sale of
the shares of Common Stock pursuant to the exercise of the related warrants to
each of The Private Investment Fund, Mr. Egan, Special Situations Private Equity
Fund, L.P., Special Situations Fund III, L.P. and Special Situations Cayman
Fund, L.P., was exempt from the registration requirements of the Securities Act
of 1933, as amended, by virtue of section 4(2) thereof as a transaction not
involving any public offering. The Company has previously filed a registration
statement with the SEC registering the resale of the Common Stock described
above under the Securities Act of 1933 as amended.

26

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth selected financial data regarding the
Company as of and for each of the periods indicated. The following data should
be read in conjunction with ITEM 7. "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and our financial statements and
notes thereto included in ITEM 8.:

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

(1) As discussed in Note 2 to our consolidated financial statements, effective
January 1, 2001, we changed our method of accounting for derivative
instruments.

(2) As discussed in Note 2 to our consolidated financial statements, effective
January 1, 2003 we changed our method of accounting for asset retirement
obligations.

(3) Deferred compensation expense includes the amortization of compensation
costs related to restricted stock grants and the non-cash charge or credit
related to requirements under FASB Interpretation No. ("FIN") 44,
"Accounting for Certain Transactions involving Stock Compensation." At
December 31, 2000, a charge was required under FIN 44 because the daily
average market price of our stock exceeded the strike price of certain
options at that date. At December 31, 2001, our daily average market price
was below the strike price of these options and as a result, a credit was
required to reduce compensation expense except as it related to repriced
options exercised in 2001. During 2002, certain options and restricted stock
were allowed to vest earlier than the original vesting date as part of a
termination agreement. A charge under FIN 44 was required related to these
transactions. At December 31, 2003, a charge of $1.2 million was required
under FIN 44 because the daily average market price of our stock exceeded
the strike price of these options at that date.

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

The following is a review of our financial position and results of
operations for the periods indicated. Our Consolidated Financial Statements and
Supplementary Information and the related notes thereto contain detailed
information that should be referred to in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations.

GENERAL OVERVIEW

Edge Petroleum Corporation is a Houston-based independent energy company
that focuses its exploration, production and marketing activities in selected
onshore basins of the United States.

We were organized as a Delaware corporation in August 1996 in connection
with our initial public offering (the "Offering") and the related combination of
certain entities that held interests in the Edge Joint Venture II (the "Joint
Venture") and certain other oil and natural gas properties, herein referred to
as the "Combination". In a series of combination transactions, we issued an
aggregate of 4,701,361 shares of common stock and received in exchange 100% of
the ownership interests in the Joint Venture and certain other oil and natural
gas properties. In March 1997, and contemporaneously with the Combination, we
completed the Offering of 2,760,000 shares of our common stock generating
proceeds of approximately $40 million, net of expenses. We undertook a top-level
management change late in 1998 and began a shift in strategy from pure
exploration which focused more on prospect generation to our current strategy
which focuses on a balanced program of exploration, exploitation and development
and acquisition of oil and gas properties.

In December 2003, we acquired all of the outstanding stock of Miller
Exploration Company ("Miller"). The transaction was treated as a tax-free
reorganization and accounted for as a purchase business combination. In the
merger, we issued approximately 2.6 million shares of Edge common stock using a
ratio of

28

1.22342 Edge shares for each share of Miller common stock outstanding. Miller
continues to conduct operating activities as a wholly owned subsidiary of Edge.

Because the merger was accounted for as a purchase business combination,
the financial and operating results presented in this report on Form 10-K
include Miller only for the period subsequent to the merger on December 4, 2003.

INDUSTRY AND ECONOMIC FACTORS

In managing our business, we must deal with many factors inherent in our
industry. First and foremost is the fluctuation of oil and gas prices.
Historically, oil and gas markets have been cyclical and volatile, with future
price movements which are difficult to predict. While our revenues are a
function of both production and prices, it is wide swings in prices that have
most often had the greatest impact on our results of operations.

Our operations entail significant complexities. Advanced technologies
requiring highly trained personnel are utilized in both exploration and
production. Even when the technology is properly used, we may still not know
conclusively if hydrocarbons will be present or the rate at which they will be
produced. Exploration is a high-risk activity, often times resulting in no
commercially productive reservoirs being discovered. Moreover, costs associated
with operating within our industry are substantial.

The oil and gas industry is highly competitive. We compete with major and
diversified energy companies, independent oil and gas businesses and individual
operators. In addition, the industry as a whole competes with other businesses
that supply energy to industrial and commercial end users.

Extensive Federal, state and local regulation of the industry significantly
affects our operations. In particular, our activities are subject to stringent
environmental regulations. These regulations have increased the costs of
planning, designing, drilling, installing, operating and abandoning oil and gas
wells and related facilities. These regulations may become more demanding in the
future.

APPROACH TO THE BUSINESS

Profitable growth of our business will largely depend upon our ability to
successfully find and develop new proved reserves in a cost effective manner. In
order to achieve an overall acceptable rate of growth, we maintain a blended
portfolio of low, moderate and higher risk exploration and development projects.
We also attempt to make selected acquisitions of oil and gas properties to
augment our growth. We believe that this approach should allow for consistent
increases in our oil and gas reserves, while minimizing the chance of failure.
To further mitigate risk, we have chosen to seek geologic and geographic
diversification by operating in multiple basins. We periodically hedge our
exposure to volatile oil and gas prices on a portion of our production to reduce
price risk.

Implementation of our business approach relies on our ability to fund
ongoing exploration and development projects with cash flow provided by
operating activities and external sources of capital. In late 2003, we announced
plans for record capital expenditures of approximately $28 million for 2004 all
of which we expect to fund from internally generated cash flows from operating
activities.

In 2003, Edge reported a 30% increase in proved reserves, a 16% increase in
annual production volumes and a 285% reserve replacement ratio. Production in
the fourth quarter was 19% higher than in the previous quarter and we exited
2003 with a record daily production rate. A strong financial position as
represented by a debt to total capital ratio of 20.4%, available unused
borrowing capacity and increasing cash flow from our growing production volumes
as a result of three separate acquisitions in the second half of 2003 will help
lay the ground work for our activities in 2004. Operationally and financially,
we believe Edge is well positioned to continue the execution of our business
strategies during 2004.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

The preparation of financial statements in conformity with generally
accepted accounting principles in the United States requires management to make
estimates and assumptions that affect the reported amounts of

29

assets, liabilities, revenues, expenses and disclosure of contingent assets and
liabilities in the accompanying financial statements. Changes in these estimates
could materially affect our financial position, results of operations or cash
flows. Key estimates used by management include revenue and expense accruals,
environmental costs, depreciation and amortization, asset impairment and fair
values of assets acquired. Significant accounting policies that we employ are
presented in the notes to the consolidated financial statements.

REVENUE RECOGNITION

We recognize oil and natural gas revenue from our interests in producing
wells as oil and natural gas is produced and sold from those wells. Oil and
natural gas sold by us is not significantly different from our share of
production.

OIL AND NATURAL GAS PROPERTIES

The accounting for our business is subject to special accounting rules that
are unique to the oil and gas industry. There are two allowable methods of
accounting for oil and gas business activities: the successful-efforts method
and the full-cost method. There are several significant differences between
these methods. Under the successful-efforts method, costs such as geological and
geophysical ("G&G"), exploratory dry holes and delay rentals are expensed as
incurred whereas under the full-cost method these types of charges would be
capitalized to their respective full-cost pool. In the measurement of impairment
of oil and gas properties, the successful-efforts method of accounting follows
the guidance provided in Statement of Financial Accounting Standards ("SFAS")
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," where
the first measurement for impairment is to compare the net book value of the
related asset to its undiscounted future cash flows using commodity prices
consistent with management expectations. Under the full-cost method to determine
impairment the net book value ("full cost pool") is compared to the future net
cash flows discounted at 10% using commodity prices in effect at the end of the
reporting period and derivatives accounted for as cash flow hedges.

We have elected to use the full-cost method to account for our oil and gas
activities. Under this method, all costs associated with acquisition,
exploration and development of oil and gas reserves, including salaries,
benefits and other internal costs directly attributable to these activities are
capitalized within a cost center. Our oil and natural gas properties are located
within the United States of America which constitutes one cost center. Although
some of these costs may ultimately result in no additional reserves, we expect
the benefits of successful wells to more than offset the costs of any
unsuccessful ones. As a result, we believe that the full-cost method of
accounting better reflects the true economics of exploring for and developing
oil and gas reserves. Our financial position and results of operations would
have been significantly different had we used the successful-efforts method of
accounting for our oil and gas investments.

Oil and natural gas properties are amortized using the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the prospects
can be determined or until impairment occurs. Unproved properties are evaluated
periodically for impairment on a property-by-property basis. If the results of
an assessment indicated that an unproved property is impaired, the amount of
impairment is added to the proved oil and natural gas property costs to be
amortized. The amortizable base includes estimated future development costs and
dismantlement, restoration and abandonment costs, net of estimated salvage
value.

In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations," which requires the use of the purchase method
of accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review of impairment. The new standard also requires that,
at a minimum, all intangible assets be aggregated and presented as a separate
line item in the balance sheet.

30

A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and 142 to companies in the extractive industries,
including oil and gas companies. This issue is currently on the Emerging Issues
Task Force ("EITF") agenda as Issue 03-S, "Applicability of FASB Statement No.
142, Goodwill and Other Intangible Assets, to Oil and Gas Companies." The issue
is whether SFAS No. 141 and 142 require registrants to classify the costs of
acquiring contractual mineral or drilling rights associated with extracting oil
and gas as intangible assets on the balance sheet, apart from other capitalized
oil and gas property costs, and provide specific footnote disclosures.
Historically, we have included the costs of mineral rights associated with
extracting oil and gas as a component of oil and gas properties. If it is
ultimately determined that SFAS No. 141 requires oil and gas companies to
classify costs of mineral rights associated with extracting oil and gas as a
separate intangible assets line item on the balance sheet, we would be required
to reclassify approximately $22.8 million and $8.8 million at December 31, 2003
and 2002, respectively, out of oil and gas properties and into a separate
intangible assets line item. These costs include those to acquire contract based
drilling and mineral use rights such as delay rentals, lease bonuses,
commissions and brokerage fees, and other leasehold costs. Our cash flows and
results of operations would not be affected since such intangible assets would
continue to be depleted and assessed for impairment in accordance with full cost
accounting rules, as allowed by SFAS No. 142. Further, we do not believe the
classification of the costs of mineral rights associated with extracting oil and
gas as intangible assets would have any impact on our compliance with covenants
under our debt agreements.

The capitalized costs of oil and natural gas properties are subject to a
"ceiling test," whereby to the extent that such capitalized costs subject to
amortization in the full cost pool (net of depletion, depreciation 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
natural gas reserves using hedge adjusted period end prices, such excess costs
are charged to operations. Once incurred, an impairment of oil and natural gas
properties is not reversible at a later date. Impairment of oil and natural gas
properties is assessed on a quarterly basis in conjunction with our quarterly
filings with the Securities and Exchange Commission. No adjustment related to
the ceiling test was required during the years ended December 31, 2003, 2002, or
2001.

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.

ASSET RETIREMENT OBLIGATIONS

We have significant obligations to remove tangible equipment and restore
land at the end of oil and gas production operations. Our removal and
restoration obligations are primarily associated with plugging and abandoning
wells. Under the full-cost method of accounting, the fair value of the
abandonment obligations, net of salvage value, are currently included as a
component of our depletion base and expensed over the production life of the oil
and gas properties. Estimating the future asset removal costs is difficult and
requires management to make estimates and judgments because most of the removal
obligations are many years in the future and contracts and regulations often
have vague descriptions of what constitutes removal. Asset removal technologies
and costs are constantly changing, as are regulatory, political, environmental,
safety and public relations considerations.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." We adopted this statement effective January 1, 2003, as
discussed in Notes 2 and 7 to our consolidated financial statements. SFAS No.
143 significantly changed the method of accruing for costs an entity is legally
obligated to incur related to the retirement of fixed assets ("asset retirement
obligations" or "ARO"). Primarily, the new statement requires us to record a
separate liability upon the incurrence of an obligation for the fair value of
our asset retirement obligations, with an offsetting increase to the related oil
and gas properties on the balance sheet.

Inherent in the fair value calculation are numerous assumptions and
judgments including the ultimate settlement amounts, inflation factors, credit
adjusted discount rates, timing of settlement, and changes in the legal,
regulatory, environmental and political environments. To the extent future
revisions to these assump-

31

tions impact the fair value of the existing ARO liability, a corresponding
adjustment is made to the oil and gas property balance. In addition, increases
in the discounted ARO liability resulting from the passage of time will be
reflected as accretion expense in the consolidated statement of operations.

The adoption of SFAS No. 143 required a cumulative adjustment to reflect
the impact of implementing the statement had the rule been in effect since
inception, which resulted in a loss of $357,800, which was recorded as a
cumulative effect of a change in accounting principle on January 1, 2003. Since
we added these costs for asset retirement obligations using a cumulative effect
approach there are no comparable costs shown in the costs incurred disclosures
for prior periods presented, therefore finding cost calculations are not
directly comparable between periods presented.

Going forward, our depletion expense will be reduced since we will deplete
a discounted amount of asset retirement costs rather than the undiscounted value
depleted in previous years. The lower depletion expense under SFAS No. 143 is
offset, however, by accretion expense.

OIL AND NATURAL GAS RESERVES

Our estimate of proved reserves is based on the quantities of oil and gas
which geological and engineering data demonstrate, with reasonable certainty, to
be recoverable in the future years from known reservoirs under existing economic
and operating conditions. The accuracy of any reserve estimate is a function of
the quality of available data, engineering and geological interpretation, and
judgment. For example, we must estimate the amount and timing of future
operating costs, severance taxes, development costs, and workover costs, all of
which may in fact vary considerably from actual results. In addition, as prices
and cost levels change from year to year, the estimate of proved reserves also
changes. Any significant variance in these assumptions could materially affect
the estimated quantity and value of our reserves.

Despite the inherent imprecision in these engineering estimates, our
reserves are used throughout our financial statements. For example, since we use
the unit-of-production method to amortize our oil and gas properties, the
quantity of reserves could significantly impact our depreciation, depletion and
amortization ("DD&A") expense and accretion expense. Our oil and gas properties
are also subject to a "ceiling" limitation based in part on the quantity of our
proved reserves. Finally, these reserves are the basis for our supplemental oil
and gas disclosures.

We engage an independent petroleum engineering firm to prepare our
estimates of proved hydrocarbon liquid and gas reserves.

INCOME TAXES

We record deferred tax assets and liabilities to account for the expected
future tax consequences of events that have been recognized in our financial
statements and our tax returns. We routinely assess the realizability of our
deferred tax assets. If we conclude that it is more likely than not that some
portion or all of the deferred tax assets will not be realized under accounting
standards, the tax asset would be reduced by a valuation allowance. We consider
future taxable income in making such assessments. Numerous judgments and
assumptions are inherent in the determination of future taxable income,
including factors such as future operating conditions (particularly as related
to prevailing oil and gas prices).

DERIVATIVES AND HEDGING ACTIVITIES

Our revenue, profitability and future rate of growth and ability to borrow
funds or obtain additional capital, and the carrying value of our properties,
are substantially dependent upon prevailing prices for oil and natural gas.
These prices are dependent upon numerous factors beyond our control, such as
economic, political and regulatory developments and competition from other
sources of energy. A substantial or extended decline in oil and natural gas
prices could have a material adverse effect on our financial condition, results
of operations and access to capital, as well as the quantities of oil and
natural gas reserves that we may economically produce.

32

Due to the interaction of these factors on the stability of oil and natural
gas prices, we may enter into, from time to time, price risk management
transactions (e.g., swaps, collars and floors) for a portion of our oil and
natural gas production to achieve a more predictable cash flow, as well as to
reduce exposure from price fluctuations. While the use of these arrangements
limits our ability to benefit from increases in the price of oil and natural
gas, it also reduces our potential exposure to adverse price movements. Our
hedging arrangements, to the extent we enter into any, apply to only a portion
of our production and provide only partial price protection against declines in
oil and natural gas prices and limits our potential gains from future increases
in prices. Our management sets all of our hedging policies, including volumes,
types of instruments and counter parties, on a quarterly basis. These policies
are implemented by management through the execution of trades by the Chief
Financial Officer after consultation and concurrence by the President and
Chairman of the Board. Our Board of Directors reviews all hedging policies and
trades. We account for these transactions as hedging activities and,
accordingly, realized gains and losses are included in oil and natural gas
revenue during the period the hedged transactions occur. See ITEMS 1 AND 2.
"BUSINESS AND PROPERTIES -- MARKETING."

We formally assess, both at the hedge's inception and on an ongoing basis,
whether the derivatives that are used in hedging transactions are expected to be
highly effective in offsetting changes in cash flows of the hedged transactions.
In the event it is determined that the use of a particular derivative may not be
or has ceased to be effective in pursuing a hedging strategy, hedge accounting
is discontinued prospectively.

STOCK-BASED COMPENSATION

We account for stock compensation plans under the intrinsic value method of
Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued
to Employees." No compensation expense is recognized for stock options that had
an exercise price equal to or greater than the market value of their underlying
common stock on the date of grant. As allowed by SFAS No. 123, "Accounting for
Stock Based Compensation," we have continued to apply APB Opinion No. 25 for
purposes of determining net income. In December 2002, the FASB issued SFAS No.
148, "Accounting for Stock Based Compensation -- Transition and Disclosure -- an
amendment of FASB Statement No. 123" to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. We elected not to change to the fair
value method. Additionally, the statement amended the disclosure requirements of
SFAS No. 123 to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based compensation
and the effect of the method used on reported results.

We are also subject to reporting requirements of FASB Interpretation No.
("FIN") 44, "Accounting for Certain Transactions involving Stock Compensation"
that requires a non-cash charge to deferred compensation expense if the market
price of our common stock at the end of a reporting period is greater than the
exercise price of certain stock options. After the first such adjustment is
made, each subsequent period is adjusted upward or downward to the extent that
the market price exceeds the exercise price of the options. The charge is
related to non-qualified stock options granted to employees and directors in
prior years in conjunction with the repricing of those options.

RESULTS OF OPERATIONS

This section includes discussion of our 2003, 2002 and 2001 results of
operations. We are an independent energy company engaged in the exploration,
development, acquisition and production of oil and natural gas. Our resources
and assets are managed and our results reported as one operating segment. We
conduct our operations primarily along the onshore United States, Gulf Coast,
with our primary emphasis in South Texas, Louisiana and SE New Mexico.

33

YEAR ENDED DECEMBER 31, 2003 COMPARED TO THE YEAR ENDED DECEMBER 31, 2002

Revenue and Production

Oil and natural gas revenue increased 62% from $20.9 million in 2002 to
$33.9 million in 2003. For 2003, natural gas production comprised 78% of total
production and contributed 82% of total revenue, oil and condensate production
comprised 9% of total production and contributed 11% of total revenue, and
natural gas liquid (NGL) production comprised 13% of total production and
contributed 7% of total revenue. For 2002, natural gas production comprised 76%
of total production and 79% of total revenue, oil and condensate production
comprised 10% of total production and contributed 13% of total revenue, and NGL
production comprised 14% of total production and contributed 8% of total
revenue.

The following table summarizes production volumes, average sales prices and
operating revenue for our oil and natural gas operations for the years ended
December 31, 2003 and 2002.

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

(1) Results for 2002 were favorably impacted by the recognition in the second
quarter of 2002 of revenue associated with underaccruals in prior periods.
This adjustment resulted in 142 MMcfe of additional production and $577,200
of additional revenue.

(2) Includes the effect of hedging.

Our revenue is sensitive to changes in prices received for our products. A
substantial portion of our production is sold at prevailing market prices, which
fluctuate in response to many factors that are outside of our control.
Imbalances in the supply and demand for oil and natural gas can have a dramatic
effect on the prices we receive for our production. Political instability,
availability of alternative fuels, the economy, weather and other factors
outside of our control could impact supply and demand.

Natural gas revenue increased 69% from $16.5 million for the year ended
December 31, 2002 to $27.9 million for 2003 due to significantly higher average
realized prices coupled with an increase in production, partially offset by a
higher realized hedge loss. Including the effect of our hedges, our average
natural gas sales price for production in 2003 was $4.43 per Mcf compared to
$3.14 per Mcf for 2002. Excluding the effect of hedges, the average natural gas
sales price for production in 2003 was $5.14 per Mcf compared to $3.20 per Mcf
for 2002. This increase in average price received resulted in increased revenue
of

34

approximately $12.2 million (based on 2003 production). Included within natural
gas revenue for the year ended December 31, 2003 and 2002 was $4.5 million and
$0.3 million, respectively, representing losses from hedging activity. These
losses decreased the effective natural gas sales price by $0.71 per Mcf and
$0.06 per Mcf, for the years ended December 31, 2003 and 2002, respectively. For
the year ended December 31, 2003, average natural gas production increased 19%
from 14.4 Mcf/d in 2002 to 17.2 Mcf/d in 2003 due to production from new wells
drilled and acquired, primarily our O'Connor Ranch East, Gato Creek and
Encinitas properties, partially offset by natural declines at our Austin Field
and O'Connor Ranch properties. This increase in production compared to the prior
year resulted in an increase in revenue of approximately $3.3 million (based on
2002 comparable period prices).

Revenue from the sale of oil and condensate totaled $3.9 million for the
year ended December 31, 2003, an increase of 41% from the prior year total of
$2.7 million. The average realized price for oil and condensate for the year
ended December 31, 2003 was $31.48 per barrel compared to $22.88 per barrel in
2002. Higher average prices for the year 2003 resulted in an increase in revenue
of approximately $1.1 million (based on 2003 production). Production volumes for
oil and condensate increased 3% to 336 Bbls/d for the year ended December 31,
2003 compared to 327 Bbls/d for the same prior year period. The increase in oil
and condensate production resulted in an increase in revenue of approximately
$70,100 (based on 2002 comparable period average prices).

Revenue from the sale of NGLs totaled $2.2 million for the year ended
December 31, 2003, an increase of 32% from the 2002 total of $1.7 million.
Higher average realized prices for the year ended December 31, 2003 resulted in
an increase in revenue of $365,500 (based on 2003 production). The average
realized price for NGLs for the year ended December 31, 2003 was $12.37 per
barrel compared to $10.31 per barrel for the same period in 2002. Production
volumes for NGLs increased 10%, from 442 Bbls/d for the year ended December 31,
2002 to 487 Bbls/d for the year ended December 31, 2003 due primarily to new
production from the Thibodeaux well. The increase in NGL production increased
revenue by $171,100 (based on 2002 comparable period average prices).

Costs and Operating Expenses

The table below presents a detail of our 2003 and 2002 expenses:

35

Lease operating expenses for the year ended December 31, 2003 totaled $2.7
million compared to $2.2 million in the same period of 2002, an increase of 21%.
Current year results were impacted by the drilling of 36 wells, an increase of
177% over 2002, increased production of 16% over 2002 and acquisitions of
properties from third parties. Operating expenses averaged $0.33 per Mcfe for
the year ended December 31, 2003 compared to $0.32 per Mcfe for the prior year
period.

Severance and ad valorem taxes for the year ended December 31, 2003
increased from $1.6 million in 2002, to $2.4 million in 2003. Severance tax
expense for 2003 was 67% higher than the prior year period as a result of higher
revenue. For the year ended December 31, 2003, severance tax expense was
approximately 5.3% of total revenue compared to 5.7% of total revenue for the
comparable 2002 period. Ad valorem costs increased 3% from $419,400 in 2002 to
$433,300 in 2003. On an equivalent basis, severance and ad valorem taxes
averaged $0.30 per Mcfe and $0.23 per Mcfe for the years ended December 31, 2003
and 2002, respectively.

DD&A and accretion for the year ended December 31, 2003 totaled $13.6
million compared to $10.4 million for the year ended December 31, 2002. Full
cost depletion on our oil and natural gas properties totaled $12.9 million for
2003 compared to $9.7 million in 2002. Depletion expense on a unit of production
basis for the year ended December 31, 2003 was $1.59 per Mcfe, 14% higher than
the 2002 rate of $1.39 per Mcfe. The higher depletion rate per Mcfe resulted in
an increase in depletion expense of $1.6 million. For the year ended December
31, 2003, higher oil and natural gas production compared to the prior year
period resulted in an increase in depletion expense of $1.6 million. The
increase in the depletion rate was primarily due to a higher amortizable base in
2003 compared to the prior year without a corresponding increase in reserves.
Depreciation of furniture and fixtures totaled $603,698, a decrease of 17%
compared to the prior year total of $729,523. We adopted SFAS No. 143, effective
January 1, 2003, and as a result, we recorded accretion expense associated with
our asset retirement obligation of $66,625 for the year ended December 31, 2003
compared to zero in 2002 due to this change in accounting for asset retirement
obligations (see Note 2 to our consolidated financial statements).

Total general and administrative ("G&A") for the year ended December 31,
2003 was $7.1 million, an increase of 36% compared to the prior year total of
$5.2 million. Total G&A costs include deferred compensation related to repriced
options, deferred compensation related to restricted stock grants and other G&A
costs.

Deferred compensation expense consists of costs reported in accordance with
FIN 44 and amortization related to restricted stock awards. A FIN 44 charge of
$1.2 million was incurred for the year ended December 31, 2003 compared to a
charge of $3,385 in the comparable prior year period. FIN 44 requires, among
other things, a non-cash charge to compensation expense if the price of our
common stock on the last trading day of a reporting period is greater than the
exercise price of certain options. FIN 44 could also result in a credit to
compensation expense to the extent that the trading price declines from the
trading price as of the end of the prior period, but not below the exercise
price of the options. We adjust deferred compensation expense upward or downward
on a monthly basis based on the trading price at the end of each such period. We
are required to report under this rule as a result of non-qualified stock
options granted to employees and directors in prior years and re-priced in May
of 1999, as well as certain newly issued options in conjunction with the
repricing.

Amortization related to restricted stock awards granted over the past three
years totaled $372,151 and $399,249, respectively, for the years ended December
31, 2003, and 2002.

Other G&A for the year ended December 31, 2003, which does not include the
deferred compensation expenses discussed above, totaled $5.5 million, a 15%
increase from the 2002 total of $4.8 million. The increase in other G&A was
attributable to higher audit and legal fees, higher franchise taxes, office
moving costs and the settlement of a lawsuit related to seismic rights in April
2003 for $70,000. In addition, we incurred costs associated with the Miller
merger of $279,400 (including retention, salaries and benefits, and integration
costs) and implementation costs to integrate our production and land computer
systems with accounting of $88,300. These costs were partially offset by lower
rent and parking and lower reserve engineer fees compared to the prior year
periods. For the years ended December 31, 2003 and 2002, overhead

36

reimbursement fees reduced G&A costs by $120,500 and $208,200, respectively. The
Company capitalized $1.7 million and $1.5 million of general and administrative
costs in 2003 and 2002, respectively. Other G&A on a unit of production basis
for the year ended December 31, 2003 was $0.68 per Mcfe compared to $0.69 per
Mcfe for the comparable 2002 period.

Included in other income (expense) was interest expense of $678,800 for the
year ended December 31, 2003 compared to $227,800 in the same 2002 period.
Interest expense, including facility fees, was $923,300 for 2003 on weighted
average debt of $23.0 million compared to interest expense of $766,700 on
weighted average debt of approximately $15.4 million for 2002. Capitalized
interest for the year ended December 31, 2003 totaled $244,500 compared to
$623,400 in the prior year. At December 31, 2003, our unproved property balance
was $5.0 million compared to $7.9 million at December 31, 2002, resulting in the
lower capitalized interest for 2003. Also included in interest expense for the
year ended December 31, 2002 was $84,500 representing amortization of deferred
loan costs associated with our credit facility.

Interest income totaled $16,500 for the year ended December 31, 2003
compared to $27,000 for the same period in 2002. The decrease in interest income
is due primarily to the overall decrease in rates at which the funds are
invested in overnight money market funds.

An income tax provision was recorded for the year ended December 31, 2003
of $2.7 million. Due to changes in permanent differences, including meals and
entertainment and compensation expense, our effective tax rate changed from
38.7% in 2002 to 36.7% in 2003. As of December 31, 2003, approximately $50.1
million of net operating loss carryforwards have been accumulated or acquired
that begin to expire in 2012. For the year ended December 31, 2002, an income
tax provision of $473,100 was recorded. Currently, we do not anticipate making
federal tax payments in 2004.

Upon adoption of SFAS No. 143 on January 1, 2003, we recorded a cumulative
effect of a change in accounting principal of $357,800 (net of income taxes of
$192,700) and accretion expense, to recognize transition amounts for asset
retirement obligations, asset retirement costs and accumulated depletion and
accretion.

For the year ended December 31, 2003, we had net income of $4.4 million, or
$0.45 basic earnings per share and $0.44 diluted earnings per share, as compared
to net income of $749,700, or $0.08 basic and diluted earnings per share in
2002. Weighted average shares outstanding increased from approximately 9.4
million for the year ended December 31, 2002 to 9.7 million in the comparable
2003 period. The increase was due primarily to options exercised and vesting of
restricted stock during 2003. The impact of the shares issued in the Miller
transaction will not be fully realized until next year since the merger closed
and the shares were issued in December 2003.

YEAR ENDED DECEMBER 31, 2002 COMPARED TO THE YEAR ENDED DECEMBER 31, 2001

Revenue and Production

Oil and natural gas revenue decreased 30% from $29.8 million in 2001 to
$20.9 million in 2002. For 2002, natural gas production comprised 76% of total
production and contributed 79% of total revenue, oil and condensate comprised
10% of total production and contributed 13% of total revenue, and NGL production
comprised 14% of total production and contributed 8% of total revenue. For 2001,
natural gas production comprised 86% of total production and 88% of total
revenue, while oil and condensate production accounted for 10% of total
production and 9% of revenue, and NGL production comprised 4% of total
production and 3% of total revenue.

37

The following table summarizes production volumes, average sales prices and
operating revenue for our oil and natural gas operations for the years ended
December 31, 2002 and 2001.

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

(1) Results for 2002 were favorably impacted by the recognition in the second
quarter of 2002 of revenue associated with underaccruals in prior periods.
This adjustment resulted in 142 MMcfe of additional production and $577,200
of additional revenue.

(2) Includes the effect of hedging.

Natural gas revenue decreased 37% from $26.2 million for the year ended
December 31, 2001 to $16.5 million for 2002. Significantly lower realized prices
coupled with a decline in production for the year were slightly offset by a
lower realized hedge loss. Including the effect of hedges, our average natural
gas sales price for production in 2002 was $3.14 per Mcf compared to $4.23 per
Mcf for 2001. Excluding the effect of hedges, the average natural gas sales
price for production in 2002 was $3.20 per Mcf compared to $4.38 per Mcf for
2001. This decrease in average price received resulted in decreased revenue of
approximately $6.2 million (based on 2002 production). Included within natural
gas revenue for the year ended December 31, 2002 and 2001 was $0.3 million and
$0.9 million, respectively, representing losses from hedging activity. These
losses decreased the effective natural gas sales price by $0.06 per Mcf and
$0.15 per Mcf, for the years ended December 31, 2002 and 2001, respectively. For
the year ended December 31, 2002, natural gas production decreased 15% from 17.0
Mcf/d in 2001 to 14.4 Mcf/d in 2002 due primarily to natural declines in
production at our Austin Field and O'Connor Ranch properties, partially offset
by increased production from new wells drilled in late 2001 and in 2002. This
decrease in production compared to the prior year resulted in a decrease in
revenue of approximately $4.1 million (based on 2001 comparable period prices).

Revenue from the sale of oil and condensate totaled $2.7 million for the
year ended December 31, 2002, a decrease of 1% from the prior year total of $2.8
million. The average realized price for oil and condensate for the year ended
December 31, 2002 was $22.88 per barrel compared to $23.94 per barrel in 2001.
Lower average prices for the year 2002 resulted in a decrease in revenue of
approximately $127,300 (based on 2002 production). Production volumes for oil
and condensate increased 3% to 327 Bbls/d for the year ended December 31, 2002
compared to 317 Bbls/d for the same prior year period. The increase in oil and
condensate production resulted in an increase in revenue of approximately
$91,000 (based on 2001 comparable period average prices).

38

Revenue from the sale of NGLs totaled $1.7 million for the year ended
December 31, 2002, an increase of 105% from the 2001 total of $0.8 million.
Production volumes for NGLs increased 253%, from 125 Bbls/d for the year ended
December 31, 2001 to 442 Bbls/d for the year ended December 31, 2002. The
increase in NGL production increased revenue by $2.1 million (based on 2001
comparable period average prices). This increase in production was largely due
to increased liquids processing stemming from Gato Creek Field (Webb County,
Texas), an acquisition made in late 2001. Lower average realized prices for the
year ended December 31, 2002 resulted in a decrease in revenue of $1.2 million
(based on 2002 production). The average realized price for NGLs for the year
ended December 31, 2002 was $10.31 per barrel compared to $17.74 per barrel for
the same period in 2001.

COSTS AND OPERATING EXPENSES

The table below presents a detail of our 2002 and 2001 expenses:

Lease operating expenses for the year ended December 31, 2002 totaled $2.2
million compared to $2.8 million in the same period of 2001, a decrease of 22%.
Current year results were impacted by lower well control insurance and salt
water disposal costs, partially offset by higher treating costs incurred in 2002
compared to the prior year. Operating expenses averaged $0.32 per Mcfe for the
year ended December 31, 2002 compared to $0.39 per Mcfe for the prior year
period.

Severance and ad valorem taxes for the year ended December 31, 2002
decreased 26% from $2.2 million in 2001, to $1.6 million in 2002. Severance tax
expense for 2002 was 39% lower than the prior year period as a result of lower
revenue as well as severance tax exemption credits on certain properties. For
the year ended December 31, 2002, severance tax expense was approximately 5.7%
of total revenue compared to 6.5% of total revenue for the comparable 2001
period. Ad valorem costs, however, increased from approximately $222,000 in 2001
to over $419,000 in 2002 due primarily to additional costs on the Ibarra and La
Jolla Parr properties as well as the Gato Creek properties which were acquired
at year-end 2001. On an equivalent basis, severance and ad valorem taxes
averaged $0.23 per Mcfe and $0.30 per Mcfe for the years ended December 31, 2002
and 2001, respectively.

DD&A for the year ended December 31, 2002 totaled $10.4 million compared to
$9.4 million for the year ended December 31, 2001. Full cost depletion on our
oil and natural gas properties totaled $9.7 million for

39

2002 compared to $8.7 million in 2001. Depletion expense on a unit of production
basis for the year ended December 31, 2002 was $1.39 per Mcfe, 14% higher than
the 2001 rate of $1.22 per Mcfe. The higher depletion rate per Mcfe resulted in
an increase in depletion expense of $1.2 million. For the year ended December
31, 2002, lower oil and natural gas production compared to the prior year period
resulted in a decrease in depletion expense of $0.2 million. The increase in the
depletion rate was primarily due to a higher amortizable base in 2002 compared
to the prior year.

In December 2001, we recorded costs of $3.5 million related to the
settlement of our litigation with BNP.

Deferred compensation expense consists of costs reported in accordance with
FIN 44, and amortization related to restricted stock awards. A FIN 44 charge of
$3,400 was incurred for the year ended December 31, 2002 compared to a credit of
$(850,300) in the comparable prior year period. Amortization related to
restricted stock awards granted during 2002 and 2001 totaled $399,200 and
$353,400, respectively.

Other G&A for the year ended December 31, 2002, which does not include the
deferred compensation expense discussed above, totaled $4.8 million, a 4%
decrease from the 2001 total of $5.0 million, due primarily to bad debt expense
of $525,000 recorded in 2001. In addition, 2002 salaries and benefits were seven
percent lower than 2001 costs. Offsetting these lower costs were higher
professional service fees (primarily legal costs and audit fees), higher
officers and directors insurance costs and higher franchise taxes for 2002
compared to 2001. For the years ended December 31, 2002 and 2001, overhead
reimbursement fees reduced G&A costs by $208,200 and $137,200, respectively. The
Company capitalized $1.5 million and $1.6 million of general and administrative
costs in 2002 and 2001, respectively. Other G&A on a unit of production basis
for the year ended December 31, 2002 was $0.69 per Mcfe compared to $0.70 per
Mcfe for the comparable 2001 period.

Included in other income (expense) was interest expense of $227,800 for the
year ended December 31, 2002 compared to $214,600 in the same 2001 period.
Interest expense, including facility fees, was $766,700 for 2002 on weighted
average debt of $15.4 million compared to interest expense of $137,600 on
weighted average debt of approximately $0.7 million for the same prior year
period. Capitalized interest for the year ended December 31, 2002 increased to
$623,400 compared to $24,400 in the prior year due primarily to higher interest
costs on higher outstanding debt for the period. Also included in interest
expense for the years ended December 31, 2002 and 2001 was $84,500 and $101,400,
respectively, representing amortization of deferred loan costs associated with a
new credit facility.

Interest income totaled $27,000 for the year ended December 31, 2002
compared to $127,700 for the same period in 2001. The decrease in interest
income is due primarily to the overall decrease in funds invested in overnight
money market funds.

An income tax provision was recorded for the year ended December 31, 2002
of $473,100. As of December 31, 2002, approximately $27.4 million of net
operating loss carryforwards had been accumulated that begin to expire in 2012.
For the year ended December 31, 2001, an income tax benefit of $818,900 was
recorded as a result of reversing a valuation reserve. We did not make federal
tax payments in 2003.

For the year ended December 31, 2002, the Company had net income of $0.7
million, or $0.08 basic earnings per share, as compared to net income of $8.1
million, or $0.87 basic earnings per share, in 2001. Weighted average shares
outstanding increased from approximately 9.3 million for the year ended December
31, 2001 to 9.4 million in the comparable 2002 period. The increase was due
primarily to options exercised and vesting of restricted stock during 2002.

ACQUISITIONS

On August 1, 2003 we closed the acquisition of oil and gas properties in
our core South Texas area for $8.9 million paid in cash. The purchase price was
funded from existing working capital and borrowings under our existing credit
facility. The acquisition consisted of interests averaging between 58% and 100%
in 70 gross (30.40 net) wells covering 10,782 gross (5,236 net) acres. As of
December 31, 2003, the estimated proved reserves associated with the interests
acquired was 7.3 Bcfe. Estimated daily production as of December 31, 2003 was
2.27 MMcfe per day. The reserves and production stream are approximately 82%
natural gas.

40

On November 20, 2003 we closed the acquisition of oil and gas properties in
our core South Texas area for $0.9 million paid in cash. The purchase price was
funded from existing working capital and borrowings under our existing credit
facility. The acquisition consisted of interests averaging between 17.625% and
50.0% in 4 gross (0.735 net) wells covering 861.6 gross (430.8 net) acres. As of
December 31, 2003, the estimated proved reserves associated with the interests
acquired was 0.6 Bcfe. Estimated current daily production is 1.1 MMcfe. The
reserves and production stream are approximately 88% natural gas.

EXPLORATION ALLIANCE

On August 26, 2003, we entered into a new exploration alliance to jointly
explore for oil and natural gas in the Southeast New Mexico portion of the
Permian Basin with two private oil and gas companies. Edge and its co-explorers
agreed to the establishment of an area of mutual interest (the "AMI") covering
all of Eddy and Lea Counties, as well as a portion of southern Chaves County.
Within the AMI, our partners own approximately 47,000 gross (27,000 net) acres
of mineral fee and leasehold, which they have committed to the exploration
alliance.

We will act as operator for the exploration alliance and earn, subject to
fulfillment of certain obligations, an assignment of an undivided 50% working
interest and a 37.5% net revenue interest, proportionately reduced, in all
acreage owned in the AMI. In order to earn the interests in the AMI properties,
we will pay a total fee of $2.7 million, $1.0 million paid at closing and the
balance to be paid in 17 equal monthly installments, and commit to the drilling
of four Grayburg/San Andres and six Atoka/Morrow wells within an 18 month time
period and carry our partners for approximately $4.0 -- $4.5 million in well
costs. All subsequent wells, new leasehold acreage and any other acquisitions
will be done on a pro-rata basis by all parties.

MERGER

On December 4, 2003 we completed our acquisition of Miller Exploration
Company ("Miller"). Miller was an independent oil and gas exploration and
production company with exploration efforts concentrated primarily in the
Mississippi Salt Basin of central Mississippi. We acquired Miller for the
development and exploitation projects in each of Miller's core areas, increased
financial flexibility, and expansion of our core areas.

Under the terms of the merger agreement, each share of issued and
outstanding common stock of Miller was converted into 1.22342 shares of Edge
common stock. We issued approximately 2.6 million shares of Edge common stock to
the shareholders of Miller in exchange for all of the outstanding common stock
of Miller. The merger was treated as a tax-free reorganization and accounted for
as a purchase business combination under generally accepted accounting
principles.

The fair value of assets acquired from Miller totaled $15.7 million and
included $6.4 million of cash. We incurred $1.2 million in costs associated with
the merger resulting in cash acquired in the merger of $5.2 million.

The acquired Miller properties are estimated to contain at least 5.6 Bcfe
of proved reserves at December 31, 2003, of which approximately 60% was natural
gas and 100% was classified as proved developed. We will operate the majority of
the acquired properties. The acreage position was approximately 83,800 gross
(17,200 net) acres with an option to acquire 80,000 gross (68,000 net) acres at
December 31, 2003.

DIVESTITURES

We regularly review our asset base for the purpose of identifying non-core
assets, the disposition of which would increase capital resources available for
other activities and create organizational and operational efficiencies. While
we generally do not dispose of assets solely for the purpose of reducing debt,
such dispositions can have the result of furthering our objective of financial
flexibility through reduced debt levels.

During 2003, 2002 and 2001, our divestitures consisted of the sales of oil
and gas properties for net proceeds of $330,100, $354,300 and $0, respectively.
Our 2003 net proceeds from asset divestitures were

41

primarily derived from the sale of our interest in affiliated entities, Essex I
and II Joint Ventures (see Note 15 to our consolidated financial statements),
and certain oil and gas properties in Texas and Louisiana. Our 2002 divestitures
were primarily derived from the sale of certain interests in oil and gas
properties in Texas, Alabama, Montana, and Louisiana.

LIQUIDITY AND CAPITAL RESOURCES

In March 1997, we completed our initial public offering which provided us
with proceeds of approximately $40 million, net of expenses and on May 6, 1999,
we completed a "Private Offering" of 1,400,000 shares of common stock at a price
of $5.40 per share. We also issued warrants, which were purchased for $0.125 per
warrant, to acquire an additional 420,000 shares of common stock at $5.35 per
share and are exercisable through May 6, 2004. Total proceeds, net of offering
costs, were approximately $7.4 million of which $4.9 million was used to repay
debt under our revolving credit facility in place at the time, with the
remainder being utilized to satisfy working capital requirements and to fund a
portion of our exploration program. Pursuant to the terms of the private
placement, we filed a registration statement with the Commission registering the
resale of the shares of Common Stock and the warrants sold in the private
placement, as well as the resale of any shares of Common Stock issued pursuant
to such warrants. On November 14, 2003, we issued 204,300 shares of our Common
Stock in connection with the exercise of warrants, which resulted in proceeds to
us of $1,093,005. On November 17, 2003, we issued 5,700 shares of our Common
Stock in connection with the exercise of warrants, which resulted in proceeds to
us of $30,495. On December 17, 2003, we issued an additional 92,648 shares of
our Common Stock in connection with the exercise of warrants, which resulted in
additional proceeds to us of $495,667. On December 19, 2003, we issued an
additional 72,352 shares of our common stock in connection with the exercise of
warrants, which resulted in additional proceeds to us of $387,083. As of
December 31, 2003, 45,000 of these warrants were outstanding. On March 2, 2004,
Mr. Elias, our Chairman and Chief Executive Officer exercised the remaining
warrants which resulted in our issuance to him of 45,000 shares of common stock
and net proceeds to us of $240,750.

Our primary ongoing source of capital is the cash flow generated from our
operating activities supplemented by borrowings under our credit facility. Both
of these sources are directly impacted by the amount of our oil and gas
reserves, production volumes and the prices we receive. Reserves and production
volumes are influenced, in part, by the amount of future capital expenditures.
Our primary uses of capital have been and will continue to be funding our
exploration and development projects and acquisitions as well as retirement of
outstanding debt. In turn, capital expenditures are influenced by many factors
including drilling results, oil and gas prices, industry conditions, prices and
availability of goods and services and the extent to which oil and gas
properties are acquired.

Capital Resources

Our primary needs for cash are for exploration, development and acquisition
of oil and gas properties, and the repayment of principal and interest on
outstanding debt. We attempt to fund our exploration and development activities
primarily through internally generated cash flows and budget capital
expenditures based on projected cash flows. We routinely adjust capital
expenditures in response to changes in oil and natural gas prices, drilling and
acquisition costs, and cash flow. We typically have funded acquisitions from
borrowings under our credit facility and cash flow from operations. We have
historically utilized net cash provided by operating activities, debt and equity
as capital resources to obtain necessary funding for all of our cash needs.

We had cash and cash equivalents at December 31, 2003 of $1.3 million
consisting primarily of short-term money market investments, as compared to $2.6
million at December 31, 2002. Working capital was $0.9 million as of December
31, 2003, as compared to $3.3 million at December 31, 2002.

42

Net Cash Provided By Operating Activities

Cash flows provided by operating activities were $23.9 million, $10.5
million and $22.2 million, for the years ended December 31, 2003, 2002, and
2001, respectively. The significant increase in cash flows provided by operating
activities for the year ended December 31, 2003 compared to 2002 was primarily
due to higher oil and gas revenue partially offset by higher operating expense.
Oil and gas revenue increased with a 39% increase in the average price received
for our production and a 16% increase in production. The decrease in cash flows
provided by operating activities in 2002 compared to 2001 was due primarily to
lower net income in 2002, a larger decrease in accrued liabilities for 2002 and
a lower decrease in accounts receivable for 2002 as compared to 2001.

Net cash generated from operating activities is a function of commodity
prices, which are inherently volatile and unpredictable, production and capital
spending. Our business, as with other extractive industries, is a depleting one
in which each gas equivalent produced must be replaced or we, and a critical
source of our future liquidity, will shrink. Based on the year-end 2003 reserve
life index, our production decline rate is approximately 13% per year. This
projection assumes the capital investment, prices, costs and taxes reflected in
our standardized measure in Note 18 to our consolidated financial statements.
Less predictable than production declines from our proved reserves is the impact
of constantly changing oil and natural gas prices on cash flows and, therefore
capital budgets.

For these reasons, we only forecast, for internal use by management, an
annual cash flow. These annual forecasts are revised monthly and capital budgets
are reviewed by management and adjusted as warranted by market conditions.
Longer-term cash flow and capital spending projections are neither developed nor
used by management to operate our business.

In the event such capital resources are not available to us, our drilling
and other activities may be curtailed. See ITEMS 1 AND 2. "BUSINESS AND
PROPERTIES -- RISK FACTORS -- Our operations have significant capital
requirements."

Net Cash Used In Investing Activities

We reinvest a substantial portion of our cash flows in our drilling,
acquisition, land and geophysical activities. As a result, we used $28.1 million
in investing activities during 2003. Capital expenditures of $33.6 million for
the year ended December 31, 2003, were partially offset by $5.2 million of cash
received in the Miller merger net of merger costs incurred (see discussion
above) and $0.3 million in proceeds from the sale of oil and gas properties
during 2003. Capital expenditures of $18.3 million were attributable to the
drilling of 36 gross wells, 28 of which were successful. Acquisition costs,
excluding Miller, totaled $12.3 million for the year ended December 31, 2003,
and an additional $0.8 million in expenditures was attributable to land
holdings, including seismic data and other geological and geophysical
expenditures. The remaining capital expenditures were associated with computer
hardware and office equipment.

During the year ended December 31, 2002, we used $19.3 million in investing
activities. Capital expenditures of $19.6 million for the year ended December
31, 2002, were partially offset by $0.4 million in proceeds from the sale of oil
and gas properties during 2002. Capital expenditures of $12.7 million were
attributable to the drilling of 13 gross wells, 11 of which were successful.
Acquisition costs totaled $1.4 million for the year ended December 31, 2002, and
an additional $5.5 million in expenditures was attributable to land holdings,
including $1.0 million for increased seismic data and other geological and
geophysical expenditures. The remaining capital expenditures were associated
with computer hardware and office equipment.

During the year ended December 31, 2001, we used $29.0 million in investing
activities, all of which were capital expenditures. Capital expenditures of
$15.9 million were attributed to drilling 22 gross wells, 17 of which were
successful. Acquisition costs totaled $6.7 million for the year ended December
31, 2001, and an additional $6.0 million was attributable to land holdings,
including $2.6 million for seismic data and other geological and geophysical
expenditures. The remaining capital expenditures were associated with computer
hardware and office equipment.

43

We currently anticipate capital expenditures in 2004 to be approximately
$27.8 million. Approximately $22.7 million is allocated to our expected drilling
and production activities; $2.9 million is allocated to land and seismic
activities; and $2.2 million relates to capitalized interest, G&A and other. We
plan to fund these expenditures from expected cash flow from operations plus
some modest incremental borrowings. We have not explicitly budgeted for
acquisitions; however, we do expect to spend considerable effort evaluating
acquisition opportunities. We expect to fund acquisitions through traditional
reserve-based bank debt and/or the issuance of equity and, if required, through
additional debt and equity financings. We currently have $19.0 million of unused
borrowing capacity under our credit facility.

Net Cash Provided By Financing Activities

Cash flows provided by financing activities totaled $2.9 million for the
year ended December 31, 2003 including $10.7 million in borrowings and $10.2
million in repayments under our current credit facility. In addition, we
received $2.4 million in proceeds from the issuance of common stock related to
options and warrants exercised in 2003. Cash flows provided by financing
activities totaled $10.6 million for the year ended December 31, 2002 including
$11.0 million in borrowings and $0.5 million in repayments under our credit
facility. In addition, we received $122,700 in proceeds from the issuance of
common stock related to options exercised in 2002. Cash flows provided by
financing activities in 2001 were $7.4 million, including borrowings of $11.0
million and repayments of $4.0 million under our credit facility. In addition,
we received $390,400 in proceeds from the issuance of common stock related to
options exercised in 2001.

Due to our active exploration, development and acquisition activities, we
have experienced and expect to continue to experience substantial working
capital requirements. We intend to fund our 2004 capital expenditures,
commitments and working capital requirements through cash flows from operations,
and to the extent necessary other financing activities. The projected 2004 cash
flows from operations are estimated to be sufficient to fund our budgeted
exploration and development program. We believe we will be able to generate
capital resources and liquidity sufficient to fund our capital expenditures and
meet such financial obligations as they come due.

Credit Facility

In March 2004, the Company entered into a new amended and restated credit
facility (the "Credit Facility"), effective December 31, 2003, which permits
borrowings up to the lesser of (i) the borrowing base and (ii) $100 million.
Borrowings under the Credit Facility bear interest at a rate equal to prime plus
0.50% or LIBOR plus 2.25%.

At that time the borrowing base under the Credit Facility was also
increased to $40.0 million, effective December 31, 2003, as a result of the
acquisition of properties in the Miller merger and our drilling activities since
the last redetermination. Upon entering into the new Credit Facility, our
available borrowing capacity was $19.0 million. We expect to redetermine our
existing borrowing base in the second quarter of 2004, and semiannually
thereafter. As of December 31, 2003, $21.0 million in borrowings were
outstanding under the Credit Facility. The Credit Facility matures December 31,
2006 and is secured by substantially all of the Company's assets.

The Credit Facility provides for certain restrictions, including but not
limited to, limitations on additional borrowings, sales of oil and natural gas
properties or other collateral, and engaging in merger or consolidation
transactions. The Credit Facility also prohibits dividends and certain
distributions of cash or properties and certain liens. The Credit Facility also
contains certain financial covenants. The EBITDAX to Interest Expense ratio
requires that (a) our consolidated EBITDAX (defined as EBITDA less similar
non-cash items and exploration and abandonment expenses for such period) for the
four fiscal quarters then ended to (b) our consolidated interest expense for the
four fiscal quarters then ended, to not be less than 3.5 to 1.0. The Working
Capital ratio requires that the amount of our consolidated current assets less
our consolidated current liabilities, as defined in the agreement, be at least
$1.0 million. The Maximum Leverage ratio requires that the ratio, as of the last
day of any fiscal quarter, of (a) Total Indebtedness (as defined in the Credit
Facility) as of such fiscal quarter to (b) an amount equal to consolidated
EBITDAX for the two quarters then ended times

44

two, shall not be greater than 3.0 to 1.0. Consolidated EBITDAX is a component
of negotiated covenants with our lenders and is presented here as part of the
Company's disclosure of its covenant obligations.

Off Balance Sheet Arrangements

The Company currently does not have any off balance sheet arrangements.

Contractual Cash Obligations

The following table summarizes our contractual cash obligations as of
December 31, 2003 by payment due date:

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

(1) The Company did not have any capital leases or purchase obligations as of
December 31, 2003.

Recently Issued Accounting Pronouncements

In January 2003, the FASB issued FIN 46 (revised December 2003),
"Consolidation of Variable Interest Entities," which addresses the consolidation
of business enterprises to which the usual condition (ownership of a majority
voting interest) of consolidation does not apply. This interpretation focuses on
controlling financial interests that may be achieved through arrangements that
do not involve voting interests. It concludes that in the absence of clear
control through voting interests, a company's exposure (variable interest) to
the economic risks and potential rewards from the variable interest entity's
assets and activities are the best evidence of control.

We share interests with related parties in a variety of different
partnership and joint venture entities in order to share the rewards of
ownership in certain oil and natural gas royalties. We do not provide
supplemental financial support to these entities nor do we have voting rights.
In general, these entities are structured such that the voting and sharing
ratios in these entities are consistent with the allocation of the entities'
distributions of cash from royalty revenues. We are not impacted by FIN 46
because there is no investment in or obligation to share in future capital
requirements of these entities. On September 2, 2003, we sold our interests in
two of these entities (see Note 15 to our consolidated financial statements).

As a result of the factors above, the adoption of the above-mentioned
standard did not have a material impact on our financial condition or results of
operations.

Hedging Activities

In December 2003, we entered into a costless natural gas collar covering
5,000 Mmbtu per day for the period January 1, 2004 to March 31, 2004 with a
floor of $4.50 per Mmbtu and a ceiling of $7.05 per Mmbtu. At December 31, 2003
the market value of this instrument was approximately $37,700 and is included in
current assets.

In August 2003, we purchased natural gas options that cover 10,000 MMbtus
per day for the period January 1, 2004 to December 31, 2004 at a floor of $4.50
per MMbtu and a ceiling of $7.00 per MMbtu for the first and fourth quarters of
2004 and $6.00 per MMbtu for the second and third quarters of 2004 for a cost of
$686,250. At December 31, 2003 the market value of this instrument was
approximately $83,100 and is included in current assets.

In April 2003, we entered into a natural gas collar covering 2,000 MMbtu
per day for the period June 1, 2003 to September 30, 2003 with a floor of $5.00
per MMbtu and a ceiling of $6.50 per Mmbtu. This collar

45

resulted in an $18,600 gain reported in oil and gas revenues in our statement of
operations for the year ended December 31, 2003.

In October 2002, we entered into a natural gas collar that covered 10,000
MMbtus per day for the period January 1, 2003 to December 31, 2003 at a floor of
$4.00 per MMbtu and a ceiling of $4.25 per MMbtu. This collar resulted in a loss
from hedging activity of $4.5 million reflected in oil and gas revenues in our
statement of operations for the year ended December 31, 2003.

In August 2002, we entered into a fixed float index swap on 5,000 MMbtus
per day at $3.59 per MMbtu for the period September 1, 2002 through December 31,
2002 and into a second fixed float index swap on an additional 5,000 MMbtus per
day at $3.685 per MMbtu for the period September 1, 2002 through December 31,
2002. These two swap transactions resulted in a loss from hedging activity
reflected in our statement of operations in oil and gas revenues of $163,150.

In March 2002, we purchased a floor on 18,000 MMbtus per day at $2.65 per
MMbtu for the period April 1, 2002 through June 30, 2002, at a cost of $163,800.
The floor structure provided a minimum realized price for the protected volume
yet preserved any upside in gas prices. The natural gas floor expired with no
additional cost to us.

Tax Matters

At December 31, 2003, we have cumulative net operating loss carryforwards
("NOLs") for federal income tax purposes of approximately $50.1 million,
including $17.4 million of NOLs acquired in the Miller merger that expire
beginning 2012 through 2022. We currently anticipate that all of these NOLs will
be utilized in connection with federal income taxes payable in the future. NOLs
assume that certain items, primarily intangible drilling costs, have been
written off for tax purposes in the current year. However, we have not made a
final determination if an election will be made to capitalize all or part of
these items for tax purposes in the future.

ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk from changes in interest rates and commodity
prices. We use a credit facility, which has a floating interest rate, to finance
a portion of our operations. We are not subject to fair value risk resulting
from changes in our floating interest rates. The use of floating rate debt
instruments provide a benefit due to downward interest rate movements but does
not limit us to exposure from future increases in interest rates. Based on the
year-end December 31, 2003 outstanding borrowings and a floating interest rate
of 3.65%, a 10% change in interest rate would result in an increase or decrease
of interest expense of approximately $73,200 on an annual basis.

In the normal course of business we enter into hedging transactions,
including commodity price collars, swaps and floors to mitigate our exposure to
commodity price movements, but not for trading or speculative purposes. During
2003, due to the instability of prices and to achieve a more predictable cash
flow, we put in place two natural gas collars for a portion of our 2004
production. While the use of these arrangements may limit the benefit to us of
increases in the price of oil and natural gas, it also limits the downside risk
of adverse price movements. At December 31, 2003, the fair value of the
outstanding hedges was approximately $120,800 (See ITEM 7. "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -- HEDGING ACTIVITIES"). A 10% change in the gas price per MMbtu, as
long as the price is either above the ceiling or below the floor price would
cause the fair value total of the hedge to increase or decrease by approximately
$22,800.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See the Consolidated Financial Statements and Supplementary information
listed in the accompanying Index to Consolidated Financial Statements and
Supplementary Information on page F-1 herein.

46

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES

None.

ITEM 9A. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of December 31, 2003 to provide reasonable
assurance that information required to be disclosed in our reports filed or
submitted under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the Securities and Exchange Commission's
rules and forms.

There has been no change in our internal controls over financial reporting
that occurred during the three months ended December 31, 2003 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information regarding directors and executive officers required under
ITEM 10 will be contained within the definitive Proxy Statement for the
Company's 2004 Annual Meeting of Shareholders (the "Proxy Statement") under the
headings "Election of Directors" and "Compliance with Section 16(a) of the
Exchange Act" and is incorporated herein by reference. The Proxy Statement will
be filed pursuant to Regulation 14A with the Securities and Exchange Commission
not later than 120 days after December 31, 2003. Pursuant to Item 401(b) of
Regulation S-K certain of the information required by this item with respect to
executive officers of the Company is set forth in Part I of this report.

We have adopted a code of ethics for all employees, officers and directors.
That code is available on our website at www.edgepet.com. Any waivers of, or
amendments to, the Code of Ethics will be posted on the website.

ITEM 11. EXECUTIVE COMPENSATION

The information required by ITEM 11 will be contained in the Proxy
Statement under the headings "Executive Compensation", "Summary Compensation
Table", "Options/SAR Grants", "Option/SAR Exercises and 2003 Year-End Option/SAR
Values", "401(k) Employee Savings Plan", "Employment Agreements and Change of
Control Agreements", "Compensation Committee Interlocks and Insider
Participation", "Performance Graph" and "Compensation Committee Report on
Executive Compensation" and is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

The information required by ITEM 12 will be contained in the Proxy
Statement under the headings "Security Ownership of Certain Beneficial Owners
and Management" and "Equity Compensation Plan Information" and is incorporated
herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by ITEM 13 will be contained in the Proxy
Statement under the heading "Certain Transactions "and is incorporated herein by
reference.

47

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by ITEM 14 will be contained in the Proxy
Statement under the heading "Approval of Appointment of Independent Public
Accountants" and is incorporated herein by reference.

48

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) Financial Statements and Schedules:

1. Financial Statements: See Index to the Consolidated Financial
Statements and Supplementary Information immediately following the
signature page of this report.

2. Financial Statement Schedule: See Index to the Consolidated
Financial Statements and Supplementary Information immediately following
the signature page of this report.

3. Exhibits: The following documents are filed as exhibits to this
report.

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 Petro-
leum Corporation, (v) Edge Mergeco, Inc. and (vi) the
Company, dated as of January 13, 1997 (Incorporated by
reference from exhibit 2.1 to the Company's Registration
Statement on Form S-4 (Registration No. 333-17269)).
2.2 -- Agreement and Plan of Merger dated as of May 28, 2003 among
Edge Petroleum Corporation, Edge Delaware Sub Inc. and
Miller Exploration Company ("Miller") (Incorporated by
reference from Annex A to the Joint Proxy
Statement/Prospectus contained in the Company's Registration
Statement on Form S-4/A filed on October 31, 2003
(Registration No. 333-106484)).
3.1 -- Restated Certificate of Incorporation of the Company
(Incorporated by reference from exhibit 3.1 to the Company's
Registration Statement on Form S-1/A filed on February 5,
1997 (Registration No. 333-17267)).
3.2 -- Certificate of Amendment to the Restated Certificate of
Incorporation of the Company (Incorporated by reference from
exhibit 3.1 to the Company's Registration Statement on Form
S-1/A filed on February 5, 1997 (Registration No.
333-17267)).
3.3 -- Bylaws of the Company (Incorporated by Reference from
exhibit 3.3 to the Company's Quarterly Report on Form 10-Q
for the quarterly period ended September 30, 1999).
3.4 -- First Amendment to Bylaws of the Company on September 28,
1999 (Incorporated by reference from exhibit 3.2 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).
3.5 -- Second Amendment to Bylaws of the Company on May 7, 2003
(Incorporated by reference from exhibit 3.4 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
March 31, 2003).
*4.1 -- Third Amended and Restated Credit Agreement dated December
31, 2003 by and between Edge Petroleum Corporation, Edge
Petroleum Exploration Company, Edge Petroleum Operating Com-
pany, Inc., Miller Oil Corporation, and Miller Exploration
Company, as borrowers, and Union Bank of California, N.A., a
national banking association, as Agent for itself and as
lender.
4.2 -- Common Stock Subscription Agreement dated as of April 30,
1999 between the Company and the purchasers named therein
(Incorporated by reference from exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q/A for the quarter ended March
31, 1999).
4.3 -- Warrant Agreement dated as of May 6, 1999 between the
Company and the Warrant holders named therein (Incorporated
by reference from exhibit 4.5 to the Company's Quarterly
Report on Form 10-Q/A for the quarter ended March 31, 1999).
4.4 -- Form of Warrant for the purchase of the Common Stock
(Incorporated by reference from the Common Stock
Subscription Agreement from exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q/A for the quarter ended March
31, 1999).
4.5 -- Registration Rights Agreement by and among Edge, Guardian
Energy Management Corp., Kelly E. Miller and the Debra A.
Miller Trust, dated December 4, 2003 (Incorporated by
reference from exhibit 4.2 of the Company's Registration
Statement on Form S-3 filed on February 3, 2004
(Registration No. 333-112462)).

49

4.6 -- Securities Purchase Agreement between Miller and Guardian
Energy Management Corp., dated July 11, 2000 (Incorporated
by reference from exhibit 10.1 to Miller's Current Report on
Form 8-K, filed on July 25, 2000).
4.7 -- Warrant between Miller and Guardian Energy Management Corp.,
dated July 11, 2000, exercisable for 900,000 shares of
Miller's common stock (as adjusted for the one for ten
reverse stock split of Miller effected October 11, 2002 and
as adjusted pursuant to the Agreement and Plan of Merger by
and among the Company, Edge Delaware Sub Inc. and Miller)
(incorporated by reference from Exhibit 4.3 to Miller's
Current Report on Form 8-K filed on July 25, 2000).
4.8 -- Miller Exploration Company Stock Option and Restricted Stock
Plan of 1997 (Incorporated by reference from exhibit 10.1(a)
to Miller's Annual Report on Form 10-K for the year ended
December 31, 1997 (File No. 000-23431)).
4.9 -- Amendment No. 1 to the Miller Exploration Company Stock
Option and Restricted Stock Plan of 1997 (Incorporated by
reference to Exhibit 4.2 from Miller's Registration
Statement on Form S-8 filed on April 11, 2001 (Registration
No. 333-58678)).
4.10 -- Amendment No. 2 to the Miller Exploration Company Stock
Option and Restricted Stock Plan of 1997 (Incorporated by
reference from Exhibit 4.3 to Miller's Registration
Statement on Form S-8 filed on April 11, 2001 (Registration
No. 333-58678)).
4.11 -- Form of Miller Stock Option Agreement (Incorporated by
reference from exhibit 10.1(b) to Miller's Annual Report on
Form 10-K for the year ended December 31, 1997 (File No.
000-23431)).
10.1 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership II, dated as of May 10,
1994 (Incorporated by reference from exhibit 10.2 to the
Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).
10.2 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership, dated as of April 11,
1992 (Incorporated by reference from exhibit 10.3 to the
Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).
10.3 -- Amendment dated August 21, 2000 to the Joint Venture
Agreement between Edge Joint Venture II and Essex Royalty
Limited Partnership II, dated as of May 10, 1994.
(Incorporated by reference from exhibit 10.3 to the
Company's Annual Report on Form 10-K/A for the year ended
December 31, 2002).
10.4 -- Amendment dated August 21, 2000 to the Joint Venture
Agreement between Edge Joint Venture II and Essex Royalty
Limited Partnership, dated as of April 11, 1992.
(Incorporated by reference from exhibit 10.2 to the
Company's Annual Report on Form 10-K/A for the year ended
December 31, 2002).
10.5 -- Letter Agreement between Edge Petroleum Corporation and
Essex Royalty Limited Partnership, dated as of July 30,
2002. (Incorporated by reference from exhibit 10.4 to the
Company's Annual Report on Form 10-K/A for the year ended
December 31, 2002).
10.6 -- Form of Indemnification Agreement between the Company and
each of its directors (Incorporated by reference from
exhibit 10.7 to the Company's Registration Statement on Form
S-4 (Registration No. 333-17269)).
10.7 -- Stock Option Plan of Edge Petroleum Corporation, a Texas
corporation (Incorporated by reference from exhibit 10.13 to
the Company's Registration Statement on Form S-4
(Registration No. 333-17269)).
10.8 -- Employment Agreement dated as of November 16, 1998, by and
between the Company and John W. Elias. (Incorporated by
reference from 10.12 to the Company's Annual Report on Form
10-K for the year ended December 31, 1998).
10.9 -- Incentive Plan of Edge Petroleum Corporation as Amended and
Restated Effective as of December 4, 2003. (Incorporated by
reference from exhibit 4.1 to the Company's Registration
Statement on Form S-8 (Registration No. 333 -- 113619).
10.10 -- Edge Petroleum Corporation Incentive Plan "Standard
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Officers named therein.
(Incorporated by reference from exhibit 10.2 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).

50

10.11 -- Edge Petroleum Corporation Incentive Plan "Director
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Directors named therein.
(Incorporated by reference from exhibit 10.3 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).
10.12 -- Severance Agreements by and between Edge Petroleum
Corporation and the Officers of the Company named herein.
(Incorporated by reference from exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).
10.12 -- Form of Employee Restricted Stock Award Agreement under the
Incentive Plan of Edge Petroleum Corporation (Incorporated
by reference from exhibit 10.15 to the Company's Quarterly
Report on Form 10-Q/A for the quarterly period ended March
31, 1999).
10.13 -- Edge Petroleum Corporation Amended and Restated Elias Stock
Incentive Plan. (Incorporated by reference from exhibit 4.5
to the Company's Registration Statement on Form S-8 filed
May 30, 2001 (Registration No. 333-61890)).
10.14 -- Form of Edge Petroleum Corporation John W. Elias
Non-Qualified Stock Option Agreement (Incorporated by
reference from exhibit 4.6 to the Company's Registration
Statement on Form S-8 filed May 30, 2001 (Registration No.
333-61890)).
*21.1 -- Subsidiaries of the Company.
*23.1 -- Consent of KPMG LLP.
*23.2 -- Consent of Ryder Scott Company.
*31.1 -- Certification by John W. Elias, Chief Executive Officer,
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2 -- Certification by Michael G. Long, Chief Financial Officer,
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1 -- Certification by John W. Elias, Chief Executive Officer,
pursuant to 18 USC Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2 -- Certification by Michael G. Long, Chief Financial Officer,
pursuant to 18 USC Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
*99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers as of December 31, 2003.

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

* Filed herewith.

(b) Reports on Form 8-K: The Company filed the following reports on Form
8-K during the quarter ended December 31, 2003:

The Company filed a Current Report on Form 8-K on October 1, 2003
announcing the issuance of a press release reporting the closing of the
previously announced acquisition of oil and gas properties in South Texas and
attaching a copy of the press release as an exhibit.

The Company filed a Current Report on Form 8-K on October 22, 2003
(information furnished not filed) announcing the issuance of a press release
reporting 2003 third quarter operations update and attaching a copy of the press
release as an exhibit.

The Company filed a Current Report on Form 8-K on November 5, 2003
(information furnished not filed) announcing the issuance of a press release
reporting 2003 third quarter financial results update and attaching a copy of
the press release as an exhibit.

The Company filed a Current Report on Form 8-K on November 26, 2003
announcing the issuance of a joint press release announcing the merger ratio
that would be applied in connection with the proposed merger with Miller
Exploration Company and attaching a copy of the press release as an exhibit.

The Company filed a Current Report on Form 8-K on December 11, 2003
announcing the completion of the merger with Miller Exploration Company.

The Company filed a Current Report on Form 8-K on December 16, 2003
(information furnished not filed) announcing the issuance of a press release
announcing their 2004 Capital Program and providing an operations and merger
update and attaching a copy of the press release as an exhibit.

51

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.

Edge Petroleum Corporation

/s/ JOHN W. ELIAS
--------------------------------------
John W. Elias
Chief Executive Officer and Chairman
of the Board

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.

/s/ JOHN W. ELIAS Chief Executive Officer and Date: March 19, 2004
- -------------------------------------- Chairman of the Board
John W. Elias (Principal Executive Officer)

/s/ MICHAEL G. LONG Senior Vice President and Date: March 19, 2004
- -------------------------------------- Chief Financial Officer
Michael G. Long (Principal Financial and
Principal Accounting Officer)

/s/ THURMON M. ANDRESS Director Date: March 19, 2004
- --------------------------------------
Thurmon M. Andress

/s/ VINCENT S. ANDREWS Director Date: March 19, 2004
- --------------------------------------
Vincent S. Andrews

/s/ JOSEPH R. MUSOLINO Director Date: March 19, 2004
- --------------------------------------
Joseph R. Musolino

/s/ STANLEY S. RAPHAEL Director Date: March 19, 2004
- --------------------------------------
Stanley S. Raphael

/s/ JOHN SFONDRINI Director Date: March 19, 2004
- --------------------------------------
John Sfondrini

/s/ ROBERT W. SHOWER Director Date: March 19, 2004
- --------------------------------------
Robert W. Shower

/s/ DAVID F. WORK Director Date: March 19, 2004
- --------------------------------------
David F. Work

52

EDGE PETROLEUM CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND
SUPPLEMENTARY INFORMATION

CONSOLIDATED FINANCIAL STATEMENTS

Audited Financial Statements:
Independent Auditors' Report................................ F-2
Consolidated Balance Sheets as of December 31, 2003 and
2002...................................................... F-3
Consolidated Statements of Operations for the Years Ended
December 31, 2003, 2002 and 2001.......................... F-4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2003, 2002 and 2001.......................... F-5
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2003, 2002 and 2001.............. F-6
Notes to Consolidated Financial Statements.................. F-7
Unaudited Information:
Supplementary Information to Consolidated Financial
Statements............................................. F-28

CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

All schedules for which provision is made in the applicable accounting
regulations of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable and therefore have been omitted.

F-1

INDEPENDENT AUDITORS' REPORT

The Board of Directors and Stockholders
Edge Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Edge
Petroleum Corporation and subsidiaries as of December 31, 2003 and 2002, and the
related consolidated statements of operations, cash flows and stockholders'
equity for each of the years in the three-year period ended December 31, 2003.
These consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Edge
Petroleum Corporation and subsidiaries as of December 31, 2003 and 2002, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2003 in conformity with accounting
principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2003, the Company changed its method of accounting for asset
retirement obligations and effective January 1, 2001, the Company changed its
method of accounting for derivative instruments.

KPMG LLP

Houston, Texas
March 12, 2004

F-2

EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

See accompanying notes to the consolidated financial statements.

F-3

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

See accompanying notes to the consolidated financial statements.

F-4

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to the consolidated financial statements.

F-5

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY

See accompanying notes to the consolidated financial statements.

F-6

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION AND NATURE OF OPERATIONS

General -- Edge Petroleum Corporation (the "Company") was organized as a
Delaware corporation in August 1996 in connection with its initial public
offering and the related combination of certain entities that held interests in
Edge Joint Venture II (the "Joint Venture") and certain other oil and natural
gas properties; herein referred to as the "Combination". In a series of
transactions the Company issued an aggregate of 4,701,361 shares of common stock
and received in exchange 100% of the ownership interests in the Joint Venture
and certain other oil and natural gas properties. In March 1997, and
contemporaneously with the Combination, the Company completed the initial public
offering of 2,760,000 shares of its common stock (the "Offering") generating
proceeds of approximately $40 million, net of expenses.

Nature of Operations -- The Company is an independent energy company
engaged in the exploration, development, acquisition and production of oil and
natural gas. The Company's resources and assets are managed and its results are
reported as one operating segment. The Company conducted its operations
primarily along the onshore United States Gulf Coast, with its primary emphasis
in South Texas, Louisiana and Southeast New Mexico. During 2003 the Company made
three acquisitions (see Note 5) and added a new focus area through an
exploration alliance in Southeast New Mexico. The Company currently controls
interests in almost 208,900 gross acres held under lease or option. 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.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation -- The consolidated financial statements
include the accounts of all majority owned subsidiaries of the Company,
including Edge Petroleum Operating Company Inc., Edge Petroleum Exploration
Company, Miller Oil Corporation and Miller Exploration Company, which are 100%
owned subsidiaries of the Company. All intercompany transactions have been
eliminated in consolidation.

Changes in Accounting Principles -- In 2003, the Company adopted Statement
of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset
Retirement Obligations," which requires a liability for an asset retirement
obligation to be recorded at its fair value in the period in which the
obligation is incurred and a corresponding increase in the carrying amount of
the related long-lived asset (see Note 7).

Beginning in the second quarter of 2003, the Company included derivative
contracts that qualify as cash flow hedges in the ceiling test calculation in
accordance with a revision to Staff Accounting Bulletin Topic 12, "Oil and Gas
Producing Activities" in the Securities and Exchange Commission's ("SEC") Staff
Accounting Bulletin ("SAB") No. 103, "Update of Codification of Staff Accounting
Bulletins." There was no impact to the Company for this change in ceiling test
calculation.

Revenue Recognition -- The Company recognizes oil and natural gas revenue
from its interests in producing wells as oil and natural gas is produced and
sold from those wells. Oil and natural gas sold by the Company is not
significantly different from the Company's share of production.

Allowance for Doubtful Accounts -- The Company routinely assesses the
recoverability of all material trade and other receivables to determine their
collectibility. Many of Edge's receivables are from joint interest owners on
properties of which the Company is the operator. Thus, Edge may have the ability
to withhold future revenue disbursements to recover any non-payment of joint
interest billings. Generally, the Company's crude oil and natural gas
receivables are typically collected within two months. The Company accrues a
reserve on a receivable when, based on the judgment of management, it is
probable that a receivable will not be collected and the amount of any reserve
may be reasonably estimated. As of December 31, 2003 and 2002, the Company had
an allowance for doubtful accounts of $525,248 related to trade receivables and
$82,000 related to joint interest receivables (see Note 3).

F-7

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Inventories -- Inventories consist principally of tubular goods and
production equipment, stated at the lower of weighted-average cost or market.

Other Property, Plant & Equipment -- Depreciation of other office furniture
and equipment and computer hardware and software is provided using the
straight-line method based on estimated useful lives ranging from five to ten
years.

Oil and Natural Gas Properties -- Investments in oil and natural gas
properties are accounted for using the full cost method of accounting. All costs
associated with the exploration, development and acquisition of oil and natural
gas properties, including salaries, benefits and other internal costs directly
attributable to these activities, are capitalized within a cost center. The
Company's oil and natural gas properties are located within the United States of
America, which constitutes one cost center. The Company capitalized $1.7
million, $1.5 million, and $1.6 million of general and administrative costs in
2003, 2002 and 2001, respectively. Interest costs related to unproved properties
are also capitalized to unproved oil and gas properties. The Company capitalized
$244,500, $623,400, and $24,400 of interest costs in 2003, 2002 and 2001,
respectively.

Oil and natural gas properties are amortized using the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the prospects
can be determined or until impairment occurs. Unproved oil and natural gas
properties consist of the cost of unevaluated leaseholds, cost of seismic data,
exploratory and developmental wells in progress, and secondary recovery projects
before the assignment of proved reserves. Unproved properties are evaluated
periodically for impairment on a property-by-property basis. Factors considered
by management in its impairment assessment include drilling results by the
Company and other operators, the terms of oil and natural gas leases not held by
production, production response to secondary recovery activities and available
funds for exploration and development. If the results of an assessment indicate
that an unproved property is impaired, the amount of impairment is added to the
proved oil and natural gas property costs to be amortized. The amortizable base
includes estimated future development costs and dismantlement, restoration and
abandonment costs, net of estimated salvage values. The depletion rates per Mcfe
for the years ended December 31, 2003, 2002 and 2001 were $1.59, $1.39, and
$1.22, respectively.

In June 2001, the Financial Accounting Standards Board ("FASB") issued SFAS
No. 141, "Business Combinations," which requires the use of the purchase method
of accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review of impairment. The new standard also requires that,
at a minimum, all intangible assets be aggregated and presented as a separate
line item in the balance sheet.

A reporting issue has arisen regarding the application of certain
provisions of SFAS No. 141 and 142 to companies in the extractive industries,
including oil and gas companies. This issue is currently on the Emerging Issues
Task Force ("EITF") agenda as Issue 03-S, "Applicability of FASB Statement No.
142, Goodwill and Other Intangible Assets, to Oil and Gas Companies." The issue
is whether SFAS No. 141 and 142 require registrants to classify the costs of
acquiring contractual mineral or drilling rights associated with extracting oil
and gas as intangible assets on the balance sheet, apart from other capitalized
oil and gas property costs, and provide specific footnote disclosures.
Historically, we have included the costs of mineral rights associated with
extracting oil and gas as a component of oil and gas properties. If it is
ultimately determined that SFAS No. 141 requires oil and gas companies to
classify costs of mineral rights associated with extracting oil and gas as a
separate intangible assets line item on the balance sheet, we would be required
to reclassify approximately $22.8 million and $8.8 million at December 31, 2003
and 2002, respectively, out of oil and gas properties and into a separate
intangible assets line item. These costs include those to acquire contract based
drilling and mineral use rights such as delay rentals, lease bonuses,
commissions and brokerage fees, and other leasehold costs. Our cash flows and
results of operations would not be affected since such

F-8

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

intangible assets would continue to be depleted and assessed for impairment in
accordance with full cost accounting rules, as allowed by SFAS No. 142. Further,
we do not believe the classification of the costs of mineral rights associated
with extracting oil and gas as intangible assets would have any impact on our
compliance with covenants under our debt agreements.

In addition, the capitalized costs of oil and natural gas properties are
subject to a "ceiling test," whereby to the extent that such capitalized costs
subject to amortization in the full cost pool (net of depletion, depreciation
and amortization and related deferred taxes) exceed the present value (using 10%
discount rate) of estimated future net after-tax cash flows from proved oil and
natural gas reserves using hedge adjusted period end prices, such excess costs
are charged to operations. Once incurred, an impairment of oil and natural gas
properties is not reversible at a later date. Impairment of oil and natural gas
properties is assessed on a quarterly basis in conjunction with the Company's
quarterly filings with the Securities and Exchange Commission. The period end
price was within the collar established by the Company's hedges at December 31,
2003 and thus did not affect prices used in this calculation. No adjustment
related to the ceiling test was required during the years ended December 31,
2003, 2002, or 2001.

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.

Income Taxes -- The Company accounts for income taxes under the provisions
of SFAS No. 109, "Accounting for Income Taxes," which provides for an asset and
liability approach for accounting for income taxes. Under this approach,
deferred tax assets and liabilities are recognized based on anticipated future
tax consequences, using currently enacted tax laws, attributable to differences
between financial statement carrying amounts of assets and liabilities and their
respective tax bases (see Note 12).

Cash and Cash Equivalents -- The Company considers all highly liquid
investments with original maturities of three months or less to be cash
equivalents.

Stock-Based Compensation -- The Company accounts for stock compensation
plans under the intrinsic value method of Accounting Principles Board ("APB")
Opinion No. 25, "Accounting for Stock Issued to Employees." No compensation
expense is recognized for stock options that had an exercise price equal to the
market value of the underlying common stock on the date of grant. As allowed by
SFAS No. 123, "Accounting for Stock Based Compensation," the Company has
continued to apply APB Opinion No. 25 for purposes of determining net income. In
December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation -- Transition and Disclosure -- an amendment of FASB Statement No.
123" to provide alternative methods of transition for a voluntary change to the
fair value based method of accounting for stock-based employee compensation. The
Company elected not to change to the fair value based method of accounting for
stock based employee compensation. Additionally, the statement amended the
disclosure requirements of SFAS No. 123 to require prominent disclosures in both
annual and interim financial statements about the method of accounting for
stock-based compensation and the effect of the method used on reported results.

The Company is also subject to reporting requirements of FASB
Interpretation No. ("FIN") 44, "Accounting for Certain Transactions involving
Stock Compensation," that requires a non-cash charge to deferred compensation
expense if the market price of the Company's common stock at the end of a
reporting period is greater than the exercise price of certain stock options.
After the first such adjustment is made, each subsequent period is adjusted
upward or downward to the extent that the market price exceeds the exercise
price of the options. The charge is related to non-qualified stock options
granted to employees and directors in prior years and re-priced in May 1999, as
well as certain options newly issued in conjunction with the repricing (see Note
14).

F-9

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Had compensation expense for stock-based compensation been determined based
on the fair value at the date of grant, our net income, earnings available to
common stockholders and earnings per share would have been reduced and the
stock-based compensation cost would have been increased to the pro forma amounts
indicated below:

The weighted-average fair value of options granted during 2003, 2002 and
2001 was $3.24, $4.19 and $6.76, respectively. The fair value of each option
grant is estimated on the date of grant using the Black-Scholes option-pricing
model with the following weighted-average assumptions: expected stock price
volatility of 73%, 77%, and 80% in 2003, 2002 and 2001, respectively; risk free
interest rate of 3.76%, 3.82% and 5.42% in 2003, 2002 and 2001, respectively;
average expected option lives of eight years in 2003, 2002 and 2001,
respectively; and a forfeiture rate of 10% over the vesting period of such
options.

Earnings Per Share -- The Company accounts for its earnings per share in
accordance with SFAS No. 128, "Earnings per Share," which requires the
presentation of "basic" and "diluted" EPS on the face of the income statement.
Basic earnings per common share amounts are calculated using the average number
of common shares outstanding during each period. Diluted earnings per share
assumes the exercise of all stock options and warrants having exercise prices
less than the average market price of the common stock using the treasury stock
method (see Note 14).

Financial Instruments -- The Company's financial instruments consist of
cash, receivables, payables, long-term debt and oil 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 as of December 31, 2003 and 2002 approximates fair value because
the interest rates are variable and reflective of market rates.

Derivatives and Hedging Activities -- Due to the instability of oil and
natural gas prices, the Company may enter into, from time to time, price risk
management transactions (e.g., swaps, collars and floors) for a portion of its
oil and natural gas production to achieve a more predictable cash flow, as well
as to reduce exposure from price fluctuations. While the use of these
arrangements limits the Company's ability to benefit from increases in the price
of oil and natural gas, it also reduces the Company's potential exposure to
adverse price movements. The Company's management sets all of the Company's
hedging policies, including volumes, types of instruments and counterparties, on
a quarterly basis. These policies are implemented by management

F-10

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

through the execution of trades by the Chief Financial Officer after
consultation and concurrence by the President and Chairman of the Board. The
Board of Directors reviews the Company's hedge policies and trades. The Company
designates and accounts for these transactions as hedging activities and,
accordingly, realized gains and losses are included in oil and natural gas
revenue during the period the hedged transactions occur (see Note 10).

The Company adopted SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities" effective January 1, 2001. The statement, as amended by
SFAS No. 137 "Accounting for Derivative Instruments and Hedging
Activities -- Deferral of the Effective Date of FASB Statement No. 133 -- an
Amendment of FASB Statement No. 133" and SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities -- an Amendment of FASB
Statement No. 133", requires that all derivatives be recognized as either assets
or liabilities and measured at fair value, and changes in the fair value of
derivatives be reported in current earnings, unless the derivative is designated
and effective as a hedge. If the intended use of the derivative is to hedge the
exposure to changes in the fair value of an asset, a liability or firm
commitment, then the changes in the fair value of the derivative instrument will
generally be offset in the income statement by the change in the item's fair
value. However, if the intended use of the derivative is to hedge the exposure
to variability in expected future cash flows then the changes in the fair value
of the derivative instrument will generally be reported in Other Comprehensive
Income ("OCI"). The gains and losses on the derivative instrument that are
reported in OCI will be reclassified to earnings in the period in which earnings
are impacted by the hedged item. Upon adoption of SFAS No. 133, the Company
recorded a transition adjustment of approximately $(1.1) million in accumulated
other comprehensive income to record the fair value of the natural gas hedges
that were outstanding at that date.

Upon entering into a derivative contract, the Company designates the
derivative instruments as a hedge of the variability of cash flow to be received
(cash flow hedge). In accordance with SFAS No. 133, the Company formally
documents all relationships between hedging instruments and hedged items, as
well as its risk management objectives and strategy for undertaking various
hedge transactions. The Company also formally assesses, both at the hedge's
inception and on an ongoing basis, the effectiveness of transactions that
receive hedge accounting. All of the Company's derivative instruments at
December 31, 2003 and 2002 were designated and effective as cash flow hedges,
accordingly, all unrealized hedging gains and losses were recognized in
accumulated other comprehensive income.

When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately.

At December 31, 2003, the Company had recorded $0.4 million, net of related
taxes, of cumulative hedging losses in accumulated other comprehensive income,
which will be reclassified to earnings within the next twelve months. The
amounts ultimately reclassified to earnings will vary due to changes in the fair
value of the open derivative instruments prior to settlement.

Comprehensive Income -- The Company follows the provisions of SFAS No. 130,
"Reporting Comprehensive Income". SFAS No. 130 establishes standards for
reporting and presentation of comprehensive income and its components. SFAS No.
130 requires that all items that are required to be recognized under accounting
standards as components of comprehensive income be reported in a financial
statement that is displayed with the same prominence as other financial
statements. In accordance with the provisions of SFAS No. 130, the Company has
presented the components of comprehensive income below the total for net income
on the face of the consolidated statements of operations. For the year ended
December 31, 2003, the Company had unrealized gains from derivative hedging
instruments of $477,522 that was added to net income to arrive at comprehensive
income of $5.0 million. As of December 31, 2002, the Company had unrealized
losses from derivative hedging instruments of $(840,996) that was deducted from
net income to arrive at comprehensive

F-11

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

loss of $(91,251). For the year ended December 31, 2001, there were no
adjustments to net income in deriving comprehensive income.

Use of Estimates -- The preparation of financial statements in conformity
with accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities as of the date of the financial statements and the reported amounts
of revenues and expenses during the reporting periods. Actual results could
differ from these estimates.

Significant estimates include volumes of oil and gas reserves used in
calculating depreciation, depletion and amortization of proved oil and natural
gas properties, future net revenues and abandonment obligations , impairment of
undeveloped properties, future income taxes and related assets/liabilities, bad
debts, derivatives, contingencies and litigation. Oil and natural gas reserve
estimates, which are the basis for unit-of-production depletion and the ceiling
test, have numerous inherent uncertainties. The accuracy of any reserve estimate
is a function of the quality of available data and of engineering and geological
interpretation and judgment. Results of drilling, testing, and production
subsequent to the date of the estimate may justify revision of such estimate.
Accordingly, reserve estimates are often different from the quantities of oil
and natural gas that are ultimately recovered. In addition, reserve estimates
are vulnerable to changes in wellhead prices of crude oil and natural gas. Such
prices have been volatile in the past and can be expected to be volatile in the
future.

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 natural 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 significant
credit losses on such receivables; however, in 2001, the Company reserved
$525,248 related to non-payments from two purchasers of the Company's oil and
natural gas. No bad debt expense was recorded in 2003 or 2002. The Company
cannot ensure that similar such losses may not be realized in the future.

Recently Issued Accounting Pronouncements -- In June 2002, the FASB issued
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities." SFAS No. 146 addresses financial accounting and reporting for costs
associated with exit or disposal activities and nullifies Emerging Issues Task
Force ("EITF") Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)." SFAS No. 146 requires that a liability for
a cost associated with an exit or disposal plan be recognized when the liability
is incurred. The Company adopted SFAS No. 146 effective January 1, 2003. The
Company did not participate in any applicable activities affected by this
standard during the year ended December 31, 2003.

In January 2003, the FASB issued FIN 46 (revised December 2003),
"Consolidation of Variable Interest Entities," which addresses the consolidation
of business enterprises to which the usual condition (ownership of a majority
voting interest) of consolidation does not apply. This interpretation focuses on
controlling financial interests that may be achieved through arrangements that
do not involve voting interests. It concludes that in the absence of clear
control through voting interests, a company's exposure (variable interest) to
the economic risks and potential rewards from the variable interest entity's
assets and activities are the best evidence of control.

The Company shares interests with related parties in a variety of different
partnership and joint venture entities in order to share the rewards of
ownership in certain oil and natural gas royalties. The Company does not provide
supplemental financial support to these entities nor does it own voting rights.
In general, these entities are structured such that the voting and sharing
ratios in these entities are consistent with the allocation of the entities'
distributions of cash from royalty revenues. The Company is not impacted by FIN
46 because

F-12

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

there is no investment in nor obligation to share in future capital requirements
of these or other entities. On September 2, 2003, the Company sold its interests
in two of these entities (see Note 15).

3. ALLOWANCE FOR DOUBTFUL ACCOUNTS

The following table sets forth changes in the Company's allowance for
doubtful accounts for the years ended December 31, 2003, 2002 and 2001:

4. OTHER CURRENT ASSETS

Below are the components of other current assets as of December 31, 2003
and 2002:

5. ACQUISITIONS, MERGER AND DIVESTITURES

ACQUISITIONS

On September 30, 2003 the Company consummated the acquisition of oil and
gas properties in its core South Texas area for $8.9 million paid in cash. The
purchase price was funded from existing working capital and borrowings under its
existing credit facility.

On November 20, 2003 the Company consummated another acquisition of oil and
gas properties in its core South Texas area for $0.9 million paid in cash. The
purchase price was funded from existing working capital and borrowings under its
existing credit facility.

MERGER

On December 4, 2003 the Company completed its merger with Miller
Exploration Company ("Miller"). Under the terms of the merger agreement, each
share of issued and outstanding common stock of Miller was converted into
1.22342 shares of Edge common stock. Edge issued approximately 2.6 million
shares of Edge common stock to the shareholders of Miller in exchange for all of
the outstanding common stock of Miller. The merger was treated as a tax-free
reorganization and accounted for as a purchase business combination. Under this
method of accounting, on the date of the merger, the assets and liabilities of
Miller were recorded

F-13

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

by Edge at their estimated fair market values. The following is a calculation of
the purchase price paid for Miller:

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

(1) Represents merger ratio of 1.22342 multiplied by 2,129,078, the number of
Miller outstanding shares at December 4, 2003.

(2) Represents the average of the closing sales prices for our common stock on a
four trading day collar around the public announcement date of the
acquisition, May 29, 2003.

(3) Relates primarily to severance costs ($255,800), professional fees directly
related to the merger ($635,600) and other direct transaction costs
($348,000). The severance costs result from change in control provisions in
employment contracts and employee plans.

In addition, the Company incurred expenses associated with the merger of
$279,400, which included retention, salaries and benefits, and integration
costs.

The following is the allocation of the purchase price to specific assets
and liabilities based on estimates of fair values and costs, which will be
adjusted to actual amounts as determined. Such adjustments are not expected to
be material.

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

(1) Represents certain tax benefits acquired from Miller primarily consisting of
net operating loss carryforwards subject to corporate ownership limitations.

The following unaudited pro forma results for 2003 and 2002 are a result of
combining the statement of income of Edge with the statement of income for
Miller adjusted for (1) the revenue and costs associated with certain Alabama
properties sold by Miller in June of 2003, prior to consummation of the merger,
(2) depletion, depreciation and amortization expense of Miller applied to the
adjusted basis of the properties acquired using the purchase method of
accounting, and (3) the related income tax effects of these adjustments based on
the applicable statutory rates.

F-14

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following unaudited pro forma information shows the effect on the
Company's consolidated results of operations as if the Miller transaction
occurred on January 1, 2002. The pro forma information includes numerous
assumptions, and is not necessarily indicative of future results of operations:

DIVESTITURES

During 2003, 2002 and 2001, the Company's sold oil and gas properties for
net proceeds of $330,100, $354,300 and $0, respectively. Proceeds from these
dispositions were credited to the full cost pool. The Company's 2003 asset
divestitures related primarily to the sale of the Company's interest in
affiliated entities, Essex I and II Joint Ventures (see Note 15), and certain
oil and gas properties in Texas and Louisiana. The Company's 2002 divestitures
were related to the sale of certain interests in oil and gas properties in
Texas, Alabama, Montana, and Louisiana.

6. PROPERTY AND EQUIPMENT

At December 31, 2003 and 2002, property and equipment consisted of the
following:

The following table summarizes the cost of the properties not subject to
amortization by the year the cost was incurred:

F-15

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

7. ASSET RETIREMENT OBLIGATIONS

In June 2001, the FASB issued SFAS No. 143, which requires that an asset
retirement obligation ("ARO") associated with the retirement of a tangible
long-lived asset be recognized as a liability in the period in which it is
incurred and becomes determinable, with an offsetting increase in the carrying
amount of the associated asset. The cost of the tangible asset, including the
initially recognized asset retirement cost ("ARC"), is depleted over the useful
life of the asset. The offsetting ARO liability is also recorded at fair value,
and accretion expense recognized as the discounted liability is accreted to its
expected settlement value. The fair value of the ARO asset and liability is
measured using expected future cash outflows discounted at the Company's
credit-adjusted risk-free interest rate.

The Company adopted SFAS No. 143 on January 1, 2003, which resulted in a
net increase to oil and gas properties of $0.4 million (i.e. ARC) and related
liabilities of $0.9 million. These amounts reflect the ARO of the Company had
the provisions of SFAS No. 143 been applied since inception and resulted in a
non-cash charge to earnings of $357,800 ($550,500 pre-tax). Going forward the
Company will record an abandonment liability associated with its oil and gas
wells when those assets are placed in service.

The following table describes all changes to the Company's ARO liability
since adoption:

ARO liabilities incurred during the year ended December 31, 2003 include
obligations assumed for over 80 wells acquired in South Texas on September 30,
2003 and 16 wells and 3 facilities acquired in the Miller merger on December 4,
2003 as well as obligations for all successful wells drilled during the year
(see Note 5). Liabilities settled during the year ended December 31, 2003
included 11 wells that were plugged.

The following table summarizes the pro forma net income and earnings per
share for the years ended December 31, 2002 and 2001 had SFAS 143 been adopted
by the Company on January 1, 2001.

Had the Company applied the provisions of SFAS No. 143 in the previous
periods, the pro forma amount of the ARO liability would have been $882,537 at
January 1, 2002 and $703,786 at January 1, 2001.

F-16

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

8. ACCRUED LIABILITIES

Below are the components of accrued liabilities as of December 31, 2003 and
2002:

9. LONG-TERM DEBT

In March 2004, the Company entered into a new amended and restated credit
facility (the "Credit Facility"), effective December 31, 2003, which permits
borrowings up to the lesser of (i) the borrowing base and (ii) $100.0 million.
Borrowings under the Credit Facility bear interest at a rate equal to prime plus
0.50% or LIBOR plus 2.25%. As of December 31, 2003, $21.0 million in borrowings
were outstanding under the Credit Facility. The Credit Facility matures December
31, 2006 and is secured by substantially all of the Company's assets.

At that time the borrowing base under the Credit Facility was also
increased to $40.0 million, effective December 31, 2003, as a result of the
acquisition of properties in the Miller merger and our drilling activities since
the last redetermination. Upon entering into the new Credit Facility, the
available borrowing capacity under this facility was $19.0 million.

The Credit Facility provides for certain restrictions, including but not
limited to, limitations on additional borrowings, sales of oil and natural gas
properties or other collateral, and engaging in merger or consolidation
transactions. The Credit Facility also prohibits dividends and certain
distributions of cash or properties and certain liens. The Credit Facility also
contains certain financial covenants. The EBITDAX to Interest Expense ratio
requires that (a) consolidated EBITDAX (defined as EBITDA less similar non-cash
items and exploration and abandonment expenses for such period) of the Company
for the four fiscal quarters then ended to (b) the consolidated interest expense
of the Company for the four fiscal quarters then ended, not be less than 3.5 to
1.0. The Working Capital ratio requires that the amount of the Company's
consolidated current assets less its consolidated current liabilities, as
defined in the agreement, be at least $1.0 million. The Maximum Leverage ratio
requires that the ratio, as of the last day of any fiscal quarter, of (a) Total
Indebtedness (as defined in the Credit Facility) as of such fiscal quarter to
(b) an amount equal to consolidated EBITDAX for the two quarters then ended
times two, shall not be greater than 3.0 to 1.0 At December 31, 2003, the
Company was in compliance with the above-mentioned covenants. Consolidated
EBITDAX is a component of negotiated covenants with our lenders and is presented
here as part of the Company's disclosure of its covenant obligations.

F-17

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

10. HEDGING ACTIVITIES

The impact on oil and natural gas revenue from hedging activities for the
three years ended December 31, 2003, 2002 and 2001 was as follows:

The outstanding hedges at December 31, 2003, 2002 and 2001 impacting the
Balance Sheet were as follows:

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

(1) The Company's current hedging activities for natural gas were entered into
on a per MMbtu delivered price basis, with settlement for each calendar
month occurring five business days following the expiration date.

(2) This hedge was entered into at a cost of $686,250.

Hedges entered into after December 31, 2003 were as follows:

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

(1) The Company's current hedging activities for natural gas were entered into
on a per MMbtu delivered price basis, Houston Ship Channel Index, with
settlement for each calendar month occurring five business days following
the expiration date.
F-18

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(2) The Company's current hedging activities for crude oil were entered into on
a per Bbl delivered price basis, West Texas Intermediate Index, with
settlement for each calendar month occurring five business days following
the expiration date.

11. COMMITMENTS AND CONTINGENCIES

COMMITMENTS

At December 31, 2003, the Company was obligated under noncancelable
operating leases. Following is a schedule of the remaining future minimum lease
payments under these leases:

2004........................................................ $ 436,200
2005........................................................ 449,700
2006........................................................ 441,800
2007........................................................ 441,800
Remainder................................................... 2,397,300
----------
Total....................................................... $4,166,800
==========

Rent expense for the years ended December 31, 2003, 2002 and 2001 was
$442,700, $566,700, and $579,000, respectively.

EXPLORATION ALLIANCE

On August 26, 2003, the Company entered into a new exploration alliance to
jointly explore for oil and natural gas in the Southeast New Mexico portion of
the Permian Basin with two private oil and gas companies. Edge and its
co-explorers agreed to the establishment of an area of mutual interest (the
"AMI") covering all of Eddy and Lea Counties, as well as a portion of southern
Chaves County. The Company will act as operator for the exploration alliance and
earn, subject to fulfillment of certain obligations, an assignment of an
undivided working interest and a net revenue interest, proportionately reduced,
in all acreage owned in the AMI. In order to earn the interests in the AMI
properties, the Company will pay a total fee of $2.7 million, $1.0 million paid
at closing and the balance to be paid in 17 equal monthly installments, and
commit to the drilling of four Grayburg/San Andres and six Atoka/Morrow wells
within an 18 month time period. In addition to the fee, the Company will carry
its partners for certain costs in the obligation wells. All subsequent wells,
new leasehold acreage and any other acquisitions will be done on a pro-rata
basis by all parties. As of December 31, 2003, the Company had $1.2 million of
payments remaining under this agreement.

CONTINGENCIES

From time to time the Company is a party to various legal proceedings
arising in the ordinary course of business. While the outcome of lawsuits cannot
be predicted with certainty, the Company is not currently a party to any
proceeding that it believes, if determined in a manner adverse to the Company,
could have a potential material adverse effect on its financial condition,
results of operations or cash flows.

Additionally, 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. 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 natural gas industry in general,
the business and prospects of the Company could be adversely affected.

F-19

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

12. INCOME TAXES

Deferred income taxes reflect the tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts calculated for income tax purposes in accordance with
SFAS No. 109. Significant components of the Company's deferred tax liabilities
and assets as of December 31, 2003 and 2002 are as follows:

Tax benefits of $137,100 associated with the exercise of non-qualified
stock options during the year ended December 31, 2003 are reflected as a
component of equity. Upon adoption of SFAS No. 143 on January 1, 2003, the
Company recorded a cumulative effect of change in accounting principle of
$357,825, after taxes of $192,675.

The Company's provision (benefit) for income taxes consists of the
following:

The differences between the statutory federal income taxes calculated using
a federal tax rate of 35% and the Company's effective tax rate is summarized as
follows:

At December 31, 2003, the Company had cumulative net operating loss
carryforwards ("NOLs") for federal income tax purposes of approximately $50.1
million that expire beginning 2012 through 2022. The Company believes that it is
more likely than not that it will utilize all of these NOLs in connection with
federal income taxes generated in the future. The estimated NOLs presented
herein assume that certain items, primarily intangible drilling costs, have been
written off for tax purposes in the current year. However,

F-20

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the Company has not made a final determination if an election will be made to
capitalize all or part of these items for tax purposes in the future. During
2001, the Company determined that it was more likely than not that future
taxable income would be sufficient to realize its recorded tax assets,
accordingly a valuation allowance totaling $3.2 million was reversed.

13. EMPLOYEE BENEFIT PLANS

Effective July 1, 1997, the Company established a defined-contribution
401(k) Savings & Profit Sharing Plan Trust (the "Plan") covering employees of
the Company who are age 21 or older. The Company's matching contributions to the
Plan are discretionary. For the years ended December 31, 2003, 2002 and 2001,
the Company contributed $74,200, $83,200, and $60,500, respectively, to the
Plan.

14. EQUITY AND STOCK PLANS

Private Offering -- In connection with a private offering on May 6, 1999 of
1,400,000 shares of common stock at a price of $5.40 per share the Company
issued warrants for $0.125 per warrant, to acquire an additional 420,000 shares
of common stock at $5.35 per share and are exercisable through May 6, 2004. At
the election of the Company, the warrants may be called at a redemption price of
$0.01 per warrant at any time after any date at which the average daily per
share closing bid price for the immediately preceding 20 consecutive trading
days exceeds $10.70. In November and December of 2003, 375,000 warrants were
exercised for proceeds of approximately $2.0 million. As of December 31, 2003,
45,000 warrants were outstanding. Subsequent to December 31, 2003, Mr. Elias,
our Chairman and Chief Executive Officer, exercised the remaining warrants which
resulted in our issuance to him of 45,000 shares of common stock and net
proceeds to us of $240,750.

Stock Plan -- In conjunction with the Offering, the Company established the
Incentive Plan of Edge Petroleum Corporation (the "Incentive Plan"). The
Incentive Plan is discretionary and provides for the granting of awards,
including options for the purchase of the Company's common stock and for the
issuance of restricted and/or unrestricted common stock to directors, officers,
employees and independent contractors of the Company. The options and restricted
stock granted to date vest over periods of 2-10 years. An aggregate of 1,700,000
shares of common stock have been reserved for grants under the Incentive Plan,
of which 558,030 shares were available for future grants at December 31, 2003.
Shares of common stock awarded as restricted stock are subject to vesting
requirements and subject to risk of forfeiture until earned by continued
employment or service. During 2003, awards of 32,000 nonqualified stock options
were issued having an exercise price in the range of $3.88 to $5.73 per share
based on the market value on the date of grant. Also, during 2003, awards for
87,300 shares of restricted stock were made having a value in the range of $3.88
to $6.68 per share based on the market value on each award date. During 2002,
awards of 199,800 nonqualified stock options were issued having an exercise
price of $3.40 to $5.69 per share based on the market value on the date of
grant. Also during 2002, awards for 15,800 shares of restricted stock were made
having a value in the range of $3.40 to $5.21 per share based on the market
value on each award date. During 2001, awards for 100,800 shares of restricted
stock were made having a value in the range of $4.58 to $8.88 per share based on
the market value on each award date. Shares of common stock associated with
these awards will be issued, subject to continued employment, ratably over three
years in accordance with the award's vesting schedule, beginning on the first
anniversary of the date of grant. Compensation expense is amortized over the
vesting period and offset to additional paid in capital. Amortization of
deferred compensation related to restricted stock awards totaled $372,200,
$399,200 and $353,400, respectively, for the years ended December 31, 2003, 2002
and 2001.

Effective May 21, 1999, the Company amended and restated the Incentive
Plan. In conjunction with those and other amendments of the Incentive Plan, the
Company exchanged, on a voluntary basis, 556,488 outstanding nonqualified stock
options of certain employees and Directors of the Company for 326,700 new

F-21

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

common stock options in replacement of those options. The exercise price of the
replacement options was $7.06 per share, which represents the fair market value
on the date of grant. The replaced options have a ten-year term with 50% of the
options vesting immediately on the date of grant with the remaining 50% vesting
on May 21, 2000. On May 21, 1999, in conjunction with the repricing, the Company
also issued 99,800 new ten-year common stock options to employees, which vested
100% on May 21, 2001. The exercise price of the new options was $7.06, which
represents the fair market value on the date of grant. On June 1, 1999, the
Company issued 21,000 ten-year common stock options to non-employee directors
with an exercise price of $7.28 per share, which represented their fair market
value at the date of grant, vesting 100% on June 1, 2001.

The Company amended the Incentive Plan in December 2003, to increase the
shares available under the plan from 1.2 million to 1.7 million.

Deferred compensation cost reported in accordance with FIN 44 included a
charge of $1.2 million for the year ended December 31, 2003. Below is a summary
of FIN 44 charges and credits impacting the Company's statement of operations
for the years indicated:

Effective January 8, 1999, as a component of his employment agreement with
the Company, John Elias, CEO and Chairman of the Board, was granted options
outside of the Incentive Plan for the purchase of 200,000 shares of common
stock. These options vest and become exercisable one-third upon issue, and one-
third upon each of January 1, 2000 and January 1, 2001. In January 2000, Mr.
Elias was granted additional options outside of the Incentive Plan for the
purchase of 50,000 shares of common stock. These options vested and became 100%
exercisable in January 2002. In January 2001, Mr. Elias was granted additional
options outside the Incentive Plan for the purchase of another 50,000 shares of
common stock. These options vested and became 100% exercisable in January 2003.
In January 2002, Mr. Elias was granted additional options outside the Incentive
Plan for the purchase of another 50,000 shares of common stock that vested and
became 100% exercisable in January 2004. In April 2002, Mr. Elias was granted
additional options outside the Incentive Plan for the purchase of another 24,000
shares of common stock. These options vest and become 100% exercisable in April
2004. In January 2003, Mr. Elias was granted options outside the Incentive Plan
for the purchase of another 50,000 shares of common stock that vest and become
100% exercisable in January 2005. In April 2001, Mr. Elias was granted 14,000
shares of restricted stock outside the Incentive Plan valued at $7.75 per share,
the market value on the award date. These shares are issued ratably over three
years in accordance with the award's vesting schedule, beginning on the first
anniversary of the date of grant. Compensation expense is amortized over the
vesting period and offset to additional paid in capital. The

F-22

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

amortization of compensation expense related to this award was included in the
amounts discussed above. Below is a summary of option and restricted stock
grants to Mr. Elias:

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

(1) Exercise price equals the fair market value on the date of grant.

(2) Value was $7.75 per share, the market value on the date of grant.

A summary of the status of the Company's stock options and changes as of
and for each of the three years ended December 31, 2003 is presented below:

The Company purchased 133,645 options from a former employee at a cost of
$100,000 that was included in general and administrative costs for the year
ended December 31, 2001.

F-23

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A summary of the Company's stock options categorized by class of grant at
December 31, 2003 is presented below:

Computation of Earnings Per Share -- The following is presented as a
reconciliation of the numerators and denominators of basic and diluted earnings
per share computations, in accordance with SFAS No. 128.

F-24

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

15. RELATED PARTY TRANSACTIONS

The transactions described below in this Note 15 were carried out on terms
at least as favorable to the Company as could have been obtained from
unaffiliated third parties in arm's length negotiations, however, because the
transactions were with affiliates, it is possible that the Company would have
obtained different terms from a truly unaffiliated third-party.

Essex Royalty Joint Ventures -- A company wholly owned by Mr. Sfondrini 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."). In April
1992, a predecessor partnership of the Company and Essex I L.P. entered into a
Joint Venture Agreement (the "Essex I Joint Venture") with respect to the
purchase of certain royalty and nonoperating interests in oil and natural gas
properties. In May 1994, the Company's predecessor partnership and Essex II L.P.
entered into a Joint Venture Agreement (the "Essex II Joint Venture") similar in
nature to the Essex I Joint Venture. Since January 1, 2001, Mr. Sfondrini and a
company wholly owned by Mr. Sfondrini have served as manager of the Essex I and
II Joint Ventures. Prior to that time, the Company served as manager.

The Essex I Joint Venture terminated in April 1997, although distributions
from it continue. Under the terms of the Essex I Joint Venture Agreement, Essex
I L.P. made capital contributions aggregating $3 million and the Company and its
predecessor made no capital contributions. The Essex I Joint Venture Agreement
provides that quarterly distributions of cash be made, in accordance with
specified 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 managing venturer and the expenses of the Essex I Joint Venture.
Initially, Essex I L.P. receives 100% of all cash distributions pursuant to the
sharing ratios until a certain payout amount has been recouped as defined in the
Essex I Joint Venture Agreement, as amended, at which time the sharing ratios
shift to 40% for the Company and 60% for Essex I L.P. The Essex I Joint Venture
Agreement was amended prior to 2003 to, among other things, modify the
calculation as to when the sharing ratio would occur, provide for a management
fee payable to the managing venture of 3% per month of gross distributions and
provide for a de minimus portion of the after-payout distributions to go to Edge
Group Partnership, a general partnership, the partners of which are three
limited partnerships, the general partner of each of which is a company wholly
owned by Mr. Sfondrini. The sharing ratio shift, or payout, for Essex I Joint
Venture occurred in 2001, and the Company became entitled to receive from Essex
I Joint Venture 40% of the net royalty distributions. During 2003, the Essex I
Joint Venture distributed $180,493, $1,135 and $61,149 in net royalty
distributions to Essex I L.P., Edge Group Partnership and the Company,
respectively.

The Essex II Joint Venture terminated in December 31, 1998, although
distributions from it continue. Essex II L.P. made capital contributions
aggregating approximately $4.6 million and the Company and its predecessor made
no capital contributions. In 2003, Essex II L.P. made additional cash
contributions of

F-25

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$57,000. Initially, Essex II L.P. receives 100% of all cash distributions
pursuant to the sharing ratios until a certain payout amount has been recouped
as defined in the Essex II Joint Venture Agreement, as amended, at which time
the sharing ratios shift to 25% for the Company and 75% for Essex II L.P.
Provisions with respect to mandatory quarterly distributions are similar to
those described for the Essex I Joint Venture. Pursuant to an amendment of the
Essex II Joint Venture in August 2000, the time at which the sharing ratio
shifts, or payout under the joint venture agreement for Essex II Joint Venture
would occur, was extended until the limited partners of Essex II L.P. had
recovered 100% of their initial capital investment in Essex II L.P. As a result
of the August 2000 amendment, the sharing ratio shift for Essex II Joint Venture
occurs when the aggregate amount of cash and property interests (valued as
determined by the joint venture agreement) actually distributed to the Essex II
L.P. during 2001 and subsequent years equals $3,324,587. During 2001, 2002 and
2003, the amount of cash distributed to Essex II L.P. was $1,325,092, $436,899
and $319,089, respectively, leaving an amount of $1,300,507 (net of additional
capital contributions) remaining to be recovered by Essex II L.P. before payout
and a sharing ratio shift occurs for Essex II Joint Venture.

During 2003, Mr. Sfondrini accrued management and administration fees
(including expenses he is entitled to be reimbursed for) in the amount of
$32,676 for managing the Essex I and II Joint Ventures, $29,100 of which was
paid to third parties who performed management, administration and tax services
for Mr. Sfondrini on behalf of the Joint Ventures.

During the third quarter of 2003, the Company sold its interests in the
Essex I and II Joint Ventures to an unrelated third party for total cash
consideration of $275,000.

Affiliates' Ownership in Prospects -- Edge Group Partnership, Edge Holding
Company, L.P., a limited partnership of which Mr. Sfondrini and a corporation
wholly owned by him are the general partners, Andex Energy Corporation and
Texedge Energy Corporation, corporations of which Mr. Andrews is an officer and
members of his immediate family hold ownership interests, Mr. Raphael, and Essex
II Joint Venture, own certain working interests in the Company's Nita and Austin
Prospects and certain other wells and prospects operated by the Company. These
working interests aggregate 7.19% in the Austin Prospect, 6.27% in the Nita
Prospect and are neglible in other wells and prospects. These working interests
bear their share of lease operating costs and royalty burdens on the same basis
as the Company. In addition, Bamaedge, L.P., a limited partnership of which
Andex Energy Corporation is the general partner, and Mr. Raphael also hold
overriding royalty interests with respect to the Company's working interest in
certain wells and prospects. Neither Mr. Raphael nor Bamaedge L.P. has an
overriding interest in excess of .075% in any one well or prospect. Essex I and
II Joint Ventures own royalty and overriding royalty interests in various wells
operated by the Company. The combined royalty and overriding royalty interests
of the Essex I and Essex II Joint Ventures do not exceed 6.2% in any one well or
prospect. The gross amounts distributed or accrued to these persons and entities
by the Company in 2003 (including net revenue, royalty and overriding royalty
interests) and the

F-26

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

amounts these same persons and entities paid to the Company for their respective
share of lease operating expenses and other costs is set forth in the following
table:

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

(1) In the case of Essex I and II Joint Ventures, amount includes royalty income
in addition to working interest and overriding royalty income.

16. SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES

A summary of non-cash investing and financing activities for the years
ended December 31, 2003, 2002 and 2001 is presented below:

Supplemental Disclosure of Cash Flow Information

F-27

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

17. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED):

The sum of the individual quarterly basic and diluted earnings (loss) per
share amounts may not agree with year-to-date basic and diluted earnings (loss)
per share amounts as a result of each period's computation being based on the
weighted average number of common shares outstanding during that period.

Included in operating expenses for the three months ended December 31,
2003, is a non-cash charge of $(1.2) million to compensation expense as required
by FIN 44.

Second quarter results for 2002 were impacted by the recognition of revenue
associated with underaccruals in prior periods. This adjustment resulted in 142
MMcfe of additional production and $577,200 additional revenue. After adjusting
for related operating costs, the impact to net income for the second quarter of
2002 was an increase of $212,300.

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

This footnote provides unaudited information required by SFAS No. 69,
"Disclosures About Oil and Natural Gas Producing Activities." The Company's oil
and natural gas properties are located within the United States of America,
which constitutes one cost center.

F-28

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

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

(1) Excluded from asset retirement costs in 2003 was $640,400 related to the
cumulative effect of the adoption of SFAS No. 143 on January 1, 2003. See
Note 7.

Results of Operations -- Results of operations for the Company's oil and
natural gas producing activities are summarized below:

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

(1) The Company adopted SFAS No. 143 effective January 1, 2003 using a
cumulative effect approach, therefore no comparable accretion expense
appears in 2002 and 2001.

F-29

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 (see
Standardized Measure) 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 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.

F-30

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Standardized Measure -- The Standardized Measure of Discounted Future Net
Cash Flows relating to the Company's ownership interests in proved oil and
natural gas reserves for each of the three years ended December 31, 2003 is
shown below:

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 oil and natural gas operating expenses and development costs are computed
primarily by the Company's petroleum engineers and are provided to Ryder Scott
as estimates of 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 the continuation of existing economic conditions.

Future income taxes are based on year-end statutory rates, adjusted for net
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 natural 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, a discount
factor more representative of the time value of money and the risks inherent in
reserve estimates.

F-31

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Changes in Standardized Measure -- Changes in Standardized Measure of
Discounted Future Net Cash Flows relating to proved oil and gas reserves are
summarized below:

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 natural 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-32

INDEX TO EXHIBITS

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

* Filed herewith.

+ Previously filed.