EDGE PETROLEUM CORP - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2001

COMMISSION FILE NUMBER: 0-22149
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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.)

CHEVRON/TEXACO HERITAGE PLAZA 77002
1111 BAGBY, SUITE 2100 (Zip code)
HOUSTON, TEXAS
(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
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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. [ ]

The aggregate market value of the voting stock held by non-affiliates of
the Registrant at March 15, 2002, was $49.6 million (based on a value of $5.30
per share, the closing price of the Common Stock as quoted by NASDAQ National
Market on such date). 9,351,215 shares of Common Stock, par value $.01 per
share, were outstanding on March 15, 2002.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the registrant's 2002 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.
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TABLE OF CONTENTS

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."

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 2001, our net
proved reserves were 44.8 Bcfe, comprised of 38.9 billion cubic feet of natural
gas, 750.5 thousand barrels of oil and 227.9 thousand barrels of plant products.
Natural gas accounted for approximately 87% of those proved reserves. About 83%
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 that time from a
prospect generation organization focused solely on high-risk, 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. After giving effect to the time needed to
make those changes, there have been significant activities that have resulted in
growth in reserves, production and financial strength.

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 and production operations

- 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 2001, we conducted an active, technology-driven drilling program in
both south Texas and south-central Louisiana. Our drilling program was balanced
between a small number of relatively higher-risk, high-potential prospects and a
larger number of relatively lower-risk, moderate and low-potential prospects. We
drilled 22 wells in 2001 with 17 completed as successful. Four of these
successful wells were waiting on testing or pipeline connection at year-end.
This drilling program, along with our 2001 acquisitions, allowed us to replace
331% of our production in 2001 and grow our year-end reserve base by 51%. We
expect to drill approximately the same number of wells in 2002, continuing a
balanced program of risk and reward.

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BALANCE

In 2001, 80 % of our reserve growth came from our drilling activity and 20%
came from acquisitions. We seek acquisitions of proven properties that typically
have exploration or exploitation upside potential. We primarily seek properties
in our core areas, or as a means to establish new core areas. We expect to focus
more of our efforts in 2002 on acquisitions than we have in the past. At the end
of 2001, we hired a Vice President of Business Development and Planning to lead
this effort.

We believe our low and moderate-risk 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 and 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 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 and
development activities. Advanced visualization and 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, 2001, we held licenses to 3-D seismic data covering approximately
1,500 square miles in Texas, 650 square miles in Louisiana and 55 square miles
in Montana.

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. Despite growing debt capacity, we have been
careful to limit our borrowings. At December 31, 2001, our debt to total capital
ratio was 15 percent. 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, significantly reduced our 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 15, 2002, our employees
and directors owned or had options to acquire an aggregate of about 16% 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, 2001. 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

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revenue as of December 31, 2001. Ryder Scott's estimates were based upon a
review of production histories and other geologic, economic, ownership and
engineering data provided by us. In estimating the reserve quantities that are
economically recoverable, Ryder Scott used year-end oil and natural gas prices
in effect at December 31, 2001 and estimated development and production costs
that were in effect during December 2001 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, 2001, 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 14 to our consolidated financial
statements. See ITEMS 1 AND 2. -- "BUSINESS AND PROPERTIES -- FORWARD LOOKING
INFORMATION AND RISK FACTORS -- The 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, 2001, which were $2.92 per Mcf of natural gas and
$18.14 per Bbl of oil.

There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and in projecting future rates of production
and timing of development expenditures, including many factors beyond the
control of the producer. The reserve data set forth herein represents estimates
only. Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact 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 future prices, production
levels and costs that may not prove correct.

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

3

In accordance with Commission regulations, the Ryder Scott Report used
year-end oil and natural gas prices in effect at December 31, 2001. 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, 2001. 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. As of March 15, 2002,
the average prices that we received for our production was approximately $2.40
per Mcf for natural gas and $21.50 per barrel for crude oil. Decreases in the
assumed commodity prices result in decreases in estimated future net revenue as
well as in estimated reserves.

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), 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 $28.6 million for the year ended December 31, 2001 that added 23.7
Bcfe, net to our interest, of proved reserves. Our average finding and
development cost was $1.21 per Mcfe for 2001. For the three most recent years,
the total of these costs were $53.8 million adding 41.8 Bcfe of proved reserves
for an average finding and development cost of $1.29 per Mcfe.

4

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.

DRILLING ACTIVITY

The following table sets forth our drilling activity for the three years
ended December 31, 2001. In the table, "gross" refers to the total wells in
which we have a working interest and "net" refers to gross wells multiplied by
our working interest therein.

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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, 2001.

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(1) Includes 82 gross wells shut-in (24.24 net).

ACREAGE DATA

The following table sets forth certain information regarding our developed
and undeveloped lease acreage as of December 31, 2001. 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 8,983 gross (3,078 net), 11,216 gross (6,785
net) and 6,565 gross (2,989 net) undeveloped acres are scheduled to expire in
2002, 2003 and 2004, 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 10,538 gross (6,920 net) acres that we have a
right to acquire pursuant to various seismic option agreements at December 31,
2001. Under the terms of our option agreements, we typically have the right for
one year, subject to extensions, to exercise our option to lease the acreage at
predetermined terms.

CORE AREAS OF OPERATION

As of December 31, 2001, 52% of our proved reserves were in south Texas and
46% in south-central Louisiana. During 2001, we added a new focus area in the
northern Rocky Mountains that we expect to become a core area in 2002.

TEXAS

We currently own an interest in 29,867 net acres in south Texas. Our areas
of focus in this region are predominately in the Wilcox, Vicksburg, Yegua, Queen
City and Frio producing trends. As of December 31, 2001, we operated
approximately 46 wells (38 excluding properties acquired in late December),
accounting for about 45% of our total net production in Texas. We drilled 19
wells during 2001 in Texas, 15 of which were successfully completed. During
2002, we currently expect to drill 10 to 15 wells in our core areas in Texas. We
are currently acquiring new 3-D seismic data in an area adjoining our O'Connor
Ranch project in Goliad County, Texas and we expect drilling operations to
commence there late in the third quarter of 2002.

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At the end of 2001, we made an acquisition in Webb County, Texas for $6.2
million. The acquired property, known as Gato Creek, consists of eight producing
wells, gathering lines, facilities and 3-D seismic data. The property covers
approximately 1,900 gross acres. We recorded about 5.4 Bcfe of proved reserves
associated with this acquisition and believe there are at least four to six
future drilling locations on the property. We expect to drill at least two new
wells on this property during 2002, and undertake several recompletions.

LOUISIANA

We currently own an interest in 4,635 net acres in south-central Louisiana.
In 1997, we began to re-establish activity in Louisiana where we had been
historically active and had prior exploration success. Our operations are
focused in a prolific gas producing area covering parts of Acadia, Lafayette,
St. Landry and Vermilion Parishes. The exploratory focus in this area is
primarily deep, geo-pressured gas prospects ranging from 12,000 to 20,000 feet
in depth. We successfully drilled two out of three exploratory wells in this
region during 2001 and currently plan to drill at least one development well and
one exploratory well in this area during 2002. The planned development well will
offset our successful Thibodeaux No. 1 well that was drilled on our Duson-Hourst
prospect in late 2001. Currently, no reserves are recorded as proved undeveloped
for this proposed well which we expect to spud in the second quarter of 2002.
The primary targets for this well are the Nonion Struma and Nodosaria sections
at approximately 13,500 to 15,000 feet. We believe a portion of the Nodosaria
section was faulted out in the Thibodeaux well. The exploratory well we hope to
drill will test our North Gueydan prospect that is a Marg-Tex sand exploratory
test to 16,500 feet in depth.

NORTHERN ROCKY MOUNTAINS

During 2001, we acquired a 50% working interest in 85,000 gross acres in
the northern Powder River Basin of Montana. In addition, we directed the
acquisition of 55 square miles of proprietary 3-D seismic covering a portion of
this acreage block. Currently, we expect to drill five wells in this area in
2002, commencing late in the second quarter or early in the third quarter of
2002. This area has multiple objectives ranging from shallow coal bed methane at
1,000 feet to a deeper Paleozoic section at approximately 11,000 feet. This
section is generally non-pressured with lower dry hole costs than many of our
Gulf Coast plays.

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 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 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 -- General Overview."

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We believe that hedges should be used as a financial tool to protect
against the effects of a leveraged capital structure, ensure project rates of
return from acquisitions and to help management budget and plan. Recommendations
with respect to hedging opportunities are made by both the financial and
marketing departments to our management committee and Chief Executive Officer
for approval. The administration of hedges, if any, is handled jointly by our
finance, marketing and production departments.

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
December 31, 2001, 2000, and 1999 was approximately $(0.9) million, $(1.5)
million and $(1.1) million, respectively, representing net losses from hedging
activity. In December 2000, we entered into a natural gas collar that covered
4,000 MMbtus per day for the period January 1, 2001 to December 31, 2001 at a
$4.50 per MMbtu floor and a $6.70 per MMbtu ceiling. On January 3, 2001, we
closed out the hedge for the period February 1, 2001 to December 31, 2001 at a
cost of $547,760. During December 1999, we entered into a crude oil fixed price
swap for 2000. As a result, included in oil and condensate revenue for the year
ended December 31, 2000 was approximately $(223,450) representing net losses
from that hedging activity. No hedges were outstanding at December 31, 2001. At
December 31, 2000 and 1999, the fair value, or net gain (loss), of outstanding
hedges, for the following year was approximately $(1.1) million and $15,000,
respectively.

In March 2002, we purchased a floor on 18,000 MMbtus per day at $2.65 for
the period April 1, 2002 through June 30, 2002 at a cost of $163,800. The floor
structure provides a minimum realized price for the protected volume, yet
preserves any upside in gas prices.

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
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
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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 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. The FERC's
jurisdiction over interstate natural gas sales and transportation was
substantially modified by the Natural Gas Policy Act of 1978 (the "NGPA"), under
which the FERC continued to regulate the maximum selling prices of certain
categories of gas sold in "first sales" in interstate and intrastate commerce.
Effective January 1, 1993, however, 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. 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. Beginning with Congressional passage of the NGPA, the
FERC adopted regulatory changes that have significantly altered the
transportation and marketing of natural gas. These changes were intended by the
FERC to foster competition by, among other things, transforming the role of
interstate pipeline companies from wholesale marketers of gas to the primary
role of gas transporters. Through similar orders affecting intrastate pipelines
that provide similar interstate services under the NGPA, the FERC expanded the
impact of open access regulations to intrastate commerce.

9

Beginning in April 1992, the FERC issued Order No. 636 and a series of
related orders, which required interstate pipelines to provide open-access
transportation on a not unduly discriminatory basis for all natural gas
shippers. All gas marketing by the pipelines was required to be divested to a
marketing affiliate, which operates separately from the transporter and in
direct competition with other gas merchants. Although Order No. 636 does not
directly regulate our production and marketing activities, it does affect how
buyers and sellers gain access to the necessary transportation facilities and
how natural gas is sold in the marketplace.

The courts have largely affirmed the significant features of Order No. 636
and the numerous related orders pertaining to individual pipelines. However,
some appeals remain pending and the FERC continues to review and modify its
regulations regarding the transportation of natural gas. For example, in 2000
the FERC issued Order No. 637 which:

- lifts the cost-based cap on pipeline transportation rates in the capacity
release market until September 30, 2002, for short-term releases of
pipeline capacity of less than one year,

- permits pipelines to file for authority to charge different maximum
cost-based rates for peak and off-peak periods,

- encourages, but does not mandate, auctions for pipeline capacity,

- requires pipelines to implement imbalance management services,

- restricts the ability of pipelines to impose penalties for imbalances,
overruns and non-compliance with operational flow orders, and

- implements a number of new pipeline reporting requirements.

Order No. 637 also requires the FERC staff to analyze whether the FERC
should implement additional fundamental policy changes. These include whether to
pursue performance-based or other non-cost based ratemaking techniques and
whether the FERC should mandate greater standardization in terms and conditions
of service across the interstate pipeline grid.

In April 1999, the FERC issued Order No. 603, which implemented new
regulations governing the procedure for obtaining authorization to construct new
pipeline facilities. In September 1999, the FERC issued a related policy
statement establishing a presumption in favor of requiring owners of new
pipeline facilities to charge rates for service on new pipeline facilities based
solely on the costs associated with such new pipeline facilities. It remains to
be seen what effect the FERC's other activities will have on access to markets,
the fostering of competition and the cost of doing business.

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. 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.

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 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.

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-Order No. 636 environment.

10

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 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
pipeline, although the annual adjustments may result in decreased rates in a
given year. 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 may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from our
operations. The EPA and states have been developing 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

11

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 requirements relating to the prevention of and
response to oil spills into waters of the United States. The OPA subjects owners
of facilities to strict joint and several liability for all containment and
cleanup costs and certain other damages arising from a spill, including, but not
limited to, the costs of responding to a release of oil to surface waters. The
OPA also requires owners and operators of offshore facilities that could be the
source of an oil spill into federal or state waters, including wetlands, to post
a bond, letter of credit or other form of financial assurance in amounts ranging
from $10 million in specified state waters to $35 million in federal outer
continental shelf waters to cover costs that could be incurred by governmental
authorities in responding to an oil spill. Such financial assurances may be
increased by as much as $150 million if a formal risk assessment indicates that
the increase is warranted. 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 will 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.

12

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

Except as discussed under "Item 3. Legal Proceedings" below, 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 a
preliminary review of local records). Investigations, including a title opinion
of local counsel, are made before commencement of drilling operations.

EMPLOYEES

At December 31, 2001, we had 31 full-time employees. We believe that our
relationships with our employees are good. None of our employees is 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

We maintain our executive offices at Chevron/Texaco Heritage Plaza, 1111
Bagby, Suite 2100, Houston, Texas. During 1997 we entered into a lease, expiring
February 3, 2003, for these offices covering 28,206 square feet of office space.
We will begin negotiations to renew our lease as well as investigate alternative
space during 2002. See Note 6 to our consolidated financial statements.

FORWARD LOOKING INFORMATION AND RISK FACTORS

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, our 3-D project
portfolio, future general and administrative expenses on a per unit of
production basis, increases in wells operated, future growth, future
exploration, future seismic data (including timing and results), expansion of
operation, generation of 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, new
credit facilities, attraction of new members to the exploration team, future
compensation programs, new focus or core areas, new prospects and drilling
locations, future capital expenditures (or funding thereof), sufficiency of
future working capital, borrowings and capital resources and liquidity,
projected cash flows from operations, expectation or timing of reaching payout,
outcome, effects or timing of any legal proceedings, drilling plans, including
scheduled and budgeted wells, 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" 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 review any forward-looking
statement, whether as a result of new information, future events, or otherwise.

13

Such statements involve risks and uncertainties, including, but not limited to,
the numerous risks and substantial and uncertain costs associated with
exploratory drilling, the volatility of oil and natural gas prices and the
effects of relatively low prices for our products, conducting successful
exploration and development in order to maintain reserves and revenue in the
future, operating risks of oil and natural gas operations, our dependence on key
personnel, our ability to utilize changing technology and the risk of
technological obsolescence, the significant capital requirements of our
exploration and development and technology development programs, governmental
regulation and liability for environmental matters, results of litigation,
management of growth and the related demands on our resources and the ability to
achieve future growth, competition from larger oil and natural gas companies,
the potential inaccuracy of estimates of oil and natural gas reserve data,
property acquisition risks, 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.

OIL AND GAS DRILLING IS A SPECULATIVE ACTIVITY AND INVOLVES NUMEROUS RISKS AND
SUBSTANTIAL AND UNCERTAIN COSTS

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. Although we believe that our use of 3-D
seismic data and other advanced technology should increase the probability of
success of our wells and should reduce average finding costs through elimination
of prospects that might otherwise be drilled solely on the basis of 2-D seismic
data and other traditional methods, drilling remains a speculative activity.
Even when fully utilized and properly interpreted, 3-D seismic data and
visualization techniques only assist geoscientists in identifying subsurface
structures and do not allow the interpreter to know if hydrocarbons will in fact
be present in such structures if they are drilled. In addition, the use of 3-D
seismic data and such technologies requires greater pre-drilling expenditures
than traditional drilling strategies and we could incur losses as a result of
such expenditures. 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. There can be no assurance that our overall
drilling success rate or our drilling success rate for activity within a
particular geographic area will not decline. Although we may discuss drilling
prospects that we have identified or budgeted for, we may ultimately not lease
or drill these prospects within the expected time frame, or at all. We may
identify prospects through a number of methods, some of which do not include
interpretation of 3-D or other seismic data. The drilling and results for these
prospects may be particularly uncertain. 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. There
can be no assurance that these projects can be successfully developed or that
the wells discussed will, if drilled, encounter reservoirs of commercially
productive oil or natural gas. There are numerous uncertainties in estimating
quantities of proved reserves, including many factors beyond our control. See
ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS -- General Overview" and ITEMS 1 AND 2. -- "BUSINESS AND
PROPERTIES -- CORE AREAS OF OPERATION."

14

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. It is impossible to predict future oil and natural gas price
movements with certainty. 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 -- General Overview" and ITEMS 1 AND 2. -- "BUSINESS AND
PROPERTIES -- OIL AND NATURAL GAS RESERVES" AND "-- MARKETING."

We review on a quarterly basis the carrying value of our oil and natural
gas properties under the applicable rules of the Commission. Under these rules,
the carrying value of proved oil and natural gas properties may not exceed the
present value of estimated future net revenue from proved reserves, discounted
at 10%. Application of this "ceiling" test generally requires pricing future
revenue at the unescalated prices in effect as of the end of each fiscal quarter
and requires a write down for accounting purposes if the ceiling is exceeded,
even if prices declined for only a short period of time. 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.

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 -- General Overview"
and ITEMS 1 AND 2. -- "BUSINESS AND PROPERTIES -- MARKETING."

MAINTAINING RESERVES AND REVENUE IN THE FUTURE DEPENDS ON SUCCESSFUL
EXPLORATION, DEVELOPMENT AND ACQUISITIONS

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.

15

WE ARE SUBJECT TO SUBSTANTIAL OPERATING RISKS

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 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."

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

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.
No assurances can be given as to the availability or terms of any such
additional financing that may be required or that financing will continue to be
available under existing or new credit facilities. 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 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 2001. Further expansion
is anticipated in 2002 both through drilling efforts and possible acquisitions.
Any future growth may place a significant strain on our financial, technical,
operational and administrative
16

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. There can be no assurance that we will
be successful in achieving growth or any other aspect of our business strategy.

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 ONLY ESTIMATES AND MAY PROVE TO BE INACCURATE

There are numerous uncertainties inherent in estimating oil and natural gas
reserves and their estimated values. The reserve data in this report represent
only estimates that may prove to be inaccurate because of these uncertainties.
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. Estimates of economically recoverable oil and natural gas reserves
depend upon a number of variable factors, such as historical production from the
area compared with production from other producing areas and assumptions
concerning effects of regulations by governmental agencies, future oil and
natural gas prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, some or all of these
assumptions may in fact vary considerably from actual results. For these
reasons, estimates of the economically recoverable quantities of oil and natural
gas attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
expected therefrom prepared by different engineers or by the same engineers but
at different times may vary substantially. 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 the Commission to be used in calculating discounted future net cash flows for
reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with us
or the oil and natural gas industry in general. See ITEMS 1 AND 2. -- "BUSINESS
AND PROPERTIES -- Oil and Natural Gas Reserves."

OUR CREDIT FACILITY HAS SUBSTANTIAL OPERATING RESTRICTIONS AND FINANCIAL
COVENANTS AND WE MAY HAVE DIFFICULTY OBTAINING ADDITIONAL CREDIT

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 both reduce debt and increase our available borrowing amounts.
There can be no assurance that, in the future, commodity prices will not
decline,

17

we will not increase our borrowings or the borrowing base will not 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 may be impaired
or such financing may be on terms unfavorable to us; 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; 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 "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- Credit Facility."

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

Our personnel have had significant acquisition experience prior to joining
Edge; however 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, which generally includes on-site
inspections and the review of reports filed with various regulatory entities,
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. There can be no assurances that any acquisition of property interests
by us will be successful and, if unsuccessful, that such failure will not have
an adverse effect on our future results of operations and financial condition.

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 4 to our consolidated financial statements.

18

WE CANNOT MARKET OUR PRODUCTION WITHOUT THE ASSISTANCE OF THIRD PARTIES

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.

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 oil and natural gas operating expenses and taxes.

19

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, 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 undeveloped 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.

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

20

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.

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 except for the litigation described below. We do not believe that the
ultimate outcome of this litigation will have a material adverse effect on us.

In October 2001, the Company was sued by certain mineral owners in its Mew
lease, upon which the Company and its partners drilled and completed the Mew No.
1 well in the Brandon Area, Duval County, Texas. The suit names the Company,
Santos USA and Mark Smith, an independent landman, as Defendants, and is filed
in the 229th Judicial District Court of Duval County, Texas. The suit seeks a
declaratory judgment to set aside certain quitclaim deeds between the Mew
lessors that were intended to result in a partition of the

21

mineral estate between the various members of the Mew family in the land where
the well is located and other lands. The pleadings allege failure of
consideration, fraud, failure to consummate the partition, bad faith trespass
and conversion. As part of the leasing effort for the prospect, some members of
the Mew family had sought to partition their minerals under the tracts where
they owned the surface in full. The Mew heirs, from whom the Company acquired
leases, could lose a portion of their mineral interest if the quitclaim deeds
are set aside. Were this to happen, it could have the effect of voiding the
Company's leases as to an undivided one-third of the unit acreage for the Mew
well and the Mew lease. Plaintiffs seek unspecified actual and exemplary damages
against the Company and Santos arising out of the alleged fraud committed by the
Company and Mark Smith. They also seek damages from Santos for the value of the
oil and natural gas produced and saved from the Mew well, or alternatively, for
the value of the oil and natural gas produced less the cost of drilling,
completing and operating the well. The Company has a 12.5% working interest in
the well. To date, the Mew well has produced $5.7 million in net revenue and has
cost $3.6 million to drill, complete and operate. Estimated gross proved
reserves are 111.6 MBbls and 4.6 Bcf. The Company has filed an answer in the
case. Santos has filed a plea of abatement asking that the case be dismissed for
failure to join necessary and indispensable parties. At this point, it is not
possible to determine the ultimate outcome of this litigation or the exposure,
if any, the Company may have.

In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil seeks
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith is made, the parties will not be able to
recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that it acted in good faith and intends to
vigorously defend its position. The Company, along with GMT and the other
partners, are attempting to negotiate a settlement with ExxonMobil that would
allow GMT et al (including the Company) to participate for their respective
shares of a 23% working interest in the Neblett unit, and would allow for the
recovery of well costs. If the case cannot be settled and the title issue is
decided unfavorably, the Company believes that it will ultimately be able to
recover its costs as a good faith trespasser. Due to the uncertainty of the
final outcome, the Company has ceased to record revenue from the properties as
of August 1, 2001, which net to the Company averaged approximately 1.4 MMcfe/d
of production at the time the well was shut-in. In addition, the Company removed
associated reserves of 1.4 Bcfe from its total proved reserves. The Company
believes this potential loss is not material to its financial condition or
results of operations.

The Company, as one of three original plaintiffs, filed a lawsuit against
BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD, Pagenergy Company,
LLC and Gap Marketing Company, LLC, as defendants, in the 229th Judicial
District Court of Duval County, Texas, for fraud and breach of contract in
connection with an agreement whereby BNP was obligated to drill a test well in
an area known as the Slick Prospect in Duval County, Texas. The allegations of
the Company in this litigation were, in general, that BNP gave the Company
inaccurate and incomplete information on which the Company relied in entering
into the transaction and in making its decision not to participate in the test
well and the prospect, resulting in the loss of the Company's interest in the
lease, the test well and four subsequent wells drilled in the prospect. The
Company sought to enforce its interest in the prospect and sought damages or
rescission, as well as costs and attorneys' fees. The case was originally filed
in Duval County, Texas on February 25, 2000. The Company filed a lis pendens to
protect its interest in the real property at issue.

22

In mid-March, 2000, the defendants filed an original answer and certain
counterclaims against plaintiffs, seeking unspecified damages for slander of
title, tortious interference with business relations and exemplary damages. The
case proceeded to trial before the court (without a jury) on June 19, 2000,
after the plaintiffs were found by the court to have failed to comply with
procedural requirements regarding the request for a jury. After several days of
trial, the case was recessed and later resumed on September 5, 2000. The court
at that time denied the plaintiffs' motion for mistrial based on the court's
denial of a jury trial. The court also ordered that the defendants'
counterclaims would be the subject of a separate trial that would commence on
December 11, 2000. The parties proceeded to try issues related to the
plaintiffs' claims on September 5-13, 2000. Defendants filed a second amended
answer and counterclaim and certain supplemental responses to a request for
disclosure in which they stated that they were seeking damages in the amount of
$33.5 million by virtue of an alleged lost sale of the subject properties, $17
million in alleged lost profits from other prospective contracts, and
unspecified incidental and consequential damages from the alleged wrongful
suspension of funds under their gas sales contract with the gas purchaser on the
properties, alleged damage to relationships with trade creditors and financial
institutions, including the inability to leverage the Slick Prospect, and
attorneys' fees at prevailing hourly rates in Duval County, Texas incurred in
defending against plaintiffs' claims and for 40% of any aggregate recovery in
prosecuting their counterclaims. In subsequent deposition testimony, the
defendants verbally alleged $26 million of damages by virtue of the alleged lost
sale of the properties (as opposed to the $33.5 million previously sought), $7.5
million of damages by virtue of loss of a lease development opportunity and $100
million of damages by virtue of the loss of a business opportunity related to
BNP's alleged inability to participate in a 3-D seismic project.

The Company also alleged that BNP, Seiskin Interests, LTD and Pagenergy
Company, LLC breached a confidentiality agreement with the plaintiffs by
obtaining oil and gas leases within an area restricted by that contract. This
breach of contract allegation is the subject of an additional lawsuit by
plaintiffs in the 165th District Court in Harris County, Texas. In this separate
action, the Company is seeking damages as a result of defendants' actions as
well as costs and attorneys' fees.

During the week of December 11-15, 2000, in Duval County BNP tried its
counterclaims against Edge, and Edge presented its defenses to the
counterclaims. BNP presented evidence that its damages were in the amounts of
$19.6 million for the alleged lost sale of the properties, $35 million for the
alleged loss of the lease development opportunity, and $308 million for the
alleged loss of the opportunity related to participation in the 3-D seismic
project. During the course of the trial, Edge presented its motion for summary
judgment on the counterclaims based on the doctrine of absolute judicial
proceeding privilege. The judge partially granted Edge's motion for summary
judgment as it related to the filing of the lis pendens, but denied it with
regard to the other allegations of BNP. The judge also granted Edge's plea in
abatement relating to the breach of the confidentiality agreement, ruling that
the District Court in Harris County has dominant jurisdiction of that issue.

On November 5, 2001, the court filed with the clerk and provided to the
Company a final judgment that had been signed by the court, but not provided to
the Company, on October 26, 2001. Pursuant to the terms of the judgment, the
Company takes nothing on its claims against BNP and is denied any recovery of
its interest in the lease, the prospect, or the wells of the Slick Prospect.
Instead, the court confirmed title in the lease, prospect, and wells in BNP's
affiliate. In addition, the Company was found to have tortiously and maliciously
interfered with two different BNP contracts or prospective contracts, and BNP
was awarded actual damages against the Company in the amount of $10 million and
punitive damages in the amount of $5.1 million. The judgment does not reflect a
credit in the amount of $1,945,000 to which the Company believes that it is
entitled by reason of certain settlements by its two co-plaintiffs and
co-counterdefendants.

On December 6, 2001, the Company agreed to settle this litigation. Pursuant
to the settlement, the Company agreed to pay $2.5 million and to release its
claims to interest in an area known as the Slick Prospect in Duval County,
Texas. The parties to the settlement agreed to the dismissal of all claims, both
in the 229th Judicial District Court of Duval County, Texas and in the 165th
District Court in Harris County, Texas. The parties also agreed to set aside the
judgment of the 229th Judicial District Court of Duval County, Texas against the
Company and to a mutual release of all claims.

23

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

No matters were submitted during the fourth quarter of the fiscal year
covered by this report to a vote of security holders, through the solicitation
of proxies or otherwise.

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. Mr. Elias is a member of the
Nominating Committee of the Board. 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 61 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. Mr. Long received a B.A. in Political Science and a M.S. in Economics
from the University of Illinois. Mr. Long is 49 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 38 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.

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.

KIRSTEN A. HINK has served as Controller of the Company since December 31,
2000 and prior to that served as Assistant Controller from June 2000 to December
2000. She served as Controller of Benz Energy Inc., an oil and gas exploration
company, from 1998 to June 2000. Prior thereto she served in financial and SEC
reporting positions with Western Atlas, Inc. and Apache Corporation. Mrs. Hink
received a B.S. in Accounting from Trinity University, San Antonio, Texas. Mrs.
Hink is a Certified Public Accountant in the State of Texas.

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

24

with Raymond James and Associates, Inc. From February 1990 to October 1999, Mr.
MacLeod was a principal with Kirkpatrick Energy Associates, Inc. where he 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.

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.

PART II

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

As of March 15, 2002, we estimate there were approximately 3,618 beneficial
holders of our Common Stock. Our Common Stock is listed on the NASDAQ National
Market ("NASDAQ") and traded under the symbol "EPEX". As of March 15, 2002, we
had 9,351,215 shares outstanding and our closing price on NASDAQ was $5.30 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. The payment of future dividends 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 -- "FORWARD LOOKING INFORMATION AND RISK
FACTORS -- We do not intend to pay dividends and our ability to pay dividends is
restricted".

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 "Management's Discussion and

25

Analysis of Financial Condition and Results of Operations" and our financial
statements and notes thereto, which follow:

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

(1) Certain prior year balances have been reclassified to conform to the current
year presentation.

(2) 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 when the daily average market price of
our stock exceeded the strike price of certain options. 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.

(3) Basic and diluted earnings (loss) per share has been computed based on the
net income (loss) shown above and assuming the 4,701,361 shares of Common
Stock issued in connection with the Combination (as defined below in ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS -- "General Overview" ) were outstanding for all periods prior to
the Combination, effective March 3, 1997.

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

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 Data 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.

27

GENERAL OVERVIEW

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 for 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 have evolved over that time from a prospect generation organization
focused solely on high-risk, high-reward exploration 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 disciplined style of business
planning and management was integrated into our technology-driven drilling
activities. After giving effect to the time needed to make those changes, there
have been significant activities that have resulted in growth in reserves,
production and financial strength.

We use the full-cost method of accounting for our oil and natural gas
properties. Under this method, all acquisition, exploration and development
costs, including certain general and administrative costs that are directly
attributable to our acquisition, exploration and development activities, are
capitalized in a "full-cost pool" as incurred. We record depletion of our
full-cost pool using the unit of production method. Investments in unproved
properties are not subject to amortization until the proved reserves associated
with the projects can be determined or until impaired. To the extent that
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, 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. For each of the years ended December 31, 2001,
2000 and 1999, respectively, no full cost ceiling test write down was necessary.

Due to the instability of oil and natural gas prices, we have entered 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 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. Our hedging arrangements typically apply to only a portion of
our production, providing only partial price protection against declines in oil
and natural gas prices. We account for these transactions as hedging activities
and, accordingly, gains and losses are included in oil and natural gas revenue
during the period the hedged production occurs. At December 31, 2001, we were
not a party to any hedging transactions. At December 2000, a natural gas collar
was in place. The natural gas collar covered 4,000 MMbtus per day for the period
January 1, 2001 to December 31, 2001 at a $4.50 per MMbtu floor and a $6.70 per
MMbtu ceiling. On January 3, 2001, we closed out the hedge for the period
February 1, 2001 to December 31, 2001 at a cost of $547,760. At December 31,
2000 and 1999, the fair value, gain (loss), of outstanding hedges was
approximately $(1.1) million and $15,000, respectively. (See Note 5 to our
consolidated financial statements).

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.

28

RESULTS OF OPERATIONS

YEAR ENDED DECEMBER 31, 2001 COMPARED TO THE YEAR ENDED DECEMBER 31, 2000

Revenue and Production

Oil and natural gas revenue increased 25% from $23.8 million in 2000 to
$29.8 million in 2001. For 2001, natural gas production comprised 86% of total
production and contributed 88% of total revenue, oil and condensate comprised
10% of total production and contributed 9% of total revenue, and NGL's comprised
4% of total production and contributed 3% of total revenue. For 2000, natural
gas production comprised 83% of total production and 84% of total revenue while
oil and condensate production accounted for 9% of total production and 11% of
revenue and NGLs production comprised 8% of total production and 5% of oil and
gas 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, 2001 and 2000.

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

(1) Includes the effect of hedging.

Natural gas revenue increased 31% from $20.0 million for the year ended
December 31, 2000 to $26.2 million for 2001. Increased production and the
favorable impact of higher natural gas prices were partially offset by the
impact of a hedging loss. For the year ended December 31, 2001, natural gas
production increased 19% from 14.2 Mcf/d in 2000 to 17.0 Mcf/d in 2001 resulting
in an increase in revenue of approximately $4.1 million (based on 2000
comparable period prices). The average natural gas sales price for production in
2001 was $4.32 per Mcf, exclusive of hedging activity, compared to $4.14 per Mcf
for 2000, exclusive of hedging activity. This increase in average price realized
resulted in increased revenue of approximately $1.1 million (based on current
year production). Included within natural gas revenue for the year ended
December 31, 2001 and 2000 was $(0.9) million and $(1.5) million, respectively,
representing losses from hedging activity. These losses decreased the effective
natural gas sales price by $(0.15) per Mcf and $(0.30) per Mcf, for the years
ended December 31, 2001 and 2000, respectively.

29

Revenue from the sale of oil and condensate totaled $2.8 million for the
year ended December 31, 2001, an increase of 9% from the prior year total of
$2.5 million. The year ended December 31, 2000 included net losses from oil
hedge activity of $223,455. No oil hedges were in place for 2001. Production
volumes for oil and condensate increased 19% to 317 Bbls/d for the year ended
December 31, 2001 compared to 265 Bbls/d for the same prior year period. The
increase in oil and condensate production caused an increase in revenue of
approximately $535,300 (based on 2000 comparable period average prices). The
average realized price for oil and condensate for the year ended December 31,
2001 was $23.94 per barrel compared to $28.47 per barrel, excluding the impact
of net oil hedge losses of $(2.31) per barrel, in 2000. Lower average prices for
the year 2001 resulted in a decrease in revenue of $524,000 (based on current
year production).

Revenue from the sale of NGLs totaled $0.8 million for the year ended
December 31, 2001, a decrease of 36% from the 2000 total of $1.3 million.
Production volumes for NGLs for the year ended December 31, 2001 decreased 41%,
from 210 Bbls/d to 125 Bbls/d, as compared to the year ended December 31, 2000.
The decrease in NGL production decreased revenue by $509,600 (based on 2000
comparable period average prices). This decrease in production was largely due
to high natural gas prices decreasing the economic value of NGL's and a
resulting decision by management not to process our gas during several months of
2001. Favorable pricing for the year ended December 31, 2001 resulted in an
increase in revenue of $62,500 (based on current year production). The average
realized price for NGLs for the year ended December 31, 2001 was $17.74 per
barrel compared to $16.37 per barrel for the same period in 2000.

Production of oil and natural gas was significantly impacted by our
drilling results in the second half of 2000 and in 2001. We successfully drilled
and completed 17 gross (7.081 net) wells in the year ended December 31, 2001
that added additional production and revenue for 2001. Gas production increases
were due primarily to the drilling of, and strong performance from, the O'Connor
Ranch wells, the Ibarra and La Jolla Parr wells on our La Jolla prospect, the
Mire #1 well on our Horeb prospect and the Robertson #1 well on our Duson Frio
prospect. Partially offsetting the favorable results of drilling were production
declines on our older wells, primarily the Margo #1 and #2 wells.

Costs and Operating Expenses

Operating expenses for the year ended December 31, 2001 totaled $2.8
million compared to $2.0 million in the same period of 2000, an increase of 44%.
Current year results were impacted by the increased number of wells operating in
2001 compared to the prior year as well as higher treating costs at the Austin
facility for a portion of 2001, higher salt water disposal costs on our older
wells, and higher well control insurance costs incurred in 2001 compared to the
prior year. Operating expenses averaged $0.39 per Mcfe for the year ended
December 31, 2001 compared to $0.31 per Mcfe for the prior year period. The
increase in operating expenses on a Mcfe basis was due to the factors resulting
in an overall increase in operating expenses described previously.

Severance and ad valorem taxes for the year ended December 31, 2001
increased 9% from $2.0 million in 2000, to $2.2 million in 2001, due to higher
severance taxes paid on the increased revenue, primarily in the first quarter of
2001. On an equivalent basis, severance and ad valorem taxes were $0.30 per Mcfe
and $0.32 per Mcfe for the years ended December 31, 2001 and 2000, respectively.

Depletion, depreciation and amortization expense ("DD&A") for the year
ended December 31, 2001 totaled $9.4 million compared to $7.6 million for the
year ended December 31, 2000. Full cost DD&A on our oil and natural gas
properties totaled $8.7 million for 2001 compared to $7.0 million in 2000.
Depletion expense on a unit of production basis for the year ended December 31,
2001 was $1.22 per Mcfe, 10% higher than the 2000 rate of $1.11 per Mcfe. The
higher depletion rate per Mcfe resulted in an increase in depletion expense of
$0.8 million. For the year ended December 31, 2001, higher oil and natural gas
production compared to the prior year period resulted in an increase in
depletion expense of $1.0 million. The increase in the depletion rate was
primarily due to a higher amortizable base in 2001 compared to the prior year.

In December 2001, we recorded costs of $3.5 million related to the
settlement of our litigation with BNP. See Note 6 to our consolidated financial
statements.

30

General and administrative expenses ("G&A") for the year ended December 31,
2001, excluding the deferred compensation expense discussed below, totaled $5.0
million, a 32% increase from the 2000 total of $3.8 million. The increase in
costs was due primarily to bad debt expense of $525,000 reserved in 2001
($225,000 of which related to purchases by an Enron affiliate), costs of
$100,000 to purchase options from a former employee, higher salaries and related
benefits, and higher legal and audit fees. For the years ended December 31, 2001
and 2000, G&A costs were reduced by overhead reimbursement fees of approximately
$137,200 and $120,300, respectively. G&A on a unit of production basis for the
year ended December 31, 2001 was $0.70 per Mcfe ($0.62 per Mcfe excluding the
bad debt expense and the purchase of options) compared to $0.61 per Mcfe for the
comparable 2000 period.

Deferred compensation cost reported in accordance with FASB Interpretation
No. (FIN) 44, Accounting for Certain Transactions involving Stock Compensation
was a credit of $(850,281) for the year ended December 31, 2001 compared to a
charge of $899,548 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 as
necessary to comply with FIN 44. 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 options newly
issued in conjunction with the repricing.

Also included in deferred compensation is amortization related to
restricted stock awards granted during 2000 and 2001. For the years ended
December 31, 2001 and 2000, such amortization totaled $353,371 and $105,250,
respectively.

No unearned compensation was reported in 2001. Unearned compensation
expense for the year ended December 31, 2000 totaled $22,696 and relates to
restricted stock granted to executives at the completion of the Offering.

Included in other income (expense) was interest expense of $214,619 for the
year ended December 31, 2001 compared to $171,783 in the same 2000 period.
Interest expense, including facility fees, was $137,623 for the year 2001 on
weighted average debt of $0.7 million compared to interest expense of $546,340
on weighted average debt of approximately $5.6 million for the same prior year
period. Also included in interest expense for the years ended December 31, 2001
and 2000 was $101,398 and $24,720, respectively, representing amortization of
deferred loan costs associated with a new credit facility. Capitalized interest
for the year ended December 31, 2001 totaled $24,402 compared to $399,277 in the
prior year. The reduction in capitalized interest resulted from lower interest
costs incurred during the year ended December 31, 2001 compared to the same
prior year period. Although gross interest expense has decreased compared to the
prior year, the effect of less interest being capitalized to oil and natural gas
properties has resulted in higher net interest costs reported in our results of
operations.

Interest income totaled $127,717 for the year ended December 31, 2001
compared to $97,860 for the same period in 2000. The increase in interest income
is due to the overall increase in funds invested in overnight money market
funds.

Other income (expense) for the year ended December 31, 2000 also included a
loss on the sale of our investment in Frontera of $(354,733) or $(0.04) per
share.

An income tax benefit was recorded for the year ended December 31, 2001 of
$818,897. As of December 31, 2001, approximately $18.2 million of net operating
loss carryforwards have been accumulated that begin to expire in 2012. Based on
our year-end 2001 projections, we now believe that we will fully realize our
recorded tax assets. Accordingly, $818,897 in associated valuation reserves was
reversed in 2001. Future financial statement income will necessitate income tax
provisions at our effective rate. Currently, we do not anticipate a federal tax
liability or making federal tax payments in 2002. For the year ended December
31,

31

2000, no tax expense or benefit was recorded because an allowance was provided
to offset the tax benefits of certain tax assets.

For the year ended December 31, 2001, the Company had net income of $8.1
million, or $0.87 basic earnings per share, as compared to net income of $6.9
million, or $0.75 basic earnings per share, in 2000.

Weighted average shares outstanding increased from approximately 9.2
million for the year ended December 31, 2000 to 9.3 million in the comparable
2001 period. The increase was due primarily to options exercised and vesting of
restricted stock during 2001.

YEAR ENDED DECEMBER 31, 2000 COMPARED TO THE YEAR ENDED DECEMBER 31, 1999

Revenue and Production

Oil and natural gas revenue increased 64% from $14.5 million in 1999 to
$23.8 million in 2000. For 2000, natural gas production comprised 83% of total
production and contributed 84% of total revenue, oil and condensate comprised 9%
of total production and contributed 11% of total revenue, and NGL's comprised 8%
of total production and contributed 5% of total revenue. For 1999, natural gas
production comprised 83% of total production and 81% of total revenue while oil
and condensate production accounted for 10% of total production and 13% of
revenue and NGLs production comprised 7% of total production and 6% of oil and
gas 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, 2000 and 1999.

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

(1) Includes the effect of hedging.

Natural gas revenue increased 70% from $11.8 million for the year ended
December 31, 1999 to $20.0 million for 2000. The favorable impact of higher
natural gas prices was partially offset by the impact of hedging losses and
decreased production. The average natural gas sales price for production in 2000
was $4.14 per Mcf, exclusive of hedging activity, compared to $2.26 per Mcf for
1999, exclusive of hedging activity. This increase in average price realized
resulted in increased revenue of approximately $9.7 million (based on current
year production). Included within natural gas revenue for the year ended
December 31, 2000 and 1999

32

was $(1.5) million and $(1.1) million, respectively, representing losses from
hedging activity. These losses decreased the effective natural gas sales price
by $(0.30) per Mcf and $(0.19) per Mcf, for the years ended December 31, 2000
and 1999, respectively. For the year ended December 31, 2000, natural gas
production decreased 8% from 15.6 Mcf/d in 1999 to 14.2 Mcf/d in 2000 resulting
in a decrease in revenue of approximately $1.1 million (based on 1999 comparable
period prices).

Revenue from the sale of oil and condensate totaled $2.5 million for the
year ended December 31, 2000 (including net losses from oil hedge activity of
$223,454), an increase of 40% from the prior year total of $1.8 million.
Favorable pricing for the year 2000 resulted in an increase in revenue of $1.2
million (based on current year production). The average realized price for oil
and condensate for the year ended December 31, 2000 was $28.47 per barrel,
excluding the impact of net oil hedge losses of $(2.31) per barrel, compared to
$16.15 per barrel for the same period in 1999. Production volumes for oil and
condensate decreased 14% to 265 Bbls/d for the year ended December 31, 2000
compared to 307 Bbls/d for the same prior year period. The decrease in oil and
condensate production caused a decrease in revenue of approximately $244,900
(based on 1999 comparable period average prices).

Revenue from the sale of NGLs totaled $1.3 million for the year ended
December 31, 2000, an increase of 38% from the 1999 total of $913,462. Favorable
pricing for the year ended December 31, 2000 resulted in an increase in revenue
of $323,500 (based on current year production). The average realized price for
NGLs for the year ended December 31, 2000 was $16.37 per barrel compared to
$12.16 per barrel for the same period in 1999. Production volumes for NGLs for
the year ended December 31, 2000 increased 2%, from 206 Bbls/d to 210 Bbls/d, as
compared to the year ended December 31, 1999. The increase in NGL production
increased revenue by $20,700 (based on 1999 comparable period average prices).

Production of oil and natural gas was significantly impacted by the sale of
certain oil and natural gas properties effective July 1, 1999 and April 1, 2000.
Offsetting these declines was the adjustment in June 2000 for 19 months of
revenue associated with payout on our McFaddin properties that reached payout in
July 1998, but was not determined until June 2000. This adjustment resulted in
recognition in 2000 of $391,300 on production of 173,800 Mcfe. In addition, we
successfully drilled and completed 24 gross (9.06 net) wells in the year ended
December 31, 2000 that added additional production and revenue for the current
year period.

Costs and Operating Expenses

Operating expenses for the year ended December 31, 2000 totaled $2.0
million compared to $1.7 million in the same period of 1999, an increase of 13%.
Results for 2000 were impacted by the recording in June 2000 of 19 months of
lifting costs totaling approximately $119,000, associated with our McFaddin
properties that reached payout in July 1998 but was not determined until June
2000. In addition, 2000 costs increased due to compression charges and salt
water disposal costs on certain older properties. These additional costs more
than offset the effect of lower costs resulting from the disposition of proved
producing properties effective July 1, 1999, and corporate efforts focused on
improving the operating structure in the field. Operating expenses averaged
$0.31 per Mcfe for the year ended December 31, 2000 compared to $0.26 per Mcfe
for the prior year period. The increase in operating expenses on a Mcfe basis
was due to the factors resulting in an overall increase in operating expenses
described previously and the sale of certain properties during the third quarter
of 1999 that had lower overall average operating costs.

Severance and ad valorem taxes for the year ended December 31, 2000
increased 54% from $1.3 million in 1999 to $2.0 million in 2000 due primarily to
higher severance taxes paid on the increased revenue, primarily in the fourth
quarter of 2000. On an equivalent basis, severance and ad valorem taxes were
$0.32 per Mcfe and $0.19 per Mcfe for the years ended December 31, 2000 and
1999, respectively.

Depletion, depreciation and amortization expense ("DD&A") for the year
ended December 31, 2000 totaled $7.6 million compared to $8.5 million for the
year ended December 31, 1999. Full cost DD&A on our oil and natural gas
properties totaled $7.0 million for 2000 compared to $7.8 million in 1999.
Depletion expense on a unit of production basis for the year ended December 31,
2000 was $1.11 per Mcfe, 3% lower than the 1999 rate of $1.15 per Mcfe. For the
year ended December 31, 2000, lower oil and natural gas

33

production compared to the prior year period resulted in a decrease in depletion
expense of $218,400. The decrease in the depletion rate was primarily due to
year-end reserve base additions and revisions.

General and administrative expenses ("G&A") for the year ended December 31,
2000, excluding the deferred compensation expense discussed below, totaled $3.8
million, a 16% decrease from the 1999 total of $4.5 million. The decrease in
costs was due primarily to lower salaries and related benefits attributable to a
work force reduction during January 2000. For the year ended December 31, 2000
and 1999, G&A was reduced by overhead reimbursement fees of approximately
$120,300 and $285,000, respectively. G&A on a unit of production basis for the
year ended December 31, 2000 was $0.61 per Mcfe compared to $0.67 per Mcfe for
the comparable 1999 period.

A non-cash charge to compensation expense of $899,548, or $0.10 per share,
was required in 2000 in accordance with FASB Interpretation No. (FIN) 44,
"Accounting for Certain Transactions involving Stock Compensation." FIN 44
requires, among other things, a non-cash charge to compensation expense if the
price of Edge's 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 as necessary to comply with FIN 44. The charge was related to
non-qualified stock options granted to employees and directors in prior years
and re-priced in May of 1999, as well as certain options newly issued in
conjunction with the repricing.

Also included in deferred compensation for the year ended December 31, 2000
is amortization of $105,250 related to restricted stock awards granted during
2000.

Unearned compensation expense for the year ended December 31, 2000 totaled
$22,696 compared to $349,623 in the prior year period. The amortization of
unearned compensation expense is recognized from restricted stock granted to
executives at the completion of the Offering. The decrease was due to the
resignation of the former President and Chief Operating Officer in December 1999
at which time he vested in his remaining restricted stock grant. We charged to
expense the unamortized unearned compensation associated with his restricted
stock upon his resignation.

The other charge during 1999 of approximately $1.7 million primarily
represented expenses incurred as a result of the resignation of our former
President and Chief Operating Officer in 1999. As a result of his resignation we
recorded a one-time charge of approximately $1.5 million to satisfy corporate
obligations under his employment contract. Included in the $1.5 million was a
$1.1 million non-cash amount relating to the vesting of the remaining balance of
the executive's restricted common stock award granted concurrent with our
Offering (see Note 9 to our consolidated financial statements). The balance of
the charge primarily represented an accrual for workforce reduction and cash
payments to be paid to the former executive from the date of his resignation to
December 31, 2000.

Other income (expense) for the year ended December 31, 2000 consisted
primarily of a loss on the sale of our investment in Frontera of $(354,733).

Also included in other income (expense) was interest expense of $171,783
for the year ended December 31, 2000 compared to $130,067 in the same 1999
period. Interest expense was $546,340 for the year 2000 on weighted average debt
of $5.6 million compared to interest expense of $662,067 on weighted average
debt of approximately $8.4 million for the same prior year period. Also included
in interest expense for the year ended December 31, 2000 was $24,720
representing amortization of deferred loan costs associated with a new credit
facility. Capitalized interest for the year ended December 31, 2000 totaled
$399,277, a decrease of 25% over the prior year amount of $532,000 for the same
period. The reduction in capitalized interest resulted from lower exploration
activities during the year ended December 31, 2000 compared to the same prior
year period. Although interest expense has decreased compared to the prior year,
the effect of less interest being capitalized to oil and natural gas properties
has resulted in higher net interest costs reported in our results of operations.

34

Interest income totaled $97,860 for the year ended December 31, 2000
compared to $51,855 for the same period in 1999. The increase in interest income
is due to the overall increase in funds invested in overnight money market
funds.

Due to our significant deferred tax assets, no tax expense was recorded for
the year ended December 31, 2000 or 1999. Because of the uncertainty at December
31, 2000 and 1999 as to whether we would have future profitability, an allowance
was provided to offset the tax benefits of certain tax assets.

For the year ended December 31, 2000 we had net income of $6.9 million, or
$0.75 basic earnings per share, as compared to a net loss of $(3.7) million, in
1999.

Weighted average shares outstanding increased from approximately 8.7
million for the year ended December 31, 1999 to 9.2 million in the comparable
2000 period. The increase was due primarily to the private placement of 1.4
million shares of common stock in May 1999.

LIQUIDITY AND CAPITAL RESOURCES

In March 1997, we completed the Offering of 2,760,000 shares of our common
stock at a public offering price of $16.50 per share. The Offering provided us
with proceeds of approximately $40 million, net of expenses. We used
approximately $12.7 million to repay our long-term outstanding indebtedness
incurred under our revolving credit facility in place at the time, subordinated
loans and equipment loans. The remaining proceeds from the Offering, together
with cash flows from operations, were used to fund capital expenditures,
commitments, and other working capital requirements and for general corporate
purposes.

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. At our
election, 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 proceeding 20 consecutive trading days exceeds $10.70.
No warrants have been exercised as of December 31, 2001. 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.

We had cash and cash equivalents at December 31, 2001 of $793,287
consisting primarily of short-term money market investments, as compared to
$247,981 at December 31, 2000. Working capital was $0.7 million as of December
31, 2001, as compared to $2.9 million at December 31, 2000. Excluding the
current portion of long-term debt, working capital was $5.9 million at December
31, 2000.

Cash flows provided by operations were $22.2 million, $9.6 million and $5.6
million, for the years ended December 31, 2001, 2000, and 1999, respectively.
The significant increase in cash flows provided by operations for the year ended
December 31, 2001 is primarily due to higher net income in 2001, lower accounts
receivable balances at December 31, 2001 compared to the prior year and higher
accrued liabilities at the current year-end. High commodity prices during the
fourth quarter of 2000 resulted in substantial accounts receivable balances for
production revenue received in 2001 but prices were significantly lower at
December 31, 2001 resulting in lower accounts receivable balances. Operating
cash flows, before changes in working capital, for the years ended December 31,
2001, 2000 and 1999 were $16.8 million, $16.0 million and $6.3 million,
respectively. The increase in operating cash flows from 2000 to 2001 was due
primarily to higher oil and natural gas revenue partially offset by increased
operating costs, including the $3.5 million litigation settlement in December
2001. The increase from 1999 to 2000 was due primarily to higher oil and natural
gas revenue during 2000 as a result of higher production and average commodity
prices.

35

We reinvest a substantial portion of our cash flows in our drilling,
acquisition, land and geophysical activities. As a result, we used $29.0 million
in investing activities during 2001, all of which were capital expenditures.
Capital expenditures of $15.9 million were attributable to the drilling of 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 in
expenditures was attributable to land holdings, including $2.6 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, 2000, we used $5.4 million in investing
activities, including capital expenditures of $10.7 million. Capital
expenditures of $5.7 million were attributed to drilling 26 gross wells, 24 of
which were successful. Capital expenditures of $3.2 million were attributable to
land holdings and $1.8 million was attributable to increased seismic data and
other geological and geophysical expenditures. These expenditures were offset by
proceeds from the sale of oil and natural gas properties of $1.8 million and net
proceeds from the sale of our investment in Frontera of $3.5 million.

During the year ended December 31, 1999, we used $7.3 million of cash in
investing activities including capital expenditures of approximately $14.6
million. Capital expenditures of $6.7 million were attributed to the drilling of
19 gross wells, 14 of which were successful. Capital expenditures of $2.7
million were attributable to increased land holdings and $5.1 million was
attributable to increased seismic data and other geologic and geophysical
expenditures. Capital expenditures of approximately $100,000 were used for the
acquisition of computer hardware and office equipment. Capital expenditures were
offset by proceeds from the sale of oil and natural gas prospects of $3.5
million. During August 1999, we completed a transaction in which we sold,
effective July 1, 1999, our working interests in proved producing and
undeveloped properties within our BTA and Spartan Extension 3-D project areas in
Goliad and Victoria Counties, Texas. Proceeds from the sale were approximately
$4.0 million.

Pursuant to a rights offering conducted by Frontera in November 1998, we
agreed to purchase 44,027 shares of Frontera Common Stock plus such additional
shares, if necessary, to maintain our then current 8.73% interest of the
partially diluted outstanding Frontera Common Stock (assuming conversion of all
preferred stock). As a result, we paid Frontera $116,671 in December 1998 for
44,027 shares of Frontera Common Stock, $5,626 in January 1999 for 2,123 shares
of Frontera Common Stock and $116,672 in April 1999 for 44,027 shares of
Frontera Common Stock bringing our total investment in Frontera to $3,867,233.
We sold our interest in Frontera in June 2000 for net proceeds of $3.5 million.

We currently anticipate capital expenditures in 2002 to be approximately
$18 million. Approximately $10.8 million is allocated to our expected drilling
and production activities; $4.2 million is allocated to land and seismic
activities; and $3.0 million relates to capitalized interest and G&A and other.
We plan to fund these expenditures largely from 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, if required, through additional debt and equity
financings.

Cash flows provided by financing activities totaled $7.4 million for the
year ended December 31, 2001 including $11.0 million in borrowings and $4.0
million in repayments under our current credit facility. In addition, we
received $390,421 in proceeds from the issuance of common stock related to
options exercised in 2001. Cash flows used in financing activities in 2000 were
$(4.0) million, including borrowings of $5.4 million and repayments of $9.2
million under our revolving credit facility and the predecessor facility. We
also incurred loan costs of approximately $202,900 in establishing our new
credit facility. Financing activities during 1999 were comprised of a private
offering of common stock that generated net proceeds of $7.4 million offset by a
net repayment of debt of $5.7 million.

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 2002 capital expenditures,
commitments and working capital requirements through cash flows from operations,
and to the extent necessary other financing activities. The projected 2002 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

36

capital resources and liquidity sufficient to fund our capital expenditures and
meet such financial obligations as they come due. 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 -- FORWARD LOOKING
INFORMATION AND RISK FACTORS -- Significant Capital Requirements."

Credit Facility

In October 2000, we entered into a new credit facility (the "Credit
Facility") with a bank. Borrowings under the Credit Facility bear interest at a
rate equal to prime plus 0.50% or LIBOR plus 2.75%. As of December 31, 2001,
$10.0 million in borrowings were outstanding under the Credit Facility. The
Credit Facility matures October 6, 2003 and is secured by substantially all of
our assets. Proceeds from the borrowings in 2001 under the Credit Facility were
used to fund the December 2001 property acquisition and the payment to BNP for
the litigation settlement.

Originally the borrowing base under the Credit Facility was $5 million and
was subject to automatic reductions at a rate of $300,000 per month beginning
October 31, 2000. In March 2001, the Credit Facility was amended to increase the
borrowing base to $14 million, and to eliminate the $300,000 per month automatic
reduction. In January 2002, the borrowing base was increased to $18 million. The
borrowing base will be re-determined again during the second quarter of 2002 and
is expected to include adjustments for the recent success of the Thibodeaux well
in Louisiana, other drilling successes and the acquisition in late December 2001
of properties in South Texas that were not factored into the January 2002
borrowing base of $18 million, offset in part by ordinary declines in reserves
from production.

The Credit Facility provides for certain restrictions, including but not
limited to, limitations on additional borrowings and issues of capital stock,
sales of oil and natural gas properties or other collateral, 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 EBITDA to Interest
Expense Ratio requires that (a) our consolidated EBITDA, as defined in the
agreement, 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 Allowable Expenses ratio
requires that (a) the aggregate amount of our year-to-date consolidated general
and administrative expenses for the period from January 1 of such year through
the fiscal quarter then ended to (b) our year-to-date consolidated oil and gas
revenues, net of hedging activity, for the period from January 1 of such year
through the fiscal quarter then ended, to be less than 0.40 to 1.0.

ACCOUNTING PRONOUNCEMENTS

Derivatives We adopted Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities"
("SFAS 133") effective January 1, 2001. The statement, as amended, 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 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.

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. In all other situations in which hedge accounting is discontinued,
the derivative will be carried at fair value on the balance sheet with future
changes in its fair value recognized in earnings prospectively.

37

We account for our natural gas and crude oil hedge derivative instruments
as cash flow hedges under SFAS 133. Although the fair value of our derivative
instruments fluctuates daily, as of January 1, 2001, the fair value of our
natural gas hedge derivative instruments was approximately ($1.1) million, which
was recorded in the Consolidated Balance Sheet on January 1, 2001. The ($1.1)
million was recorded as a liability on our balance sheet as part of the
transition adjustment related to our adoption of SFAS 133. The offset to this
balance sheet adjustment was a decrease to "Accumulated Other Comprehensive
Income", a component of stockholders' equity. In early January 2001, we closed
out of our hedge obligation for the period from February 1, 2001 to December 31,
2001. In accordance with SFAS 133, the cost to close out of the hedge was
recognized in net income over the period in which the hedged production
occurred. As of December 31, 2001, the full loss from the close out of $547,760
has been recorded to net income. As of December 31, 2001, we were not a party to
any hedging activity.

On June 29, 2001, the Financial Accounting Standards Board ("FASB")
approved its proposed SFAS No. 141, ("SFAS 141") "Business Combinations," and
SFAS No. 142 ("SFAS 142"), "Goodwill and Other Intangible Assets." Under SFAS
141, all business combinations should be accounted for using the purchase method
of accounting; use of the pooling-of-interests method is prohibited. The
provisions of the statement will apply to all business combinations initiated
after June 30, 2001.

SFAS 142 will apply to all acquired intangible assets whether acquired
singly, as part of a group, or in a business combination. The statement will
supersede Accounting Principals Board, ("APB"), Opinion No. 17, "Intangible
Assets," and will carry forward provisions in APB Opinion No. 17 related to
internally developed intangible assets. Under this statement, goodwill will no
longer be amortized but will be subject to annual impairment analysis. All of
the provisions of the statement should be applied in fiscal years beginning
after December 15, 2001 to all goodwill and other intangible assets recognized
in an entity's statement of financial position at that date, regardless of when
those assets were initially recognized. We do not have any goodwill or
intangible assets recorded as of December 31, 2001.

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." The statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement of
obligations of tangible long-lived assets in the period in which it is incurred.
When the liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset. Accretion of the liability is recognized
each period, and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement. The
standard is effective for fiscal years beginning after June 15, 2002, with
earlier application encouraged. We are currently evaluating the effect of
adopting Statement No. 143 on our financial statements and have not determined
the timing of adoption.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses the
accounting and reporting for the impairment or disposal of long-lived assets and
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed of" and APB Opinion No. 30, "Reporting the
Results of Operations -- Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions." SFAS No. 144 establishes one accounting model for long-lived
assets to be disposed of by sale as well as resolves implementation issues
related to SFAS No. 121. The standard also expands the scope of discontinued
operations to include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. We adopted SFAS No.
144 effective January 1, 2002. The adoption did not have a material impact on
the consolidated financial statements.

We do not expect the adoption of any of the above-mentioned standards to
have a material effect on our consolidated financial statements.

HEDGING ACTIVITIES

In December 2000, we entered into a natural gas collar that covered 4,000
MMbtu per day for the period January 1, 2001 to December 31, 2001 at a floor of
$4.50 per MMbtu and a ceiling of $6.70 per MMbtu. On
38

January 3, 2001, we closed out the hedge for the period February 1, 2001 to
December 31, 2001 at a cost of $547,760.

As of December 31, 2001, we had no hedges in place. We believe that hedges
should be used as a financial tool to protect against the effects of a leveraged
capital structure, ensure project rates of return from acquisitions and to help
management budget and plan. Recommendations with respect to hedging
opportunities are made by both the financial and marketing departments to our
management committee and Chief Executive Officer for approval. The
administration of hedges, if any, is handled jointly by the finance, marketing
and production departments.

In March 2002, we purchased a natural gas floor at $2.65 per MMbtu covering
18,000 MMbtus per day for the period April 1, 2002 to June 30, 2002 at a cost of
$163,800. See ITEMS 1 AND 2. -- "BUSINESS AND PROPERTIES -- MARKETING."

TAX MATTERS

At December 31, 2001, we have cumulative net operating loss carryforwards
("NOLs") for federal income tax purposes of approximately $18.2 million that
will begin to expire in 2012. We anticipate that all of these NOLs will be
utilized in connection with federal income taxes payable in the future. In the
fourth quarter of 2001 we reversed a valuation allowance that previously offset
our deferred tax assets. To the extent that we have financial statement income
in the future, we will require a tax provision in our consolidated statement of
operations.

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 DISCLOSURE 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, 2001 outstanding borrowings and a floating interest rate
of 4.5%, a 10% change in interest rate would result in an increase or decrease
of interest expense of approximately $43,200 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. Due to
the instability of prices and to achieve a more predictable cash flow, we may
put in place a hedge on a portion of our 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. As of
December 31, 2001 no hedges were in place.

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.

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

As noted in the Company's Current Report on Form 8-K filed on October 10,
2001, on October 4, 2001, the Company dismissed its independent accountant,
Deloitte & Touche LLP, and engaged Arthur Andersen LLP as its new independent
accountant and auditor. The decision to engage Arthur Andersen, LLP and dismiss
Deloitte & Touche LLP was recommended by the Audit Committee and approved by the
Board of Directors.

39

None of the reports of Deloitte & Touche LLP on the financial statements of
the Company during their engagement contained an adverse opinion or was
qualified or modified as to uncertainty, audit scope or accounting principles.
Further, during the Company's two fiscal years ended December 31, 1999 and
December 31, 2000 and for the period from January 1, 2001 to October 4, 2001,
there were no disagreements between the Company and Deloitte & Touche LLP on any
matter of accounting principles, or auditing scope or procedure, which
disagreement, if not resolved to the satisfaction of Deloitte & Touche LLP,
would have caused them to make reference to the subject matter of the
disagreements in connection with their report on the financial statements for
such years. There were no reportable events (as defined in Regulation S-K, Item
304(a)(1)(v)) during the Company's two fiscal years ended December 31, 1999 and
December 31, 2000 and for the period from January 1, 2001 to October 4, 2001.
During the Company's two fiscal years ended December 31, 1999 and December 31,
2000 and for the period from January 1, 2001 to October 4, 2001, the Company did
not consult with Arthur Andersen LLP regarding any of the matters or events set
forth in Item 304(a)(2)(i) or (ii) of Regulation S-K.

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 of the Company's
2002 Annual Meeting of Shareholders (the "Proxy Statement") under the headings
"Election of Directors" and "Section 16(a) Beneficial Ownership Reporting
Compliance" 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, 2001. 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.

ITEM 11. EXECUTIVE COMPENSATION

The information required by ITEM 11 will be contained in the Proxy
Statement under the heading "Executive Compensation and Other Information" and
is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The information required by ITEM 12 will be contained in the Proxy
Statement under the heading "Security Ownership of Management and Certain
Beneficial Owners" 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 "Transactions with Management and Certain
Shareholders" and "Executive Compensation and Other Information" and is
incorporated herein by reference.

PART IV

ITEM 14. 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.

40

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

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

* Filed herewith.

+ Incorporated by reference as indicated.

(b) Reports on Form 8-K: The Company filed the following reports on Form
8-K during the quarter ended December 31, 2001:

The Company filed with the Securities and Exchange Commission during
the quarter ended December 31, 2001, a Current Report on Form 8-K dated
October 4, 2001, that reported a change in auditors.

The Company filed with the Securities and Exchange Commission during
the quarter ended December 31, 2001, a Current Report on Form 8-K dated
November 5, 2001, that reported the status of certain litigation.

The Company filed with the Securities and Exchange Commission during
the quarter ended December 31, 2001, a Current Report on Form 8-K dated
December 6, 2001, that reported the status of certain litigation.

43

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

Date: March 28, 2002

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.

44

EDGE PETROLEUM CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION

CONSOLIDATED FINANCIAL STATEMENTS

CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

None.

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

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors,
Edge Petroleum Corporation:

We have audited the accompanying consolidated balance sheet of Edge
Petroleum Corporation (a Delaware corporation) and subsidiaries as of December
31, 2001, and the related consolidated statements of operations, cash flows and
stockholders' equity for the year then ended. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally
accepted in the United States. 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 financial statements referred to above present fairly,
in all material respects, the financial position of the Company as of December
31, 2001, and the results of its operations and its cash flows for the year then
ended in conformity with accounting principles generally accepted in the United
States.

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

ARTHUR ANDERSEN LLP

Houston, Texas
March 5, 2002

F-2

INDEPENDENT AUDITORS' REPORT

To the Stockholders and Board of Directors,
Edge Petroleum Corporation
Houston, Texas

We have audited the accompanying consolidated balance sheet of Edge
Petroleum Corporation (a Delaware Corporation) (the "Company") as of December
31, 2000, and the related consolidated statements of operations, stockholders'
equity, and cash flows for each of the two years in the period ended December
31, 2000. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

We conducted our audits 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, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company as of December 31,
2000, and the results of its operations and its cash flows for each of the two
years in the period ended December 31, 2000 in conformity with accounting
principles generally accepted in the United States of America.

/s/ Deloitte & Touche LLP
Houston, Texas
March 19, 2001

F-3

EDGE PETROLEUM CORPORATION

CONSOLIDATED BALANCE SHEETS

See accompanying notes to the consolidated financial statements.
F-4

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

See accompanying notes to the consolidated financial statements.

F-5

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to the consolidated financial statements.
F-6

EDGE PETROLEUM CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

See accompanying notes to the consolidated financial statements.

F-7

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
combination 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 conducts its operations primarily along the onshore United
States Gulf Coast, with its primary emphasis in South Texas and Louisiana.
During 2001, the Company added a new focus area in the northern Rocky Mountains
that it expects to become a core area in 2002. The Company currently controls
interests in almost 250,000 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., and Edge Petroleum Exploration Company, which
are 100% owned subsidiaries of the Company. All intercompany transactions have
been eliminated in consolidation.

Other Charge On December 31, 1999, but effective January 3, 2000, James D.
Calaway resigned as President, Chief Operating Officer and Director of the
Company. As a result of his resignation the Company recorded a one-time charge
of approximately $1.5 million to satisfy corporate obligations under his
employment contract. Included in the $1.5 million is a $1.1 million non-cash
amount relating to vesting of the remaining balance of Mr. James Calaway's
restricted common stock award granted concurrent with the Company's Offering
(see Note 9). The balance of the 1999 other charge primarily represents an
accrual for workforce reduction and cash payments to be paid to Mr. Calaway from
the date of his resignation to December 31, 2000.

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.

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. The Company capitalized $1.6
million, $1.3 million and $2.0 million of these internal costs in 2001, 2000 and
1999, 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. 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, where
significant, dismantlement, restoration and abandonment costs, net of estimated
salvage values.

F-8

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The depletion rates per Mcfe for the years ended December 31, 2001, 2000 and
1999 were $1.22, $1.11 and $1.15, respectively.

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

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, 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. No adjustment related to the ceiling test
was required during December 31, 2001, 2000 or 1999.

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.

Income Taxes The Company accounts for income taxes under the provisions of
Statement of Financial Accounting Standards No. 109 -- "Accounting for Income
Taxes," ("SFAS No. 109") 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 7).

Hedging Activities Due to the instability of oil and natural gas prices,
the Company has entered 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 may
limit the benefit to the Company of increases in the price of oil and natural
gas, it may also limit the downside risk of adverse price movements. The
Company's hedging arrangements, to the extent it enters into any, apply to only
a portion of its production and provide only partial price protection against
declines in oil and natural gas prices and limits potential gains from future
increases in prices. The Company accounts for these transactions as hedging
activities and, accordingly, gains and losses are included in oil and natural
gas revenue during the period the hedged transactions occur (see Note 5).

Statements of Cash Flows The consolidated statements of cash flows are
presented using the indirect method and consider all highly liquid investments
with original maturities of three months or less to be cash equivalents.

Investment in Frontera In August 1997, the Company acquired 15,171 shares
of Series D Preferred Stock of Frontera Resources Corporation ("Frontera") that
were convertible into common stock. The Company paid $3.6 million for these
shares. Frontera develops and operates oil and gas projects in emerging market
areas around the world.

Pursuant to a rights offering conducted by Frontera in November 1998, the
Company agreed to purchase 44,027 shares of Frontera common stock (the "Frontera
Common Stock") plus such additional shares, if necessary, to maintain its then
current 8.73% interest of the partially diluted outstanding Frontera Common
Stock (assuming conversion of all preferred stock). As a result, the Company
paid Frontera $116,671 in December 1998 for 44,027 shares of Frontera Common
Stock, $5,626 in January 1999 for 2,123 shares of

F-9

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Frontera Common Stock and $116,672 in April 1999 for 44,027 shares of Frontera
Common Stock bringing its total investment in Frontera to $3.9 million.

The Company sold its investment in Frontera in June 2000 for proceeds of
$3.6 million and paid related fees of $87,500 resulting in a loss on the sale of
investment of $354,733.

Stock-Based Compensation The Company accounts for stock options under
Accounting Principles Board Opinion ("APB") No. 25, "Accounting for Stock Issued
to Employees." No compensation expense is recognized for such options. As
allowed by SFAS No. 123, "Accounting for Stock Based Compensation," ("SFAS No.
123") the Company has continued to apply APB Opinion No. 25 for purposes of
determining net income and to present the pro forma disclosure required by SFAS
No. 123.

The Company is subject to reporting requirements of Financial Accounting
Standards Board ("FASB") Interpretation No. (FIN) 44, Accounting for Certain
Transactions involving Stock Compensation that requires a non-cash charge to
deferred compensation expense if the price of the Company's common stock on the
last trading day of each reporting period is greater that 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 trading 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 9).

Earnings Per Share The Company accounts for its earnings per share in
accordance with Statement of Financial Accounting Standards No. 128 -- "Earnings
per Share," ("SFAS No. 128") which establishes the requirements for presenting
earnings per share ("EPS"). SFAS No. 128 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. During the
year ended December 31, 1999, the Company reported a net loss, thus the effects
of stock options were antidilutive (See Note 9).

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, 2001 and 2000 approximates fair value because
the interest rates are variable and reflective of market rates. No hedges were
outstanding at December 31, 2001. The fair value, gain (loss), of outstanding
hedges was approximately $(1.1) million at December 31, 2000.

Derivatives The Company adopted Statement of Financial Accounting
Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS 133") effective January 1, 2001. The statement, as amended,
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.

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. In all other

F-10

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

situations in which hedge accounting is discontinued, the derivative will be
carried at fair value on the balance sheet with future changes in its fair value
recognized in earnings prospectively.

The Company accounts for its natural gas and crude oil hedge derivative
instruments as cash flow hedges, as defined. Although the fair value of the
Company's derivative instruments fluctuates daily, as of January 1, 2001, the
fair value of our natural gas hedge derivative instrument was approximately
($1.1) million, which was recorded as a liability on the balance sheet in
January 2001 as part of the transition adjustment related to the Company's
adoption of SFAS 133. The offset to this balance sheet adjustment was a decrease
to "Accumulated other comprehensive income", a component of stockholders'
equity. The entire amount related to 2001 anticipated transactions and was
reclassified to earnings during 2001. At December 31, 2001, all hedging gains
and losses had been recognized in earnings. The Company believes the adoption of
SFAS 133 will result in more volatility in its financial statements than in the
past.

Comprehensive Income As of December 31, 2001, 2000 and 1999, there were no
adjustments ("Other Comprehensive Income") to net income (loss) in deriving
comprehensive income.

Use of Estimates The preparation of financial statements in conformity
with accounting principles generally accepted in the United States 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 revenue and
expenses during the reporting periods. Actual results could differ from these
estimates.

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 purchasers of the Company's oil and
natural gas. No bad debt expense was recorded in 2000 or 1999. The Company
cannot ensure that similar such losses may not be realized in the future.

Accounting Pronouncements On June 29, 2001, the FASB approved its proposed
SFAS No. 141, ("SFAS 141") "Business Combinations," and SFAS No. 142 ("SFAS
142"), "Goodwill and Other Intangible Assets." Under FAS 141, all business
combinations should be accounted for using the purchase method of accounting;
use of the pooling-of-interests method is prohibited. The provisions of the
statement will apply to all business combinations initiated after June 30, 2001.

SFAS 142 will apply to all acquired intangible assets whether acquired
singly, as part of a group, or in a business combination. The statement will
supersede Accounting Principals Board, ("APB"), Opinion No. 17, "Intangible
Assets," and will carry forward provisions in APB Opinion No. 17 related to
internally developed intangible assets. Under this statement, goodwill will no
longer be amortized but will be subject to annual impairment analysis. All of
the provisions of the statement should be applied in fiscal years beginning
after December 15, 2001 to all goodwill and other intangible assets recognized
in an entity's statement of financial position at that date, regardless of when
those assets were initially recognized. The Company does not have any goodwill
or intangible assets recorded as of December 31, 2001.

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." The statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement of
obligations of tangible long-lived assets in the period in which it is incurred.
When the liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset. Accretion of the liability is recognized
each period, and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement. The
standard is effective for fiscal years beginning after June 15, 2002, with
F-11

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

earlier application encouraged. We are currently evaluating the effect of
adopting Statement No. 143 on our financial statements and have not determined
the timing of adoption.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses the
accounting and reporting for the impairment or disposal of long-lived assets and
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed of" and APB Opinion No. 30, "Reporting the
Results of Operations -- Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions." SFAS No. 144 establishes one accounting model for long-lived
assets to be disposed of by sale as well as resolves implementation issues
related to SFAS No. 121. The standard also expands the scope of discontinued
operations to include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The Company adopted
SFAS No. 144 effective January 1, 2002. The adoption did not have a material
impact on the consolidated financial statements.

The Company does not expect the adoption of any of the above-mentioned
standards to have a material effect on our consolidated financial statements.

Reclassifications Certain prior year balances have been reclassified to
conform to the current year presentation.

3. PROPERTY AND EQUIPMENT

At December 31, 2001 and 2000, property and equipment consisted of the
following:

The Company uses the full-cost method of accounting for its oil and natural
gas properties. Unevaluated oil and natural gas properties are not subject to
amortization and consist of the cost of unevaluated leaseholds, exploratory and
developmental wells in progress, and secondary recovery projects before the
assignment of proved reserves. These costs are reviewed periodically by
management for impairment, with any costs impaired added to the cost of oil and
natural gas properties subject to amortization. Factors considered by management
in its impairment assessment include drilling results by the Company and other
operators, the terms of oil and natural gas leases not held by production,
production response to secondary recovery activities and available funds for
exploration and development. Interest cost capitalized in 2001, 2000 and 1999,
respectively, relating to unproved properties was $24,400, $399,300, and
$531,700.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

Under the full-cost method, a sale of oil and natural gas properties,
whether or not being amortized currently, is accounted for as an adjustment of
capitalized costs, with no gain or loss recognized unless such adjustment would
significantly alter the relationship between capitalized costs and proved
reserves.

4. LONG-TERM DEBT

In October 2000, the Company entered into a new credit facility (the
"Credit Facility") with a bank. Borrowings under the Credit Facility bear
interest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%. As of December
31, 2001, $10.0 million in borrowings were outstanding under the Credit
Facility. The Credit Facility matures October 6, 2003 and is secured by
substantially all of the Company's assets.

Originally the borrowing base under the Credit Facility was $5 million and
was subject to automatic reductions at a rate of $300,000 per month beginning
October 31, 2000. In March 2001, the Credit Facility was amended to increase the
borrowing base to $14 million, and to eliminate the $300,000 per month automatic
reduction. In January 2002, the borrowing base was increased to $18 million. The
borrowing base will be re-determined again during the second quarter of 2002.

The Credit Facility provides for certain restrictions, including but not
limited to, limitations on additional borrowings and issues of capital stock,
sales of oil and natural gas properties or other collateral, 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 EBITDA to Interest
Expense Ratio requires that (a) consolidated EBITDA, as defined in the
agreement, 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, to 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
Allowable Expenses ratio requires that (a) the aggregate amount of the Company's
year to date consolidated general and administrative expenses for the period
from January 1 of such year through the fiscal quarter then ended to (b) the
Company's year to date consolidated oil and gas revenues, net of hedging
activity, for the period from January 1 of such year through the fiscal quarter
then ended, to be less than 0.40 to 1.0. At December 31, 2001, the Company was
in compliance with the above-mentioned covenants.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

At December 31, 2001 and 2000, debt and long-term debt consisted of the
following:

5. HEDGING ACTIVITIES

The impact on oil and natural gas revenue from hedging activities for the
three years ended December 31, 2001, 2000 and 1999 was as follows:

The Company's natural gas hedging activities are entered into on a per
MMbtu delivered price basis, Houston Ship Channel, with settlement for each
calendar month occurring five business days following the publishing of the
Inside F.E.R.C. Gas Marketing Report.

Included within natural gas revenue for the three years ended December 31,
2001 was approximately $(0.9) million, $(1.5) million and $(1.1) million,
respectively, representing net losses from hedging activity. Included within oil
and condensate revenue for the year ended December 31, 2000 was $(223,454)
representing net (losses) from hedging activity. During December 2000, the
Company entered into a natural gas collar covering 4,000 MMbtu per day for the
period January 1, 2001 to December 31, 2001 with a floor of $4.50 per MMBtu and
a ceiling of $6.70 per MMbtu. On January 3, 2001, the Company closed out the
hedge for the period February 1, 2001 to December 31, 2001 at a cost of
$547,760. No hedges were outstanding at December 31, 2001. At December 31, 2000
and 1999, the fair value of outstanding hedges was approximately $(1.1) million
and $15,000, respectively.

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EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

6. COMMITMENTS AND 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 the Company's financial
condition, results of operations or cash flows, except for the litigation
described below. The Company does not believe that the ultimate outcome of this
litigation will have a material adverse effect on the Company.

In October 2001, the Company was sued by certain mineral owners in its Mew
lease, upon which the Company and its partners drilled and completed the Mew No.
1 well in the Brandon Area, Duval County, Texas. The suit names the Company,
Santos USA and Mark Smith, an independent landman, as Defendants, and is filed
in the 229th Judicial District Court of Duval County, Texas. The suit seeks a
declaratory judgment to set aside certain quitclaim deeds between the Mew
lessors that were intended to result in a partition of the mineral estate
between the various members of the Mew family in the land where the well is
located and other lands. The pleadings allege failure of consideration, fraud,
failure to consummate the partition, bad faith trespass and conversion. As part
of the leasing effort for the prospect, some members of the Mew family had
sought to partition their minerals under the tracts where they owned the surface
in full. The Mew heirs, from whom the Company acquired leases, could lose a
portion of their mineral interest if the quitclaim deeds are set aside. Were
this to happen, it could have the effect of voiding the Company's leases as to
an undivided one-third of the unit acreage for the Mew well and the Mew lease.
Plaintiffs seek unspecified actual and exemplary damages against the Company and
Santos arising out of the alleged fraud committed by the Company and Mark Smith.
They also seek damages from Santos for the value of the oil and natural gas
produced and saved from the Mew well, or alternatively, for the value of the oil
and natural gas produced less the cost of drilling, completing and operating the
well. The Company has a 12.5% working interest in the well. To date, the Mew
well has produced $5.7 million in net revenue and has cost $3.6 million to
drill, complete and operate. Estimated gross proved reserves are 111.6 MBbls and
4.6 Bcf. The Company has filed an answer in the case. Santos has filed a plea of
abatement asking that the case be dismissed for failure to join necessary and
indispensable parties. At this point, it is not possible to determine the
ultimate outcome of this litigation or the exposure, if any, the Company may
have.

In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas, enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil has filed
a counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil seeks
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith is made, the parties will not be able to
recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that it acted in good faith and intends to
vigorously defend its position. The Company, along with GMT and the other
partners, are attempting to negotiate a settlement with ExxonMobil that would
allow GMT et al (including the Company) to participate for their respective
shares of a 23% working interest in the Neblett unit, and would allow for the
recovery of well costs. If the case cannot be settled and the title issue is
decided unfavorably, the Company believes that it will ultimately be able to
recover its costs as a good faith trespasser. Due to the uncertainty of
F-15

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the final outcome, the Company has ceased to record revenue from the properties
as of August 1, 2001, which net to the Company averaged approximately 1.4
MMcfe/d of production at the time the well was shut-in. In addition, the Company
removed associated reserves of 1.4 Bcfe from its total proved reserves. The
Company believes this potential loss is not material to its financial condition
or results of operations.

The Company, as one of three original plaintiffs, filed a lawsuit against
BNP Petroleum Corporation ("BNP"), Seiskin Interests, LTD, Pagenergy Company,
LLC and Gap Marketing Company, LLC, as defendants, in the 229th Judicial
District Court of Duval County, Texas, for fraud and breach of contract in
connection with an agreement whereby BNP was obligated to drill a test well in
an area known as the Slick Prospect in Duval County, Texas. The allegations of
the Company in this litigation were, in general, that BNP gave the Company
inaccurate and incomplete information on which the Company relied in entering
into the transaction and in making its decision not to participate in the test
well and the prospect, resulting in the loss of the Company's interest in the
lease, the test well and four subsequent wells drilled in the prospect. The
Company sought to enforce its interest in the prospect and sought damages or
rescission, as well as costs and attorneys' fees. The case was originally filed
in Duval County, Texas on February 25, 2000. The Company filed a lis pendens to
protect its interest in the real property at issue.

In mid-March, 2000, the defendants filed an original answer and certain
counterclaims against plaintiffs, seeking unspecified damages for slander of
title, tortious interference with business relations and exemplary damages. The
case proceeded to trial before the court (without a jury) on June 19, 2000,
after the plaintiffs were found by the court to have failed to comply with
procedural requirements regarding the request for a jury. After several days of
trial, the case was recessed and later resumed on September 5, 2000. The court
at that time denied the plaintiffs' motion for mistrial based on the court's
denial of a jury trial. The court also ordered that the defendants'
counterclaims would be the subject of a separate trial that would commence on
December 11, 2000. The parties proceeded to try issues related to the
plaintiffs' claims on September 5-13, 2000. Defendants filed a second amended
answer and counterclaim and certain supplemental responses to a request for
disclosure in which they stated that they were seeking damages in the amount of
$33.5 million by virtue of an alleged lost sale of the subject properties, $17
million in alleged lost profits from other prospective contracts, and
unspecified incidental and consequential damages from the alleged wrongful
suspension of funds under their gas sales contract with the gas purchaser on the
properties, alleged damage to relationships with trade creditors and financial
institutions, including the inability to leverage the Slick Prospect, and
attorneys' fees at prevailing hourly rates in Duval County, Texas incurred in
defending against plaintiffs' claims and for 40% of any aggregate recovery in
prosecuting their counterclaims. In subsequent deposition testimony, the
defendants verbally alleged $26 million of damages by virtue of the alleged lost
sale of the properties (as opposed to the $33.5 million previously sought), $7.5
million of damages by virtue of loss of a lease development opportunity and $100
million of damages by virtue of the loss of a business opportunity related to
BNP's alleged inability to participate in a 3-D seismic project.

The Company also alleged that BNP, Seiskin Interests, LTD and Pagenergy
Company, LLC breached a confidentiality agreement with the plaintiffs by
obtaining oil and gas leases within an area restricted by that contract. This
breach of contract allegation is the subject of an additional lawsuit by
plaintiffs in the 165th District Court in Harris County, Texas. In this separate
action, the Company is seeking damages as a result of defendants' actions as
well as costs and attorneys' fees.

During the week of December 11-15, 2000, in Duval County BNP tried its
counterclaims against Edge, and Edge presented its defenses to the
counterclaims. BNP presented evidence that its damages were in the amounts of
$19.6 million for the alleged lost sale of the properties, $35 million for the
alleged loss of the lease development opportunity, and $308 million for the
alleged loss of the opportunity related to participation in the 3-D seismic
project. During the course of the trial, Edge presented its motion for summary
judgment on the counterclaims based on the doctrine of absolute judicial
proceeding privilege. The judge partially granted Edge's motion for summary
judgment as it related to the filing of the lis pendens, but denied it with
regard to

F-16

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the other allegations of BNP. The judge also granted Edge's plea in abatement
relating to the breach of the confidentiality agreement, ruling that the
District Court in Harris County has dominant jurisdiction of that issue.

On November 5, 2001, the court filed with the clerk and provided to the
Company a final judgment that had been signed by the court, but not provided to
the Company, on October 26, 2001. Pursuant to the terms of the judgment, the
Company takes nothing on its claims against BNP and is denied any recovery of
its interest in the lease, the prospect, or the wells of the Slick Prospect.
Instead, the court confirmed title in the lease, prospect, and wells in BNP's
affiliate. In addition, the Company was found to have tortiously and maliciously
interfered with two different BNP contracts or prospective contracts, and BNP
was awarded actual damages against the Company in the amount of $10 million and
punitive damages in the amount of $5.1 million. The judgment does not reflect a
credit in the amount of $1,945,000 to which the Company believes that it is
entitled by reason of certain settlements by its two co-plaintiffs and
co-counterdefendants.

On December 6, 2001, the Company agreed to settle this litigation. Pursuant
to the settlement, the Company agreed to pay $2.5 million and to release its
claims to interest in an area known as the Slick Prospect in Duval County,
Texas. The parties to the settlement agreed to the dismissal of all claims, both
in the 229(th) Judicial District Court of Duval County, Texas and in the 165(th)
District Court in Harris County, Texas. The parties also agreed to set aside the
judgment of the 229(th) Judicial District Court of Duval County, Texas against
the Company and to a mutual release of all claims.

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.

At December 31, 2001, the Company was obligated under noncancelable
operating leases. Following is a schedule of the remaining future minimum lease
payments under these leases:

Rent expense for the years ended December 31, 2001, 2000 and 1999 was
$578,952, $499,033 and $511,270, respectively.

7. 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.

F-17

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Significant components of the Company's deferred tax liabilities and assets
as of December 31, 2001 and 2000 are as follows:

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

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 the remaining valuation allowance was reversed.

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, 2001, the Company had cumulative net operating loss
carryforwards ("NOLs") for federal income tax purposes of approximately $18.2
million that will begin to expire in 2012. The Company anticipates 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, 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.

8. 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

F-18

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

matching contributions to the Plan are discretionary. For the years ended
December 31, 2001, 2000 and 1999, the Company contributed $60,516, $53,926, and
$81,990, respectively, to the Plan.

9. EQUITY AND STOCK PLANS

Equity Offerings On March 3, 1997, the Combination was consummated
resulting in the issuance of 4,701,361 shares to the predecessor owners of the
combining entities involved in the Combination (see Note 1). In addition, during
March 1997, the Company completed its Offering issuing 2,760,000 shares at
$16.50 per share. Net proceeds totaled approximately $40.0 million, net of
offering costs of approximately $5.4 million.

Private Offering On May 6, 1999, the Company completed a private offering
of 1,400,000 shares of common stock at a price of $5.40 per share. The Company
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. 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. No warrants have been exercised as of
December 31, 2001. Total proceeds, net of offering costs, were approximately
$7.4 million of which $4.9 million was used to repay debt under the previous
revolving credit facility with the remainder being utilized to satisfy working
capital requirements and to fund a portion of the Company's exploration program.

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 2-10 years. An aggregate of 1,200,000 shares of
common stock have been reserved for grants under the Incentive Plan, of which
364,652 shares were available for future grants at December 31, 2001. 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 2001, awards for 100,800 shares of restricted stock were made having a
value in the range of $4.58 to $8.88 based on the market value on each award
date. During 2000, awards for 161,300 shares of restricted stock were made
having a market value of $3.00 per share as of the 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 $353,371 and $105,250, respectively, for the years ended December
31, 2001 and 2000.

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 common
stock options in replacement of those options. The exercise price of the
replacement options was $7.06, 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 vest 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 represents fair market value at the date of
grant, vesting 100% on June 1, 2001.

Deferred compensation cost reported in accordance with FASB Interpretation
No. (FIN) 44, Accounting for Certain Transactions involving Stock Compensation
was a credit of $(850,281), or $(0.09) per share, for

F-19

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the year ended December 31, 2001 compared to a charge of $899,548, or $0.10 per
share in the comparable prior year period. FIN 44 requires, among other things,
a non-cash charge to compensation expense if the price of Edge's 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. The
Company will adjust deferred compensation expense upward or downward on a
monthly basis, based on the trading price at the end of each such period as
necessary to comply with FIN 44. 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 options newly
issued in conjunction with the repricing as discussed above.

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. These amounts are
included within options granted for 1999. 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 vest and become exercisable 100% 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 vest and become exercisable 100% in January 2003. In April 2001,
Mr. Elias was granted 14,000 shares of restricted stock under the Incentive Plan
valued at $7.75 per share, the market value on the award date. These shares are
issued ratable 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
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.

In addition, as of the date of the Combination, Old Edge had in place a
stock incentive plan that was administered by non-employee members of the Board
of Directors of Old Edge. Prior to the Combination, two executives of the
Company each held outstanding options for the purchase of 2,193 shares of Old
Edge common stock granted under the Old Edge incentive plan. Upon completion of
the Combination, such options were converted into incentive stock options for
the purchase of an aggregate of 97,844 (48,922 for each of the two individuals)
shares of common stock of the Company (such number of shares of common stock as
would have existed if such options had been exercised immediately prior to the
Combination Transactions). After

F-20

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

adjustment for the conversion, the option price per share of common stock for
each of the two 48,922 grants was approximately $4.09 and $2.04, respectively.
Options for the purchase of 48,922 shares of common stock were exercised during
1997. The remaining 48,922 shares of common stock were exercised during 2001.

Unearned Compensation Expense Unearned compensation expense is amortized
to operations over the corresponding vesting period. No unearned compensation
expense was reported in 2001. Unearned compensation expense for the years ended
December 31, 2000 and 1999 totaled $22,696 and $349,623, respectively, and
relates to restricted stock granted to executives at the completion of the
Offering.

Effective December 31, 1999, Mr. James D. Calaway resigned as President and
Chief Operating Officer and a Director of the Company. In connection with his
resignation his remaining restricted stock, 93,552 shares, became fully vested.
Included in "Other charge" for 1999 is the amortization of approximately $1.1
million of unearned compensation expense resulting from the vesting of those
restricted shares.

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, 2001 is presented below:

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

F-21

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, 2001 is presented below:

The Company applies the intrinsic value based method of APB No. 25 in
accounting for its stock options. Accordingly, no compensation expense has been
recognized for any stock options granted, with the exception of amounts
recognized in relation to the FIN 44 effect of the repricing, restricted stock
awards and options repurchased. Had compensation expense for the Company's stock
options granted during the years ended December 31, 2001, 2000 and 1999 been
determined based on the fair value at the grant dates, consistent with the
methodology prescribed by SFAS No. 123, the Company's net income and earnings
per share would have been the amounts indicated below based on the Black-Scholes
option pricing model (the "Model") adopted for the use in valuing stock options.
The estimated values under the Model are based on the following assumptions for
the years ended December 31, 2001, 2000 and 1999: expected volatility based on
historical volatility of daily Common Stock Prices (80%, 83% and 70%,
respectively), a risk free rate of return based on a discount rate which
approximates the U.S. Treasury rate at the time of the grant, no dividend
yields, an expected option exercise period of 8 years for all periods (with the
exercise occurring at the end of such period) and a forfeiture rate of 0-10%
over the vesting period of such options.

Following is the pro forma effect of SFAS No. 123 and its impact on net
income (loss) and earnings (loss) per basic and diluted share for the three
years ended December 31, 2001, 2000 and 1999.

F-22

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

For the year ended December 31, 1999, the Company reported a net loss, thus
the effects of stock options and warrants were antidilutive.

10. RELATED PARTY TRANSACTIONS

In May 1992, the Company became the managing venturer of the Essex Royalty
Joint Venture ("Essex") and the Company entered into a management agreement with
Essex. In September 1994, the Company became the managing venturer of the Essex
Royalty Joint Venture II ("Essex II") and the Company entered into a management
agreement with Essex II. Under the management agreements with Essex and Essex II
(collectively, the "Essex Joint Ventures"), the Company historically received a
monthly management fee for managing the Essex Joint Ventures, the general
partner of each of which is a related party. No management fees were recorded
for the year ended December 31, 2001 or 2000. For the year ended December 31,
1999, the Company recorded management fees totaling $52,560 and recorded this
amount as a reduction of general and administrative expenses. In addition, these
agreements stipulated that the Company was entitled to be reimbursed for certain
direct general and administrative expenses and other reimbursable costs. No such
amounts were due or invoiced by the Company to the Essex Joint Ventures for the
year ended December 31, 2001. The Company is no longer the manager for these
ventures. At December 31, 2001, there were no receivables from the Essex Joint
Ventures owed to the Company. At December 31, 2000 and 1999, the Company had a
receivable from the Essex Joint Ventures of $21,110 and $58,651, respectively,
relating to these management fees, direct expenses, and costs.

F-23

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Pursuant to a Purchase and Sale Agreement dated as of November 9, 1999, the
Company sold 18,872 shares of Common Stock to Mr. James C. Calaway. In exchange
for such stock, the Company received from Mr. Calaway his working interests in
all the Company's prospects, leases and areas of mutual interest.

11. SUBSEQUENT EVENTS (UNAUDITED)

In March 2002, the Company 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 provides a minimum realized price for the
protected volume, yet preserves any upside in gas prices.

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

The Company considers all highly liquid debt instruments purchased with an
original maturity of three months or less to be cash equivalents. A summary of
non-cash investing and financing activities for the years ended December 31,
2001, 2000 and 1999 is presented below:

In March 2001, 42,103 shares of common stock were issued representing
one-third of a restricted stock award granted March 2, 2000. The value of the
restricted stock on the date of grant was $3.00 per share.

In December 2001, 1,033 shares of restricted stock were issued valued at
$4,834 based on the quoted market price on the date of issuance.

In May 2000, a portion of the annual retainer due our directors was paid by
the issuance of 9,648 shares of common stock valued at $30,000, based on quoted
market prices on the date of issuance.

For the year ended December 31, 2000, forfeitures of restricted stock were
recorded with respect to 5,600 shares valued at $11,528.

In June 1999, a portion of the annual retainer due our directors was paid
by the issuance of 4,809 shares of restricted common stock valued at $29,479,
based on the quoted market prices on the date of issuance.

In November 1999, we issued 18,872 shares of common stock in exchange for
working interests in certain prospects, leases and areas of mutual interest
valued at $92,500.

For the year ended December 31, 1999, forfeitures of restricted stock were
recorded with respect to 325 shares valued at $4,024.

Supplemental Disclosure of Cash Flow Information

F-24

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

13. 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, 2001
is $3.5 million for the settlement of litigation with BNP.

Included in operating expenses for the three months ended March 31, 2001,
is a non-cash credit of $(755,372), to compensation expense as required by FASB
Interpretation No. (FIN) 44, Accounting for Certain Transactions involving Stock
Compensation. In the second quarter of 2001, an additional credit of $(95,353)
was included in operating expenses related to FIN 44.

Included in operating expenses for the three months ended December 31,
2000, is a non-cash charge of $899,548, to compensation expense as required by
FIN 44.

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

This footnote provides unaudited information required by Statement of
Financial Accounting Standards No. 69, "Disclosures About Oil and Natural Gas
Producing Activities."

F-25

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:

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

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 interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below.

F-26

EDGE PETROLEUM CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-27

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, 2001 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-28

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-29

EXHIBIT INDEX

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

* Filed herewith.

+ Incorporated by reference as indicated.