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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, 2000
Commission file number: 0-22149
EDGE PETROLEUM CORPORATION
(Exact name of Registrant as specified in its charter)
DELAWARE 76-0511037
(State or other jurisdiction of (I.R.S. Employer Identification
incorporation or organization) No.)
TEXACO HERITAGE PLAZA
1111 BAGBY, SUITE 2100
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip code)
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 19, 2001, was $64.8 million (based on a value of $7.44 per
share, the closing price of the Common Stock as quoted by NASDAQ National Market
on such date). 9,252,139 shares of Common Stock, par value $.01 per share, were
outstanding on March 19, 2001.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the registrant's 2001 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
PAGE
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PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES..................................... 1
ITEM 3. LEGAL PROCEEDINGS........................................... 27
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS......... 28
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS......................................... 30
ITEM 6. SELECTED FINANCIAL DATA..................................... 31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS................................... 33
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET
RISK........................................................ 44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................. 44
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURES................................... 44
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.......... 45
ITEM 11. EXECUTIVE COMPENSATION...................................... 45
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT.................................................. 45
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.............. 45
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM
8-K......................................................... 46
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 energy company engaged in the
exploration, development and production of oil and natural gas. Edge conducts
its operations primarily along the onshore Gulf Coast with its primary emphasis
in South Texas and Louisiana where it currently controls interests in excess of
90,000 gross acres under lease and option. The Company explores for oil and
natural gas by emphasizing an integrated application of highly advanced data
visualization techniques and computerized 3-D seismic data analysis to identify
potential hydrocarbon accumulations. The Company believes its approach to
processing and analyzing geophysical data differentiates it from other
independent exploration and production companies and is more effective than
conventional 3-D seismic data interpretation methods. The Company also believes
that it maintains one of the larger databases of onshore Gulf Coast 3-D seismic
data of any independent oil and natural gas company, and is continuously looking
for ways to acquire additional data within this core region.
The Company's extensive technical expertise has enabled it to internally
generate substantially all of its oil and gas prospects drilled to date and to
assemble a portfolio of drilling prospects. The Company pursues drilling
opportunities that include a blend of shallower, normally pressured reservoirs
that generally involve moderate costs and risks as well as deeper, high-pressure
reservoirs that generally involve greater costs and risks, but have higher
economic potential. The Company mitigates its exposure to exploration costs and
risk by conducting its operations with industry partners, including major oil
companies and large independents, that generally pay a disproportionately
greater share of the costs than the Company. In addition to its in-house
prospect generation efforts, the Company pursues outside generated opportunities
as well as selected acquisitions within its core operating areas to increase the
opportunities for growth and set the stage for growth into new core areas.
From 1995 through 1998, the Company experienced steady growth in reserves,
production and cash flow as a result of its increased drilling activities,
retention of larger interests in the wells it drilled and the larger average
resource potential of its wells. In 1999, the Company was not able to increase
its reserves and production due primarily to two factors. First, effective
July 1, 1999, the Company sold a group of producing properties, which it
believed had limited development potential, to its partner in the properties at
a price which exceeded the Company's valuation of those properties. The effect
of the sale was a reduction of approximately 1.4 Bcfe of proved reserves and
approximately 500,000 Mcfe of production during the second half of 1999.
Second, the collapse of commodity prices in late 1998 and early 1999
resulted in a reduction of capital budgets for 1999 by most industry
participants. Exploration budgets were typically hit the hardest in this
downturn. The Company is dependent on finding partners for its exploratory
activity and the industry wide pull back from exploratory activity plus the
Company's own reduced cash flow early in 1999 from falling commodity prices
caused a reduction in the number of wells drilled relative to the Company's
original budget and previous years.
Although drilling activity was curtailed in 1999, the Company continued to
invest in prospect development resulting in a portfolio of prospects, in various
stages of development, ready for drilling in 2000 and 2001. Late in the second
quarter of 2000, the Company actively initiated its 2000 drilling
1
program and drilled a total of 26 gross (10.486 net) wells. The Company's
estimate of proved oil and natural gas reserves, as of December 31, 2000, was
25.4 Bcf of natural gas and 720 MBbls of oil or about 29.7 Bcfe. This represents
a 19% increase over year-end 1999 proved reserves, and a 190% replacement ratio
of 2000 production of 6.2 Bcfe. Production and reserves in 2000 were negatively
impacted by the sale of about .8 Bcfe total of proved reserves in two separate
transactions during the year. The Company's average daily production for 2000
was 17.1 MMcfe per day as compared to 18.6 MMcfe per day in 1999. At
December 31, 2000, the Company's average production was 20.6 MMcfe per day. At
December 31, 2000, Edge's estimated future net revenue to be generated from
proved reserves before income taxes and discounted to present value at 10% per
annum was $172 million, based on pricing at year-end of $26.80 per barrel of oil
and $10.54 per Mcf of gas. Gas prices were at historically high levels at
December 31, 2000 and are not necessarily reflective of expected future prices.
Our future net revenue discounted at 10% using a $5.00 per Mcf gas price rather
than $10.54 was approximately $84 million. See Item 1--"Oil and Natural Gas
Reserves."
EXPLORATION TECHNOLOGY
Since 1992, as a result of the advent of economic onshore 3-D seismic
surveys and the improvement and increased affordability of data interpretation
technologies, the Company has relied almost exclusively on the interpretation of
3-D seismic data in its exploration strategy. The principal advantage of 3-D
seismic data over 2-D seismic data is that it affords a geoscientist the ability
to investigate the entire prospective area using a 3-D seismic data volume, as
compared to the limited number of two dimensional profiles covering a small
percentage of the prospective area that are available using 2-D seismic data. As
a consequence, a geoscientist using 3-D seismic data is able to more fully
evaluate prospective areas and produce more accurate interpretations. The use of
structural maps based upon 3-D seismic data can significantly improve the
probability of drilling commercially successful wells, since this data allows
structurally advantageous positions to be more accurately located in highly
drilled exploration plays where only 2-D seismic data was used in the past.
The Company's methodology for interpreting 3-D seismic data has advanced
beyond traditional 3-D interpretation techniques, which consist of interpreting
multiple closely spaced 2-D profiles extracted from 3-D seismic volumes to
generate 3-D structural maps. The Company's advanced visualization and data
analysis techniques and resources enable its geoscientists to view large volumes
of information contained within the 3-D seismic data. This improves the
geoscientist's ability to recognize certain important patterns or attributes in
the data which may indicate hydrocarbon traps and which, if viewed incorrectly
or with the application of improper techniques, could go undetected.
Visualization techniques also enable the geoscientist to quickly identify and
prioritize key areas from the large volumes of data reviewed in order to realize
the greatest early benefit. The Company's sophisticated computing resources and
unique visualization and data analysis techniques allow its geoscientists to
more easily identify features such as shallow amplitude anomalies, complex
channel systems, sharp structural details and fluid contacts, which might have
been overlooked using less sophisticated 3-D seismic data interpretation
techniques.
The application of advanced 3-D exploration technology requires large scale
information processing and graphic visualization, made possible by the rapid
improvements in computing technology. The Company has made a significant
investment in its 3-D seismic data visualization technology, which is closely
linked with the Company's well-log database and other geoscience application
software. Additionally, the Company has developed a fully integrated,
client-server environment utilizing multiple workstation nodes. The Company uses
a comprehensive suite of Landmark Graphics geoscience software applications in
its interpretation environment, including Landmark's EarthCube software, which
is designed specifically to integrate visualization, 3-D geologic
interpretation, and well databases.
2
The Company's technological success is dependent in part upon hiring and
retaining highly skilled technical personnel. The Company has assembled a
technical team that it believes has the capacity to adapt to the rapidly
changing technological demands in the field of oil and natural gas exploration.
This team currently consists of five geoscientists with an average of 18 years
industry experience, most of which have had extensive experience with major oil
companies. The Company provides its technical team with a sophisticated work
environment. With its technical capabilities and personnel, the Company believes
that it will be able to analyze large quantities of data without a commensurate
increase in the number of employees. Additionally, the expertise of the
Company's team of geoscientists reduces its dependence on outside technical
consultants and enables the Company to internally generate substantially all of
its prospects and quickly evaluate outside generated prospects.
EXPLORATION AND OPERATING APPROACH
The Company's exploration philosophy is to identify large play areas,
primarily for natural gas reserve potential, where its advanced geophysical
tools and techniques can be profitably brought to bear. The Company typically
seeks to explore in areas with (i) numerous accumulations of normally pressured
reserves at shallow depths and in geologic traps that are difficult to define
without the use of advanced data visualization and interpretation and (ii) the
potential for large accumulations of deeper, over-pressured reserves. The
Company typically sells a portion of its interest in the deep, over-pressured
prospects in order to mitigate its exploration risk and fund the anticipated
capital requirements for the interests it retains in such prospects, while
retaining all or the majority of its interest in the prospects with
normally-pressured reservoirs. As the Company has grown and our financial
resources have increased, we have retained larger interests in our prospects.
The Company emphasizes preplanning in play development to lower capital and
operational costs and to efficiently integrate potential well locations into the
existing and planned infrastructure, including gathering systems and other
surface facilities. In constructing surface facilities, the Company seeks to use
reliable, high quality, used equipment in place of new equipment to achieve cost
savings. The Company also seeks to minimize cycle time from drilling to hook-up
of wells, thereby accelerating cash flow and improving ultimate project
economics.
An important component of the Company's exploration approach is the
acquisition of large 3-D seismic data sets at the lowest possible cost. The
Company has sought to obtain large 3-D data sets either by participating in
large proprietary seismic data acquisition programs through joint venture
arrangements with other energy companies or non-proprietary group shoots in
which the Company shares the costs and results of seismic surveys. The Company
believes its technical capabilities allow it to rapidly evaluate these large 3-D
data sets and identify and secure drilling opportunities prior to the other
participants in these group shoots. In both the proprietary and the
non-proprietary shoots, the Company's partners have generally borne a
disproportionate share of the up-front costs of seismic data acquisition and
interpretation in return for the Company's expertise in the management of
seismic surveys, interpretation of 3-D seismic data, development of prospects
and acquisition of exploration rights. Substantially all of the Company's
operations are conducted through joint operations with industry participants.
Under the participation agreements for most of its projects, the Company is
generally responsible for determining the area to explore; managing the land
permitting and optioning process; determining seismic survey design; overseeing
data acquisition and processing; preparing, integrating and interpreting the
data; identifying the drill site; and in selected instances, managing drilling
and production operations. The Company is therefore responsible for exercising
control over what it believes are the critical functions in the exploration
process. The Company seeks to obtain lease operator status and control over
field operations, including decisions regarding drilling and completion methods
and accounting and reporting functions, only when its expertise and planning
capabilities indicate that meaningful value can be added through its performance
of these functions. Typically, in
3
cases when the Company does not have field operator status, the Company is
primarily responsible for identifying prospects for the operator and, when
necessary, asserts its rights under its joint operating agreements to ensure
drilling of such prospects. The Company began field operations of wells in 1995
and operates approximately 37% of its current production.
The Company has developed extensive experience in the development and
management of projects along the Gulf Coast. Since its inception, the Company
has generated and assembled numerous prospects within the onshore Gulf Coast
area. The Company believes that the ability to develop large scale 3-D projects
in this area, on an economic basis, requires experience in obtaining the rights
to explore and is a source of competitive advantage for the Company.
The Company's primary strategy for acreage acquisition is to obtain leasing
options covering large geographic areas prior to conducting its 3-D seismic
surveys. The Company, therefore, typically seeks to acquire seismic permits that
include options to lease, thereby reducing the cost and the level of competition
for leases on drillable prospects that may emerge upon completing a successful
seismic data acquisition program over a project area.
OIL AND NATURAL GAS RESERVES
The following table sets forth estimated net proved oil and natural gas
reserves of the Company and the present value of estimated future pretax net
cash flows related to such reserves as of December 31, 2000. The Company engaged
Ryder Scott Company ("Ryder Scott") to estimate the Company's net proved
reserves, projected future production, estimated future net revenue attributable
to its proved reserves, and the present value of such estimated future net
revenue as of December 31, 2000. Ryder Scott's estimates were based upon a
review of production histories and other geologic, economic, ownership and
engineering data provided by the Company. In estimating the reserve quantities
that are economically recoverable, Ryder Scott used year end oil and natural gas
prices in effect at December 31, 2000 and estimated development and production
costs that were in effect during December 2000 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
de-escalation was considered by Ryder Scott. For further information concerning
Ryder Scott's estimate of proved reserves of the Company at December 31, 2000,
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 the Company. For further information concerning the
present value of future net revenue from these proved reserves, see Note 13 of
Notes to the 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."
PROVED RESERVES
DEVELOPED(1) UNDEVELOPED(2) TOTAL
------------ --------------- ------------
Oil and condensate (MBls)(3)....................... 675 45 720
Natural gas (MMcf)................................. 21,965 3,395 25,360
Total MMcfe...................................... 26,015 3,666 29,681
Estimated future net revenue before income taxes... $218,126,777 $30,998,853 $249,125,630
Present value of estimated future net revenue
before income taxes (discounted 10% annum)(4).... $150,271,550 $22,170,987 $172,442,537
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(1) Proved developed reserves are proved reserves which are expected to be
recovered from existing wells with existing equipment and operating methods.
4
(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
production and future development costs, using year end oil and natural gas
prices in effect at December 31, 2000, which were $10.54 per Mcf of natural
gas and $26.80 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.
In accordance with Commission regulations, the Ryder Scott Report used year
end oil and natural gas prices in effect at December 31, 2000. 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, 2000. 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. In particular, natural gas
prices at December 31, 2000 were at or near their all-time highs. Natural gas
prices have experienced significant volatility and since that time prices for
natural gas have fallen substantially. As of March 19, 2001, the average price
of natural gas that the Company receives for its production had fallen to
approximately $5.00 per Mcf. Decreases in the assumed commodity prices result in
decreases in estimated future net revenue as well as in estimated reserves.
5
VOLUMES, PRICES AND OIL AND NATURAL GAS OPERATING EXPENSE
The following table sets forth certain information regarding production
volumes, average sales prices and average oil and natural gas operating expense
associated with the Company's sales of oil and natural gas for the periods
indicated.
YEAR ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------
PRODUCTION:
Oil and condensate (MBbls)........................ 97 112 126
Natural gas liquids (MBbls)....................... 77 75 16
Natural gas (MMcf)................................ 5,206 5,676 6,284
Natural gas equivalent (MMcfe).................... 6,249 6,799 7,135
AVERAGE SALES PRICE:
Oil and condensate ($ per Bbl)(1)................. $26.16 $16.15 $11.96
Natural gas liquids ($ per Bbl)................... 16.37 12.16 14.94
Natural gas ($ per Mcf)(1)........................ 3.84 2.07 2.18
Natural gas equivalent ($ per Mcfe)(1)............ 3.80 2.13 2.17
AVERAGE OIL AND NATURAL GAS OPERATING EXPENSES
INCLUDING PRODUCTION AND AD VALOREM TAXES ($ PER
MCFE)(2).......................................... $ 0.63 $ 0.45 $ 0.47
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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.
RESERVE REPLACEMENT
From January 1, 1997 to December 31, 2000, the Company incurred total
acquisition, exploration and development costs of approximately $87.0 million
and generated proceeds of approximately $14.6 million from the sale of
undeveloped prospects. Total acquisition, exploration, and development
activities from January 1, 1997 to December 31, 2000, resulted in the addition
of approximately 40.1 Bcfe, net to the Company's interest, of proved reserves at
an average reserve replacement cost of $1.81 per Mcfe (net cost incurred divided
by net reserve additions). Reserve replacement costs reflect the proceeds from
the sales of undeveloped prospects recorded as a reduction to the full-cost
pool.
The Company's reserve replacement costs have historically fluctuated on a
year to year basis. Reserve replacement costs, as measured annually, may not be
indicative of the Company's ability to economically replace oil and natural gas
reserves because the recognition of costs may not necessarily coincide with the
addition of proved reserves.
6
ACQUISITION, EXPLORATION AND DEVELOPMENT CAPITAL EXPENDITURES
The following table sets forth certain information regarding the total costs
incurred in the acquisition, exploration and development of proved and unproved
properties.
YEAR ENDED DECEMBER 31,
------------------------------
2000 1999 1998
-------- -------- --------
(IN THOUSANDS)
Acquisition Cost:
Unproved projects and prospects................ $ 4,220 $ 7,692 $20,853
Exploration costs................................ 2,707 3,335 10,236
Development costs................................ 3,766 3,455 3,250
------- ------- -------
Total costs incurred........................... 10,693 14,482 34,339
Less proceeds from sales of prospects............ 1,811 3,471 6,952
------- ------- -------
Net costs incurred............................. $ 8,882 $11,011 $27,387
======= ======= =======
Net costs incurred excludes sales of proved oil and natural gas properties
which are accounted for as adjustments of capitalized costs with no gain or loss
recognized, unless such adjustments would significantly alter the relationship
between capitalized costs and proved reserves.
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company for the
three years ended December 31, 2000. In the table, "gross" refers to the total
wells in which the Company has a working interest and "net" refers to gross
wells multiplied by the Company's working interest therein.
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
2000 1999 1998
------------------- ------------------- -------------------
GROSS NET GROSS NET GROSS NET
-------- -------- -------- -------- -------- --------
EXPLORATORY:
Productive......................... 19 7.90 9 3.78 43 19.34
Non-productive..................... 2 1.43 4 0.67 23 10.27
-- ----- -- ---- -- -----
Total............................ 21 9.33 13 4.45 66 29.61
-- ----- -- ---- -- -----
DEVELOPMENT:
Productive......................... 5 1.16 5 1.56 12 3.53
Non-productive..................... -- -- 1 0.30 5 2.89
-- ----- -- ---- -- -----
Total............................ 5 1.16 6 1.86 17 6.42
-- ----- -- ---- -- -----
GRAND TOTAL.......................... 26 10.49 19 6.31 83 36.03
== ===== == ==== == =====
7
PRODUCTIVE WELLS
The following table sets forth the number of productive oil and natural gas
wells in which the Company owned an interest as of December 31, 2000.
COMPANY
OPERATED NON-OPERATED TOTAL(1)
------------------- ------------------- -------------------
GROSS NET GROSS NET GROSS NET
-------- -------- -------- -------- -------- --------
Oil................................. 13 7.42 21 5.33 34 12.75
Natural gas......................... 50 32.80 72 15.36 122 48.16
-- ----- -- ----- --- -----
Total............................. 63 40.22 93 20.69 156 60.91
== ===== == ===== === =====
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(1) Includes 42 gross wells shut in (17.62 net).
ACREAGE DATA
The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of December 31, 2000. Developed acres
refer to acreage within producing units and undeveloped acres refer to acreage
that has not been placed in producing units.
UNDEVELOPED
DEVELOPED ACRES ACRES TOTAL
------------------- ------------------- -------------------
GROSS NET GROSS NET GROSS NET
-------- -------- -------- -------- -------- --------
Texas........................ 58,565 21,417 20,222 3,985 78,787 25,402
Louisiana.................... 2,117 458 6,087 2,659 8,204 3,117
Mississippi.................. 2,660 87 184 36 2,844 123
Alabama...................... 1,116 92 40 1 1,156 93
------ ------ ------ ----- ------ ------
Total...................... 64,458 22,054 26,533 6,681 90,991 28,735
====== ====== ====== ===== ====== ======
Leases covering approximately 10,709 gross (3,969 net), 2,530 gross (651
net) and 2,647 gross (645 net) undeveloped acres are scheduled to expire in
2001, 2002 and 2003, respectively. In general, the Company's 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 43,798 gross (21,819 net) acres that the Company
has a right to acquire pursuant to various seismic option agreements at
December 31, 2000. Under the terms of its option agreements, the Company
typically has the right for one year, subject to extensions, to exercise its
option to lease the acreage at predetermined terms.
CORE AREAS OF OPERATION
Set forth below are descriptions of the Company's core areas of focus where
it is actively exploring for potential oil and natural gas reserves and in many
cases currently has oil and natural gas production. The Company's operations are
focused on the primary natural gas trends of South Texas and South Central
Louisiana. The Company has seismic and production data and operations in over 20
specific project areas within these large natural gas plays. The descriptions
below highlight the areas of particular focus for the Company in 2001 and
beyond. The seismic data the Company is using to analyze its project areas range
from regional non-proprietary group shoots to single field proprietary surveys.
The Company has typically participated in these project areas with industry
partners under agreements that generally provide for the industry partners to
bear a greater share of the up-front costs associated with obtaining option
arrangements with landowners, seismic data acquisition and related
8
data interpretation. The working interest and net revenue interest shown for the
project areas are the average for acreage under lease and option by the Company
in that project area.
Although the Company is currently pursuing prospects or seeking to obtain
seismic data within certain of the project areas listed below, there can be no
assurance that these prospects will be drilled or that such seismic data will be
obtained at all or within the expected timeframe. The final determination with
respect to the drilling of any scheduled or budgeted wells will be dependent on
a number of factors, including (i) the results of exploration efforts and the
acquisition, review and analysis of the seismic data, (ii) the availability of
sufficient capital resources by the Company and the other participants for the
drilling of the prospects, (iii) the approval of the prospects by other
participants after additional data has been compiled, (iv) economic and industry
conditions at the time of drilling, including prevailing and anticipated prices
for oil and natural gas and the availability of drilling rigs and crews,
(v) the financial resources and results of the Company and (vi) the availability
of leases and permits on reasonable terms for the prospect. 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 the control of the Company. See
ITEMS 1 AND 2.--"BUSINESS AND PROPERTIES--FORWARD LOOKING INFORMATION AND RISK
FACTORS."
TEXAS
SOUTH TEXAS FRIO-VICKSBURG TREND
The Company's activity in this trend covers approximately 600 square miles
and spans parts of Brooks, Starr, and Hidalgo Counties in South Texas. The
Company's average working interests range from 100% in the Santellana area to
22.5% in the Encinitas area. There were three wells drilled in this trend in
2000. At year-end 2000, Edge's net production from this area was approximately 6
MMcfe per day. The focus for this area will be deeper drilling in the Vicksburg
formation. Two wells are currently planned for this area in 2001.
SOUTH TEXAS FRIO-WILCOX-QUEEN CITY TREND
The Company's activity in this trend covers approximately 800 square miles
in Duval, Webb, Live Oak, Bee and Goliad Counties. The Company's average working
interests range from 0% to 100%. In some areas in this trend the Company has
historically sold prospects, retaining only a back-in working interest after
payout. There were 22 wells drilled in this trend during 2000. At year-end 2000,
Edge's net production from this area was approximately 12.5 MMcfe per day. Edge
currently plans to drill approximately 16 to 20 wells in this area during 2001,
consisting of a combination of typical shallower Frio and Vicksburg wells plus
select deeper Wilcox wells.
LOUISIANA
During 1997, Edge began to reestablish activity in Louisiana where the
Company had been historically active and has had prior exploratory successes.
Early in its history, the Company developed and sold a number of South Louisiana
exploration prospects including a prospect that became the Maurice Field, a
field that has produced in excess of 100 Bcfe since its discovery in 1987. Edge
currently has a 2.68% working interest in one producing well in this field.
During 2000 Edge participated in the drilling of one well in South Louisiana. At
year end, Edge's net production from this area was about 2 MMcfe per day.
SOUTH LOUISIANA MARGTEX, BOLMEX TREND
The Company's operations are focused in a prolific, 650 square mile area
that covers a major natural gas producing region in Acadia, Lafayette, St.
Landry and Vermillion Parishes. Edge's working
9
interests in this area range between 22.5% to 100%. The exploration focus in
this area is primarily deeper, geo-pressured gas accumulations ranging from
12,000 feet to 20,000 feet. Currently, the Company plans to drill four to six
wells in this area during 2001.
INVESTMENT IN FRONTERA RESOURCES CORPORATION
In August 1997, the Company acquired 15,171 shares of Series D Preferred
Stock of Frontera Resources Corporation ("Frontera") that were convertible into
Frontera common stock. The Company paid $3.6 million for these shares. 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 Frontera Common Stock and $116,672 in
April 1999 for 44,027 shares of Frontera Common Stock to bring its total
investment in Frontera to $3,867,233 at December 31, 1999. In June 2000, the
Company sold all of its investment in Frontera for proceeds of $3.6 million and
paid related fees of $87,500, resulting in a loss of $354,733, or $0.04 per
basic share.
MARKETING
The Company's 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 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.
The Company's marketing objective is to receive the highest possible
wellhead price for its product. The Company is aided by the presence of multiple
outlets near its production on the Gulf Coast. The Company takes an active role
in determining the available pipeline alternatives for each property based upon
historical pricing, capacity, pressure, market relationships, seasonal variances
and long-term viability.
There are a variety of factors which affect the market for oil and natural
gas, including the extent of domestic production and imports of oil and natural
gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and natural gas, the marketing of
competitive fuels and the effects of state and federal regulations on oil and
natural gas production and sales. The Company has not experienced any
difficulties in marketing its oil and natural gas. The oil and natural gas
industry also competes with other industries in supplying the energy and fuel
requirements of industrial, commercial and individual customers.
The Company markets its own production where feasible with a combination of
market-sensitive pricing and forward-fixed pricing. Forward pricing is utilized
to take advantage of anomalies in the futures market and to hedge a portion of
the Company's production 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."
Despite the measures taken by the Company to attempt to control price risk,
the Company remains subject to price fluctuations for natural gas sold in the
spot market due primarily to seasonality of demand and other factors beyond the
Company's control. Domestic oil prices generally follow worldwide oil prices,
which are subject to price fluctuations resulting from changes in world supply
and demand. The Company continues to evaluate the potential for reducing these
risks by entering into, and expects to enter into, additional hedge transactions
in future years. In addition, the Company may
10
also close out any portion of hedges that may exist from time to time as
determined to be appropriate by management. During the three years ended
December 31, 2000, the Company had in place several natural gas commodity
collars with financial institutions covering 5,000 - 13,000 MMbtus per day, or
approximately 30% - 76% of the Company's average daily natural gas production.
Prices received float between a floor and cap price 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 years ended December 31,
2000, 1999 and 1998 was approximately $(1.5) million, $(1.1) million, and
$482,000 respectively, representing net (losses) and net gains from hedging
activity. During December 1999, the Company 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. In December 2000, the Company entered into a natural
gas collar. The natural gas collar covers 4,000 MMbtus per day for the period
January 1, 2001 to December 31, 2001 at a $4.50 floor and a $6.70 ceiling. At
December 31, 2000 and 1999, the fair value, net gain (loss), of outstanding
hedges was approximately $(1.1) million and $15,000, respectively. 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.
As of March 28, 2001, the Company has no hedges in place. Edge believes 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 Edge's
management committee and Chief Executive Officer for approval. The
administration of hedges, if any, is handled jointly by the finance and
marketing departments of the Company.
COMPETITION
The Company encounters competition from other oil and natural gas companies
in all areas of its operations, including the acquisition of exploratory
prospects and proven properties. The Company's competitors include major
integrated oil and natural gas companies and numerous independent oil and
natural gas companies, individuals and drilling and income programs. Many of its
competitors are large, well-established companies with substantially larger
operating staffs and greater capital resources than the Company's and which, in
many instances, have been engaged in the oil and natural gas business for a much
longer time than the Company. Such companies may be able to pay more for
exploratory prospects and productive oil and natural gas properties and may be
able to define, evaluate, bid for and purchase a greater number of properties
and prospects than the Company's financial or human resources permit. In
addition, such companies may be able to expend greater resources on the existing
and changing technologies that the Company believes are and will be increasingly
important to the current and future success of oil and natural gas companies.
The Company's ability to explore for oil and natural gas reserves and to acquire
additional properties in the future will be dependent upon its ability to
conduct its operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. The Company
believes that its technological expertise, its exploration, land, drilling and
production capabilities and the experience of its management generally enable it
to compete effectively. Many of the Company's competitors, however, have
financial resources and exploration and development budgets that are
substantially greater than those of the Company, which may adversely affect the
Company's 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 the Company's control. These factors
include regulation of oil and natural gas production, federal and state
regulations governing environmental quality and pollution control, state
11
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 the Company may conduct operations. State and
federal regulations generally are intended to prevent waste of oil and natural
gas, protect rights to produce oil and natural gas between owners in a common
reservoir, control the amount of oil and natural gas produced by assigning
allowable rates of production and control contamination of the environment.
Pipelines are subject to the jurisdiction of various federal, state and local
agencies. The Company is 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. The Company
believes that it is in substantial compliance with the various statutes, rules,
regulations and governmental orders to which the Company's 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 the Company's 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 the Company's operations may be subject.
REGULATION OF OIL AND NATURAL GAS EXPLORATION AND PRODUCTION. The Company's
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. The Company's operations are also subject to various
conservation laws and regulations. These 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 the Company can produce
from its wells and may limit the number of wells or the locations at which the
Company can drill. The regulatory burden on the oil and natural gas industry
increases the Company's costs of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently expanded,
amended and reinterpreted, the Company is unable to predict the future cost or
impact of complying with such regulations.
REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS. Federal legislation
and regulatory controls have historically affected the price of natural gas
produced by the Company and the manner in which such production is transported
and marketed. Under the Natural Gas Act 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 was substantially modified by the Natural Gas
Policy Act, 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 the Company of its own
production. As a result, all of the Company's domestically produced natural
12
gas may now be sold at market prices, subject to the terms of any private
contracts which may be in effect. The FERC's jurisdiction over natural gas
transportation was not affected by the Decontrol Act.
The Company's natural gas sales are affected by intrastate and interstate
gas transportation regulation. Beginning in 1985, 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, the FERC expanded the impact of open access regulations to intrastate
commerce.
Beginning in April 1992, the Federal Energy Regulatory Commission 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 the Company's 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 Federal Energy Regulatory Commission
continues to review and modify its regulations regarding the transportation of
natural gas. For example, the Federal Energy Regulatory Commission 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 Federal Energy Regulatory Commission Staff
to analyze whether the Federal Energy Regulatory Commission should implement
additional fundamental policy changes. These include whether to pursue
performance-based or other non-cost based ratemaking techniques and whether the
Federal Energy Regulatory Commission should mandate greater standardization in
terms and conditions of service across the interstate pipeline grid.
In April 1999, the Federal Energy Regulatory Commission issued Order
No. 603, which implemented new regulations governing the procedure for obtaining
authorization to construct new pipeline facilities. In September 1999, the
Federal Energy Regulatory Commission 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. The Company believes
these changes generally have improved the Company's access to
13
markets while, at the same time, substantially increasing competition in the
natural gas marketplace. The Company cannot predict what new or different
regulations the FERC and other regulatory agencies may adopt, or what effect
subsequent regulations may have on the Company's 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. Thus, in
addition to "first sale" deregulation, Congress also repealed incremental
pricing requirements and gas use restraints previously applicable. There are
other legislative proposals pending in the Federal and state legislatures which,
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 the Company. 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 the
Company's sales of gas, cannot be predicted.
The Company owns certain natural gas pipelines that it believes 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.
OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate
and gas liquids by the Company are not currently regulated and are made at
market prices. The price the Company receives 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 last year, 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. The Company is not able at this time to predict the effects of these
regulations, if any, on the transportation costs associated with oil production
from the Company's oil producing operations.
ENVIRONMENTAL REGULATIONS. The Company's 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, the business and prospects of the
Company could be adversely affected.
14
The Company generates 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 the Company's oil and natural gas
operations that are currently exempt from treatment as "hazardous wastes" may in
the future be designated as "hazardous wastes," and therefore be subject to more
rigorous and costly operating and disposal requirements.
The Company currently owns or leases numerous properties that for many years
have been used for the exploration and production of oil and natural gas.
Although the Company believes that it has 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 the Company or on or
under locations where such wastes have been taken for disposal. In addition,
many of these properties have been operated by third parties whose treatment and
disposal or release of hydrocarbons or other wastes was not under the Company's
control. These properties and the wastes disposed thereon may be subject to 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, the Company could be required to
remove or remediate previously disposed wastes (including wastes disposed of or
released by prior owners or operators) or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.
The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted in
1990 and contain provisions that may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from the operations
of the Company. The EPA and states have been developing regulations to implement
these requirements. The Company may be required to incur certain capital
expenditures in the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals
addressing other air emission-related issues. However, the Company does not
believe its operations will be materially adversely affected by any such
requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control, countermeasure ("SPCC") and response plans relating
to the possible discharge of oil into surface waters. The Company has
acknowledged the need for SPCC plans at certain of its properties and believes
that it will be able to develop and implement these plans in the near future.
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.
Operations of the Company 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,
15
participate in a group permit or seek coverage under an EPA general permit.
While certain of its properties may require permits for discharges of storm
water runoff, the Company believes that it 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 the
Company. 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.
The Company also is subject to a variety of federal, state and local
permitting and registration requirements relating to protection of the
environment. Management believes that the Company is in substantial compliance
with current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse effect on
the Company.
OPERATING HAZARDS AND INSURANCE
The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosion, blow-out, pipe failure, casing collapse,
abnormally pressured formations and environmental hazards such as oil spills,
natural gas leaks, ruptures and discharges of toxic gases, the occurrence of any
of which could result in substantial losses to the Company due to injury or loss
of life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, cleanup responsibilities,
regulatory investigation and penalties and suspension of operations.
In accordance with customary industry practice, the Company maintains
insurance against some, but not all, of the risks described above. The Company's
insurance does not cover business interruption or protect against loss of
revenue. There can be no assurance that any insurance obtained by the Company
will be adequate to cover any losses or liabilities. The Company cannot predict
the continued availability of insurance or the availability of insurance at
premium levels that justify its purchase. The occurrence of a significant event
not fully insured or indemnified against could materially and adversely affect
the Company's financial condition and operations.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and
natural gas industry. The Company's properties are subject to customary royalty
interests, liens incident to operating agreements, liens for current taxes and
other burdens which the Company believes do not materially interfere with the
use of or affect the value of such properties. As is customary in the industry
in the case of undeveloped properties, little investigation of record title is
made at the time of acquisition (other than a preliminary review of local
records). Investigations, including a title opinion of local counsel, are made
before commencement of drilling operations.
16
EMPLOYEES
At December 31, 2000, the Company had 30 full-time employees, primarily
professionals, including three geologists/geophysicists, one geo-technician, two
landmen and three engineers. The Company believes that its relationships with
its employees are good. None of the Company's employees are covered by a
collective bargaining agreement. From time to time, the Company utilizes the
services of independent consultants and contractors to perform various
professional services, particularly in the areas of construction, design, well
site surveillance, permitting and environmental assessment. Field and on-site
production operation services, such as pumping, maintenance, dispatching,
inspection and testing are generally provided by independent contractors.
OFFICE AND EQUIPMENT
The Company maintains its executive offices at Texaco Heritage Plaza, 1111
Bagby, Suite 2100, Houston, Texas. During 1997 the Company entered into a lease,
expiring February 3, 2003, for these offices covering 28,206 square feet of
office space.
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 the Company's drilling plans, its 3-D project
portfolio, future G&A 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, new credit facilities, attraction of
new members to the exploration team, 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 the Company's current view of future events
and financial performance. When used in this document, the words "budgeted,"
"anticipate," "estimate," "expect," "may," "project," "believe," "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. The Company undertakes no
obligation to publicly update or review any forward-looking statement, whether
as a result of new information, future events, or otherwise. Such statements
involve risks and uncertainties, including, but not limited to, 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 the Company's products, conducting successful exploration and
development in order to maintain reserves and revenue in the future, operating
risks of oil and natural gas operations, the Company's dependence on key
personnel, the Company's ability to utilize changing technology and the risk of
technological obsolescence, the significant capital requirements of the
Company's 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 the Company's
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 the Company's other filings with the Commission. Should one
or more
17
of these risks or uncertainties materialize, or should underlying assumptions
prove incorrect, actual outcomes may vary materially from those indicated.
EXPLORATORY DRILLING IS A SPECULATIVE ACTIVITY AND INVOLVES NUMEROUS RISKS AND
SUBSTANTIAL AND UNCERTAIN COSTS
The success of the Company will be materially dependent upon the success of
its future exploratory drilling program. Exploratory drilling 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 the Company's
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
the Company believes that its use of 3-D seismic data and other advanced
technology should increase the probability of success of its exploratory wells
and should reduce average finding costs through elimination of prospects that
might otherwise be drilled solely on the basis of 2-D seismic data and other
traditional methods, exploratory drilling remains a speculative activity. Even
when fully utilized and properly interpreted, 3-D seismic data and visualization
techniques only assist geoscientists in identifying subsurface structures and do
not allow the interpreter to know if hydrocarbons will in fact be present in
such structures if they are drilled. In addition, the use of 3-D seismic data
and such technologies requires greater pre-drilling expenditures than
traditional drilling strategies and the Company could incur losses as a result
of such expenditures. The Company's future drilling activities may not be
successful and, if unsuccessful, such failure will have an adverse effect on the
Company's future results of operations and financial condition. There can be no
assurance that the Company's overall drilling success rate or its drilling
success rate for activity within a particular project area will not decline.
Although the Company may discuss drilling prospects that it has identified or
budgeted for, the Company may ultimately not lease or drill these prospects
within the expected time frame, or at all. The Company 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. The Company may not be able to lease or drill a
particular prospect because, in some cases, it identifies a prospect or drilling
location before seeking an option or lease rights in the prospect or location.
Similarly, the Company's drilling schedule may vary from its capital budget. 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."
OIL AND NATURAL GAS PRICES ARE HIGHLY VOLATILE IN GENERAL AND LOW PRICES
NEGATIVELY AFFECT THE COMPANY'S FINANCIAL RESULTS
The Company's revenue, profitability, cash flow, future growth and ability
to borrow funds or obtain additional capital, as well as the carrying value of
its properties, are substantially dependent upon prevailing prices of oil and
natural gas. The Company's reserves are predominantly natural gas; therefore
changes in natural gas prices may have a particularly large impact on its
financial results. Lower oil and natural gas prices also may reduce the amount
of oil and natural gas that the Company 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 the control of the Company. These factors
include the level of consumer product demand, weather conditions, domestic and
foreign governmental regulations, the price and availability of alternative
fuels, political conditions, the foreign supply of oil and natural gas, the
price of foreign imports and overall economic conditions.
18
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 the Company's 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."
The Company reviews on a quarterly basis the carrying value of its 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. The Company
has in the past and may in the future be required to write down the carrying
value of its oil and natural gas properties when oil and natural gas prices are
depressed or unusually volatile. Whether the Company 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 its exposure to short-term fluctuations in the price of
oil and natural gas, the Company periodically enters into hedging arrangements.
The Company's hedging arrangements apply to only a portion of its production and
provide only partial price protection against declines in oil and natural gas
prices. Such hedging arrangements may expose the Company to risk of financial
loss in certain circumstances, including instances where production is less than
expected, the Company's customers fail to purchase contracted quantities of oil
or natural gas or a sudden, unexpected event materially impacts oil or natural
gas prices. In addition, the Company's hedging arrangements limit the benefit to
the Company of increases in the price of 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
AND DEVELOPMENT
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 the Company acquires properties
containing proved reserves or conducts successful exploration and development
activities, or both, the proved reserves of the Company will decline. The
Company's future oil and natural gas production is, therefore, highly dependent
upon its level of success in finding or acquiring additional reserves. In
addition, the Company is dependent on finding partners for its exploratory
activity. To the extent that others in the industry do not have the financial
resources or choose not to participate in the Company's exploration activities,
the Company will be adversely affected.
THE COMPANY IS 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. The
Company could suffer substantial losses as a result of any of these events. The
Company is not fully insured against all risks incident to its business.
19
The Company is not the operator of some of its wells. As a result, its
operating risks for those wells and its ability to influence the operations for
these wells is less subject to its control. Operators of these wells may act in
ways that are not in the best interests of the Company. See ITEMS 1 AND 2.--
"BUSINESS AND PROPERTIES--OPERATING HAZARDS AND INSURANCE."
THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT THE COMPANY
The Company depends to a large extent on the services of certain key
management personnel, including its executive officers and other key employees,
the loss of any of which could have a material adverse effect on the Company's
operations. The Company does not maintain key-man life insurance with respect to
any of its employees. The Company believes that its success is also dependent
upon its ability to continue to employ and retain skilled technical personnel.
See ITEMS 1 AND 2.--"BUSINESS AND PROPERTIES--Exploration Technology."
THE COMPANY'S SUCCESS DEPENDS ON ITS ABILITY TO UTILIZE CHANGING TECHNOLOGY AND
IT FACES THE RISK OF TECHNOLOGICAL OBSOLESCENCE
The Company believes that its ability to utilize state of the art
technologies currently gives it an advantage over many of its competitors. This
advantage, however, is based in part upon technologies developed by others, and
the Company may not be able to maintain this advantage. The Company's business
is dependent upon utilization of changing technology. As a result, the Company's
ability to adapt to evolving technologies, obtain new products and maintain
technological advantages will be important to its future success. There can be
no assurance that the Company will be able to successfully utilize, or expend
the financial resources necessary to acquire, new technology. One or more of the
technologies currently utilized by the Company or implemented in the future may
become obsolete. If any of these events were to occur, the Company's business,
financial condition and results of operations could be materially adversely
affected. See ITEMS 1 AND 2.--"BUSINESS AND PROPERTIES--Exploration Technology."
THE COMPANY'S OPERATIONS HAVE SIGNIFICANT CAPITAL REQUIREMENTS
The Company has experienced and expects to continue to experience
substantial working capital needs due to its active exploration and development
and technology development programs. Additional financing may be required in the
future to fund the Company's growth and developmental and exploratory drilling
and continued technological development. No assurances can be given as to the
availability or terms of any such additional financing that may be required or
that financing will continue to be available under existing or new credit
facilities. In the event such capital resources are not available to the
Company, its drilling and other activities may be curtailed. See 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 THE COMPANY'S 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
20
used in connection with oil and natural gas operations. In addition, the Company
may be liable for environmental damages caused by previous owners of property it
purchases or leases. As a result, the Company may incur substantial liabilities
to third parties or governmental entities. The Company is 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 the Company. See ITEMS 1 AND
2.--"BUSINESS AND PROPERTIES--INDUSTRY REGULATIONS."
THE COMPANY IS SUBJECT TO SIGNIFICANT LITIGATION
The Company is subject to litigation described in "ITEM 3.--LEGAL
PROCEEDINGS." No assurance can be provided as to the outcome of the matter
described therein or the timing of the related proceedings. An adverse outcome
in that matter could have a material adverse effect on the Company.
THE COMPANY MAY HAVE DIFFICULTY MANAGING ANY FUTURE GROWTH AND THE RELATED
DEMANDS ON ITS RESOURCES AND MAY HAVE DIFFICULTY IN ACHIEVING FUTURE GROWTH
The Company has experienced growth in the past through the expansion of its
drilling program. This expansion was curtailed in 1998 and 1999, but resumed in
2000 and is expected to be increased in 2001. Any future growth may place a
significant strain on the Company's financial, technical, operational and
administrative resources. The Company's ability to grow will depend upon a
number of factors, including its ability to identify and acquire new exploratory
sites, its ability to develop existing sites, its ability to continue to retain
and attract skilled personnel, the results of its drilling program, hydrocarbon
prices and access to capital. There can be no assurance that the Company will be
successful in achieving growth or any other aspect of its business strategy.
THE COMPANY FACES STRONG COMPETITION FROM LARGER OIL AND NATURAL GAS COMPANIES
The Company's competitors include major integrated oil and natural gas
companies and numerous independent oil and natural gas companies, individuals
and drilling and income programs. Many of its competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than the Company. The Company may not be able to
successfully conduct its 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 the
Company's financial or human resources permit. In addition, such companies may
be able to expend greater resources on the existing and changing technologies
that the Company believes are and will be increasingly important to 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
INTO 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 which 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
21
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. In particular, natural gas prices have fallen
significantly from the December 31, 2000 prices used in determining year end
reserves and estimated future net revenue. SEE ITEMS 1 AND 2.--"BUSINESS AND
PROPERTIES--OIL AND NATURAL GAS RESERVES." Actual production, revenue and
expenditures with respect to the Company's 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 the Company's 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 the Company or the oil and
natural gas industry in general. See ITEMS 1 AND 2.--"BUSINESS AND
PROPERTIES--Oil and Natural Gas Reserves."
THE COMPANY'S CREDIT FACILITY HAS SUBSTANTIAL OPERATING RESTRICTIONS AND
FINANCIAL COVENANTS AND IT MAY HAVE DIFFICULTY OBTAINING ADDITIONAL CREDIT
Until recently, the limited availability of additional credit under the
terms of the Company's revolving credit facility reduced the Company's
flexibility to changing business and economic conditions and limited its ability
to increase the Company's capital expenditures. The recent increase in commodity
prices, the increase in proved reserve amounts and the resultant increase in
estimated discounted future net revenue, has allowed the Company to both reduce
debt and increase its available borrowing amounts. There can be no assurance
that, in the future, commodity prices will not decline, the Company will not
increase its borrowings or the borrowing base will not be adjusted downward. The
Company's credit facility is secured by a pledge of substantially all of the
Company's assets and has covenants that limit additional borrowings, sales of
assets and that prohibit the payment of dividends, the incurrence of liens and
limit the distributions of cash or properties. The revolving credit facility
also requires that specified financial ratios be maintained. The restrictions of
the Company's credit facility and the difficulty in obtaining additional debt
financing may have adverse consequences on the Company's operations and
financial results, including the Company's ability to obtain financing for
working capital, capital expenditures, the Company's drilling program, purchases
of new technology or other purposes may be impaired or such financing may be on
terms unfavorable to the Company; the Company may be required to use a
substantial portion of its 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 the Company's operating cash
flow or an increase in its expenses could make it difficult for it to meet debt
service requirements and require it to modify operations; and the Company may
become more vulnerable to downturns in its business or the economy generally.
The Company's ability to obtain and service indebtedness will depend on its
future performance, including its ability to manage cash flow and working
capital, which are in turn subject to a variety of factors beyond its control.
The Company's business may not generate cash flow at or above anticipated levels
or it may not be able to borrow funds in amounts sufficient to enable us to
service indebtedness, make anticipated capital expenditures or finance its
drilling program. If the Company is unable to
22
generate sufficient cash from operations or to borrow sufficient funds in the
future to service its debt, the Company may be required to curtail portions of
its drilling program, sell assets, reduce capital expenditures, refinance all or
a portion of its existing debt or obtain additional financing. The Company may
not be able to refinance its debt or obtain additional financing, particularly
in view of current industry conditions, the restrictions on its ability to incur
debt under its existing debt arrangements, and the fact that substantially all
of its assets are currently pledged to secure obligations under its 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."
THE COMPANY'S ACQUISITION PROGRAM MAY BE UNSUCCESSFUL, PARTICULARLY IN LIGHT OF
THE COMPANY'S LIMITED ACQUISITION EXPERIENCE
The Company generally seeks to explore for oil and natural gas rather than
to purchase producing properties. Because the Company has not typically
purchased properties, it may not be in as good a position as its 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 companies, are necessarily
inexact and their accuracy inherently uncertain. The Company's 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. The Company may not always
perform inspections on every well, and may not be able to observe structural and
environmental problems even when it undertakes 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 the Company will be
successful and, if unsuccessful, that such failure will not have an adverse
effect on the Company's future results of operations and financial condition.
THE COMPANY DOES NOT INTEND TO PAY DIVIDENDS AND ITS ABILITY TO PAY DIVIDENDS IS
RESTRICTED
The Company currently intends to retain any earnings for the future
operation and development of its business and does not currently anticipate
paying any dividends in the foreseeable future. Any future dividends also may be
restricted by the Company's then-existing loan agreements. See ITEM 7.--
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Liquidity and Capital Resources" and Note 3 to the Company's
Consolidated Financial Statements.
THE COMPANY CANNOT MARKET ITS PRODUCTION WITHOUT THE ASSISTANCE OF THIRD PARTIES
The marketability of the Company's production depends upon the proximity of
its reserves to, and the capacity of facilities, third party services and
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 the Company's financial
condition. In addition, federal and state regulation of oil and natural gas
production and transportation affect the Company's ability to produce and market
its oil and natural gas on a profitable basis.
23
PROVISIONS OF DELAWARE LAW AND THE COMPANY'S CHARTER AND BYLAWS MAY DELAY OR
PREVENT TRANSACTIONS THAT WOULD BENEFIT STOCKHOLDERS
The Company's Certificate of Incorporation and Bylaws and the Delaware
General Corporation Law contain provisions that may have the effect of delaying,
deferring or preventing a change of control of the Company. These provisions,
among other things, provide for a classified Board of Directors with staggered
terms, restrict the ability of stockholders to take action by written consent,
authorize the Board of Directors to set the terms of Preferred Stock, and
restrict the Company's 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 the
Company's board of directors rather than pursue non-negotiated takeover
attempts. As a result, these provisions may make it more difficult for
stockholders of the Company 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.
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.
24
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 the Company pursuant to
generally accepted accounting principles, including all costs involved in
acquiring acreage, geological and geophysical work and the cost of drilling and
completing wells, 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.
MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons.
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.
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. Are 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
25
future development costs, using prices and costs in effect as of the date
indicated, without giving effect to nonproperty-related expenses such as general
and administrative expenses, debt service and future income tax expense or to
depletion, depreciation, and amortization, discounted using an annual discount
rate of 10%.
PRODUCTIVE WELL. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceeds production expenses and taxes.
PROVED DEVELOPED NONPRODUCING RESERVES. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
PROVED DEVELOPED PRODUCING RESERVES. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.
PROVED DEVELOPED RESERVES. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED LOCATION. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
RECOMPLETION. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
RESERVOIR. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
ROYALTY INTEREST. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.
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.
26
ITEM 3. LEGAL PROCEEDINGS
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.
The Company, as one of three original plaintiffs, has 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 are, 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 seeks to enforce its interest in the prospect and seeks 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, 2000. All parties rested on the plaintiffs'
claims on September 13, 2000. The court took the matter under advisement and has
not yet announced a ruling. 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.
27
During the week of December 11-15, 2000, 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 loss of the lease development
opportunity, and $308 million for 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. At the conclusion of this trial, the court
took the matter under advisement. The parties have filed overviews of the
evidence, proposed findings of fact and conclusions of law and proposed charges
The court has not yet ruled but has requested that the parties file proposed
forms of judgment.
While the Company believes it has presented sufficient legal and factual
defenses to all of the defendants' counterclaims, and has vigorously defended
itself in this matter, there can be no assurance that the outcome of any portion
of this litigation will be favorable to the Company. In the possible event of a
material adverse outcome on the counterclaims or related matters, there could be
a material adverse effect on the Company. In that event, the Company might well
be required to post a bond in the amount of the judgment (or the portion of the
counterclaim judgment for which it has liability) in order to prevent the
defendants from executing on that judgment. Depending on the amount of such a
judgment, there could be no assurance that the Company could obtain such a bond
or pay the judgment. In the event of an adverse judgment, the Company would
likely appeal such judgment, and the Company is optimistic about its chances for
success on appeal, should such be necessary. However, there can be no assurance
as to the outcome of this matter.
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 (chairman) 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 including senior management
positions with Amoco Corporation, a major integrated oil and gas company.
Mr. Elias has more than 35 years of experience in the oil and natural gas
exploration and production business. He is 60 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 48 years old.
28
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.
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.
JOHN O. TUGWELL has served as the Vice President of Production for the
Company since March 1997 and prior thereto 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.
29
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
As of March 19, 2001, the Company estimates there were approximately 2,807
beneficial holders of its Common Stock. The Company's Common Stock is listed on
the NASDAQ National Market ("NASDAQ") and traded under the symbol "EPEX". As of
March 19, 2001, the Company had 9,252,139 shares outstanding and its closing
price on NASDAQ was $7.44 per share. The following table sets forth, for the
periods indicated, the high and low closing sales prices for Common Stock of the
Company as listed on NASDAQ.
COMMON
STOCK
---------------------
HIGH LOW
($) ($)
--------- ---------
CALENDAR 2000
First Quarter............................................... 4 2 1/8
Second Quarter.............................................. 3 3/8 1 3/4
Third Quarter............................................... 4 3/8 2 5/8
Fourth Quarter.............................................. 9 7/8 3 3/4
CALENDAR 1999
First Quarter............................................... 5 3/4 4 1/8
Second Quarter.............................................. 7 1/2 4 5/8
Third Quarter............................................... 7 1/4 5 5/8
Fourth Quarter.............................................. 7 1/4 2 1/2
The Company has never paid a dividend, cash or otherwise and does not intend
to in the foreseeable future. The payment of future dividends will be determined
by the Company's Board of Directors in light of conditions then existing,
including the Company's 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--The Company does not intend to pay dividends and its ability to pay
dividends is restricted."
30
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 Analysis of Financial Condition
and Results of Operations" and the Company's financial statements and notes
thereto, which follow:
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2000 1999 1998 1997 1996(4)
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
OPERATIONAL DATA:
Oil and natural gas revenue.................... $23,774 $14,486 $ 15,463 $ 13,468 $ 7,719
Operating expenses:
Oil and natural gas operating expenses
including production and ad valorem
taxes...................................... 3,955 3,039 3,376 2,331 1,600
Depletion, depreciation and amortization..... 7,641 8,512 10,002 2,876 1,613
Impairment of oil and natural gas
properties................................. -- -- 10,013 -- --
General and administrative expenses.......... 3,824 4,528 4,583 4,641 2,753
Deferred compensation expense(1)............. 1,004 -- -- -- --
Unearned compensation expense................ 23 350 621 513 --
Other charge................................. -- 1,688 2,898 -- --
------- ------- -------- -------- -------
Total operating expenses................... 16,447 18,117 31,493 10,361 5,966
------- ------- -------- -------- -------
Operating income (loss)........................ 7,327 (3,631) (16,030) 3,107 1,753
Interest expense and amortization of deferred
loan costs................................. (172) (130) (90) (183) (859)
Interest income.............................. 98 52 133 901 --
Gain (loss) on sale of investment............ (355) -- -- -- 233
------- ------- -------- -------- -------
Net income (loss) before income taxes, minority
interest and cumulative effect of accounting
change....................................... 6,898 (3,709) (15,987) 3,825 1,127
Net income tax (expense) benefit............. -- -- 983 -- (394)
Minority interest............................ -- -- -- -- (433)
------- ------- -------- -------- -------
Net income (loss) before cumulative effect of
accounting change............................ 6,898 (3,709) (15,004) 3,825 300
Cumulative effect of accounting change....... -- -- 1,781 -- --
------- ------- -------- -------- -------
Net income (loss).............................. $ 6,898 $(3,709) $(13,223) $ 3,825 $ 300
======= ======= ======== ======== =======
Basic income (loss) per share:(2)
Net income (loss) before cumulative effect of
accounting change.......................... $ 0.75 $ (0.43) $ (1.93) $ 0.53 $ 0.06
Cumulative effect of accounting change....... -- -- 0.23 -- --
------- ------- -------- -------- -------
Basic earnings (loss) per share.............. $ 0.75 $ (0.43) $ (1.70) $ 0.53 $ 0.06
======= ======= ======== ======== =======
Diluted income (loss) per share:(2)
Net income (loss) before cumulative effect of
accounting change.......................... $ 0.74 $ (0.43) $ (1.93) $ 0.52 $ 0.06
Cumulative effect of accounting change....... -- -- 0.23 -- --
------- ------- -------- -------- -------
Diluted earnings (loss) per share............ $ 0.74 $ (0.43) $ (1.70) $ 0.52 $ 0.06
======= ======= ======== ======== =======
Basic weighted average number
of shares outstanding(2)..................... 9,183 8,680 7,759 7,275 4,701
Diluted weighted average number of shares
outstanding(2)............................... 9,330 8,680 7,759 7,320 4,701
31
YEAR ENDED DECEMBER 31,
----------------------------------------------------
2000 1999 1998 1997 1996(4)
-------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
SELECT CASH FLOW DATA:
EBITDA(3)...................................... $14,711 $ 4,933 $ 4,118 $ 6,884 $ 3,166
Capital expenditures........................... 10,718 14,588 34,824 29,874 10,467
Net cash provided by operating activities...... 10,659 5,913 11,983 4,145 2,278
Net cash used in investing activities.......... (5,395) (7,259) (27,989) (31,177) (5,651)
Net cash provided by (used in) financing
activities................................... (4,003) 1,651 12,500 29,266 4,716
AS OF DECEMBER 31,
----------------------------------------------------
2000 1999 1998 1997 1996(4)
-------- -------- -------- -------- --------
(IN THOUSANDS)
SELECT BALANCE SHEET DATA:
Working capital surplus (deficit)........... $ 2,879 $(4,977) $ (8,255) $ 7,603 $ 690
Property and equipment, net................. 47,242 45,976 47,259 36,663 11,989
Total assets................................ 58,533 55,318 56,279 53,766 19,556
Long-term debt, including current
maturities................................ 3,000 6,800 12,500 -- 11,862
Stockholders' equity (deficit).............. 50,129 42,174 36,956 47,911 (373)
- ------------------------
(1) Non-cash charge as required under FASB Interpretation No. (FIN) 44,
ACCOUNTING FOR CERTAIN TRANSACTIONS INVOLVING STOCK COMPENSATION. 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.
(2) 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.
(3) EBITDA represents income (loss) before cumulative effect of accounting
change, interest expense, income taxes, depletion, depreciation and
amortization and impairment. Management of the Company believes that EBITDA
may provide additional information about the Company's ability to meet its
future requirements for debt service, capital expenditures and working
capital. EBITDA is a financial measure commonly used 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.
(4) The Combination (as defined herein) was accounted for as a reorganization of
entities under common control. Accordingly, as of and for the year ended
December 31, 1996, the consolidated accounts are presented using the
historical costs and results of operations of the affiliated entities as if
such entities had always been combined. Accordingly the consolidated
financial statements include the accounts of Edge Petroleum Corporation, a
Texas corporation, ("Old Edge"), and Edge Joint Venture II (the "Joint
Venture"). The Joint Venture interests not owned by Old Edge is recorded as
minority interest.
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is a review of the Company's financial position and results of
operations for the periods indicated. The Company's 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.
GENERAL OVERVIEW
The Company was organized as a Delaware corporation in August 1996 in
connection with its initial public offering (the "Offering") and the related
combination of certain entities that held interests in 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 Offering of 2,760,000 shares of its common stock
generating proceeds of approximately $40 million, net of expenses.
The Company began operations in 1983 and until 1992 generated exploratory
drilling prospects based on 2-D seismic data for sale to other exploration and
production companies. During 1992, as a result of the advent of economic onshore
3-D seismic surveys and the improvement and increased affordability of data
interpretation technologies, the Company changed its strategy to emphasize
exploration based upon the use of 3-D seismic data. From 1992 to 1995, the
Company reduced its inventory of 2-D based prospects, began limited drilling for
its own account and began developing prospects based on 3-D seismic data. Since
early 1995, the Company has almost exclusively drilled prospects generated from
3-D seismic data, while accelerating its drilling activity and increasing its
working interests in new project areas primarily in South Texas and Louisiana.
The Company uses the full-cost method of accounting for its 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 the Company's acquisition, exploration and development
activities, are capitalized in a "full-cost pool" as incurred. The Company
records depletion of its full-cost pool using the unit of production method.
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 in
conjunction with the Company's quarterly filings with the Commission. During the
years ended December 31, 2000 and 1999 no full cost ceiling test write down was
necessary. At December 31, 1998 the Company recorded a full cost ceiling test
write down of its oil and natural gas properties of approximately
$10.0 million.
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
and collars) for a portion of its oil and natural gas production to achieve a
more predictable cash flow, as well as to reduce exposure from price
fluctuations. While the use of these arrangements limits the benefit to the
Company of increases in the price of oil and natural gas it also limits the
downside risk of adverse price movements. The Company's hedging arrangements
typically apply to only a portion of its production, providing only partial
price protection against declines in oil and natural gas prices and limiting
potential gains from future increases in prices. The Company accounts for these
transactions as hedging activities and, accordingly,
33
gains and losses are included in oil and natural gas revenues during the period
the hedged production occurs. In December 2000, the Company entered into a
natural gas collar. The natural gas collar covers 4,000 MMbtus per day for the
period January 1, 2001 to December 31, 2001 at a $4.50 floor and a $6.70
ceiling. At December 31, 2000 and 1999, the fair value, gain (loss), of
outstanding hedges was approximately $(1.1) million and $15,000, respectively.
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. (See Note 4 to the consolidated
financial statements).
The Company's revenue, profitability and future rate of growth and ability
to borrow funds or obtain additional capital, and the carrying value of its
properties, are substantially dependent upon prevailing prices for oil and
natural gas. These prices are dependent upon numerous factors beyond the
Company's control, such as economic, political and regulatory developments and
competition from other sources of energy. Even though oil and natural gas
commodity prices have recovered from previously low prices, a substantial or
extended decline in oil and natural gas prices could have a material adverse
effect on the Company's financial condition, results of operations and access to
capital, as well as the quantities of oil and natural gas reserves that the
Company may economically produce.
RESULTS OF OPERATIONS
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
$23.8 million in 2000. For 2000, natural gas production comprised 83% of total
production and contributed 84% of total revenue, oil and condensate comprised 9%
of total production and contributed 11% of total revenue, and natural gas
liquids (NGLs) comprised 8% of total production and contributed 5% of total
revenue. For 1999, natural gas production comprised 83% of total production and
81% of total revenue while oil and condensate production accounted for 10% of
total production and 13% of revenue and NGLs production comprised 7% of total
production and 6% of oil and gas revenue.
The following table summarizes production volumes, average sales prices and
operating revenue for the Company's oil and natural gas operations for the years
ended December 31, 2000 and 1999.
2000 PERIOD COMPARED
TO 1999 PERIOD
DECEMBER 31, -----------------------
------------------------- INCREASE % INCREASE
2000 1999 (DECREASE) (DECREASE)
----------- ----------- ---------- ----------
PRODUCTION VOLUMES:
Natural gas (Mcf).......................... 5,206,236 5,675,938 (469,702) (8)%
Oil and condensate (Bbls).................. 96,925 112,089 (15,164) (14)%
Natural gas liquids (Bbls)................. 76,835 75,134 1,701 2%
Natural gas equivalent (Mcfe).............. 6,248,796 6,799,276 (550,480) (8)%
AVERAGE SALES PRICE:
Natural gas ($ per Mcf).................... $ 3.84 $ 2.07 $ 1.77 86%
Oil and condensate ($ per Bbl)............. 26.16 16.15 10.01 62%
Natural gas liquids ($ per Bbl)............ 16.37 12.16 4.21 35%
Natural gas equivalent ($ per Mcfe)........ 3.80 2.13 1.67 78%
OPERATING REVENUE:
Natural gas................................ $19,980,704 $11,762,490 $8,218,214 70%
Oil and condensate......................... 2,536,028 1,810,043 725,985 40%
Natural gas liquids........................ 1,257,684 913,462 344,222 38%
----------- ----------- ----------
Total........................................ $23,774,416 $14,485,995 $9,288,421 64%
=========== =========== ==========
34
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. 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 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 MCFPD in 1999 to 14.2 MCFPD 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
$223,455), 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 BPD for the year ended December 31, 2000
compared to 307 BPD 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 BPD to 210 BPD, 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 $1,960,640
compared to $1,742,415 in the same period of 1999, an increase of 13%. Current
year results 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 operation 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.
35
Severance and ad valorem taxes for 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 year 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 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 non-cash charge to compensation expense discussed below,
totaled $3.9 million, a 13% 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 $0.63 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. 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. The charge is
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.
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 is 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.
The Company charged to expense the unamortized unearned compensation associated
with his restricted stock upon his resignation, thereby reducing the future
amounts to be charged to income.
The other charge during 1999 of approximately $1.7 million primarily
represents expenses incurred as a result of the resignation of the Company's
former President and Chief Operating Officer in 1999. 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 the
vesting of the remaining balance of the executive's restricted common stock
award granted concurrent with Company's Offering (see Note 8 to the consolidated
financial statements). The balance of the charge primarily represents 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.
36
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) or
$(0.04) per share.
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.
Gross interest expense was $546,340 for the year 2000 on weighted average debt
of $5.6 million compared to gross interest expense of $662,067 on weighted
average debt of approximately $8.4 million for the same prior year period.
Included in gross 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 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 $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. Due to the uncertainty as to whether
we will be profitable in the future, an allowance has been provided to offset
the tax benefits of certain tax assets. Should we continue to have net income in
future periods, incurred tax expense will be recorded upon utilization of
available tax assets.
For the year ended December 31, 2000 the Company had net income of
$6.9 million, or $0.75 basic earnings per share, as compared to a net loss of
$3.7 million, or $(0.43) basic earnings per share, 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.
YEAR ENDED DECEMBER 31, 1999 COMPARED TO THE YEAR ENDED DECEMBER 31, 1998
REVENUE AND PRODUCTION
Oil and natural gas revenue decreased 6% from $15.5 million in 1998 to
$14.5 million in 1999. Production volumes for natural gas decreased 10% from
6,284,495 Mcf in 1998 to 5,675,938 Mcf in 1999. The decrease in natural gas
production reduced revenues by approximately $1.3 million. A 5% decrease in
average natural gas prices further reduced revenues by approximately $630,000. A
35% increase in average oil and condensate prices increased revenue by
approximately $469,100 for 1999 over 1998. This was partly offset by the impact
of a decrease in oil and condensate production of 11% from 126,252 barrels in
1998 to 112,089 barrels in 1999. The decrease in oil production negatively
impacted revenue by approximately $169,400. NGL production for the year ended
December 31, 1999 increased from 15,522 barrels in 1998 to 75,134 barrels in
1999, increasing revenue by approximately $890,700. This was partly offset by
the impact of a 19% decrease in average NGL prices, which reduced revenue by
approximately $209,200. The overall net decrease in oil and natural gas
production was primarily due to a sale of producing oil and natural gas
properties effective July 1, 1999 which effectively reduced production during
the second half of 1999 by approximately 500,000 Mcfe. Oil and natural gas
production was further reduced during 1999 by production declines from existing
wells offset by production from 14 new gross, (5.34 net), producing exploratory
and development wells drilled and completed since December 31, 1998. Included
within natural gas revenues for the two years ended
37
December 31, 1999 and 1998 was approximately $(1.1) million and $482,000,
respectively, representing net (losses) and net gains from hedging activity. The
hedging settlements decreased the effective average natural gas prices by
$(0.19) per Mcf for the year ended December 31, 1999 and increased the effective
average natural gas prices by $0.07 per Mcf for the year ended December 31,
1998.
The following table summarizes production volumes, average sales prices and
operating revenue for the Company's oil and natural gas operations for the years
ended December 31, 1999 and 1998.
1999 PERIOD COMPARED
TO 1998 PERIOD
DECEMBER 31, ------------------------
------------------------- INCREASE % INCREASE
1999 1998 (DECREASE) (DECREASE)
----------- ----------- ----------- ----------
PRODUCTION VOLUMES:
Natural gas (Mcf).......................... 5,675,938 6,284,495 (608,557) (10)%
Oil and condensate (Bbls).................. 112,089 126,252 (14,163) (11)%
Natural gas liquids (Bbls)................. 75,134 15,522 59,612 384%
Natural gas equivalent (Mcfe).............. 6,799,276 7,135,139 (335,863) (5)%
AVERAGE SALES PRICE:
Natural gas ($ per Mcf).................... $ 2.07 $ 2.18 $ (0.11) (5)%
Oil and condensate ($ per Bbl)............. 16.15 11.96 4.19 35%
Natural gas liquids ($ per Bbl)............ 12.16 14.94 (2.78) (19)%
Natural gas equivalent ($ per Mcfe)........ 2.13 2.17 (0.04) (2)%
OPERATING REVENUE:
Natural gas................................ $11,762,490 $13,721,121 $(1,958,631) (14)%
Oil and condensate......................... 1,810,043 1,510,384 299,659 20%
Natural gas liquids........................ 913,462 231,927 681,535 294%
----------- ----------- -----------
Total........................................ $14,485,995 $15,463,432 $ (977,437) (6)%
=========== =========== ===========
COSTS AND OPERATING EXPENSES
Oil and natural gas operating expenses, including production and ad valorem
taxes, decreased 10% from $3.4 million in 1998 to $3.0 million in 1999. Oil and
natural gas operating expenses, including production and ad valorem taxes, on a
unit of production basis were $0.45 per Mcfe and $0.47 per Mcfe for the years
ended December 31, 1999 and 1998, respectively. The decrease in per unit costs
reflects an intensive monitoring of field level costs plus the addition of
several high volume low cost wells to the production stream during 1999.
DD&A decreased 15% from $10.0 million in 1998 to $8.5 million in 1999.
Included within DD&A for the years ended December 31, 1998 and 1999 was
$9.3 million and $7.8 million, respectively, representing depletion expense of
oil and natural gas properties. An 11% decrease in the overall depletion rate
decreased depletion expense by approximately $1.0 million. The decrease in the
depletion rate was primarily due to a full cost ceiling test write-down of oil
and natural gas properties of approximately $10 million at December 31, 1998
offset by the abandonment of certain properties during the fourth quarter of
1999. Decreased oil and natural gas production further decreased depletion
expense by approximately $436,000. Depletion on a unit of production basis for
the years ended December 31, 1999 and 1998 was $1.15 per Mcfe and $1.30 per
Mcfe, respectively. The remaining decrease in DD&A was due primarily to the
amortization of deferred loan costs on the Revolving Credit Facility, which were
fully amortized at March 31, 1999.
The Commission requires that the carrying cost of proved reserves be
assessed periodically for ceiling test impairment. At December 31, 1998, as a
result of the Company's carrying cost of proved reserves being in excess of the
present value using a discount rate of 10%, the Company recorded a full
38
cost ceiling test write down of its oil and natural gas properties of
approximately $10.0 million. At December 31, 1999, no ceiling test write down
was necessary.
G&A decreased 1% from $4.6 million in 1998 to $4.5 million in 1999. Included
as a reduction in G&A for the years ended December 31, 1999 and 1998, was
approximately $285,000 and $743,000, respectively, of overhead reimbursements
and management fees received from various management, operating and seismic
agreements. Excluding the reduction of G&A attributable to overhead
reimbursements, G&A decreased by approximately $558,000 due primarily to lower
costs of outside professional services, discontinuing of international new
business development and a Company-wide focus on cost reduction. General and
administrative expenses on a unit of production basis for the years ended
December 31, 1999 and 1998 were $0.67 per Mcfe and $0.64 per Mcfe, respectively.
The increase in G&A on a per unit of production basis was due to lower
production volumes during 1999 which were largely attributable to the mid-year
sale of proved producing properties referred to above.
Unearned compensation expense decreased 44% from $621,191 in 1998 to
$349,623 in 1999. The amortization of unearned compensation expense is
recognized from restricted stock granted to executives at the completion of the
Offering. The decrease is due to the resignation of the former CEO and Chairman
of the Board during November of 1998 whereby he vested in his remaining
restricted stock grant. The Company charged to expense during 1998 his remaining
unamortized unearned compensation upon his resignation.
The other charge during 1999 of approximately $1.7 million primarily
represents expenses incurred as a result of James D. Calaway's resignation as
President and 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 8 to the
consolidated financial statements). The balance of the special 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.
The other charge during 1998 of approximately $2.9 million primarily
represents expenses incurred as a result of John E. Calaway's resignation as
Chairman of the Board, Chief Executive Officer ("CEO") and Director of the
Company. As a result of his resignation the Company recorded a one-time charge
of approximately $2.9 million to satisfy corporate obligations under his
employment contract. Included in the $2.9 million is a $1.6 million non-cash
amount relating to vesting of the remaining balance of Mr. John Calaway's
restricted common stock award granted concurrent with the Company's Offering
(see Note 8 to the consolidated financial statements). The balance of the
special charge primarily represents cash payments to be paid to Mr. Calaway from
the date of his resignation to January 2000.
Interest expense for the years ended December 31, 1999 and 1998 was $130,067
and $90,075, respectively, net of interest capitalized to oil and natural gas
properties of approximately $532,000 and $411,000, respectively. The weighted
average debt was $8.4 million for the year ended December 31, 1999 compared to
$7 million for the same period in 1998.
Interest income for the year ended December 31, 1999 was $51,855 compared to
$132,993 for the same period in 1998. The decrease was due to the Offering
proceeds being fully deployed in operations by the end of the first quarter of
1998.
For the year ended December 31, 1998, the Company had a tax benefit of
$982,966. As a result of the cumulative effect of the accounting change, the
Company recorded a provision for taxes payable during the second quarter of 1998
with the corresponding tax expense being recorded as a reduction of the
cumulative effect of the accounting change. As a result of losses generated
during the second half
39
of 1998, a tax benefit was recognized to the extent of previously recorded
provision for taxes payable. Due to the availability of net operating loss carry
forwards and other net deferred tax assets there is no provision for current or
deferred taxes for the year ended December 31, 1999. As of December 31, 1999 and
1998, the Company had available a substantial net operating loss carryforward
and other net deferred tax assets and should the Company have taxable income in
future periods a provision for tax expense will be provided.
For the year ended December 31, 1999, the Company had an operating loss of
$3.6 million as compared to an operating loss of $16.0 million in 1998. The
significant decrease in the operating loss was primarily attributable to the
full cost ceiling test write down of approximately $10.0 million recorded in
1998. The operating loss during 1999 was further decreased by lower DD&A, lower
oil and natural gas operating expenses and lower G&A offset by lower oil and
natural gas revenue which was reduced due to a decline in natural gas production
(due to a mid-year property sale) and lower natural gas prices. Net loss for the
year ended December 31, 1999 was $3.7 million, or basic and diluted loss per
share of $0.43, as compared to net loss of $13.2 million, (a net loss of
$15.0 million before cumulative effect of accounting change), or basic and
diluted loss per share of $1.70 for 1998.
LIQUIDITY AND CAPITAL RESOURCES
In March 1997, the Company completed the Offering of 2,760,000 shares of its
common stock at a public offering price of $16.50 per share. The Offering
provided the Company with proceeds of approximately $40 million, net of
expenses. The Company used approximately $12.7 million to repay its long-term
outstanding indebtedness incurred under its revolving credit facility (the
"Revolving Credit Facility"), 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, 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 proceeding 20
consecutive trading days exceeds $10.70. No warrants have been exercised as of
December 31, 2000. Total proceeds, net of offering costs, were approximately
$7.4 million of which $4.9 million was used to repay debt under the Revolving
Credit Facility with the remainder being utilized to satisfy working capital
requirements and to fund a portion of the Company's exploration program.
Pursuant to the terms of the private placement, the Company 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.
The Company had cash and cash equivalents at December 31, 2000 of
$1.8 million consisting primarily of short-term money market investments, as
compared to $577,864 at December 31, 1999. Working capital was $2.9 million as
of December 31, 2000 as compared to $(5.0) million at December 31, 1999.
Excluding the current portion of long-term debt, working capital was
$5.9 million at December 31, 2000 compared to $(0.9) million at December 31,
1999.
Cash flows provided by operations were $10.7 million, $5.9 million and
$12.0 million, for the years ended December 31, 2000, 1999, and 1998,
respectively. The significant increase in cash flows provided by operations for
the year ended December 31, 2000 is primarily due to net income of $6.9 million
for the year ended December 31, 2000 compared to a net loss of $(3.7) million in
1999, partially offset by an increase in trade accounts receivable. High
commodity prices during the fourth quarter of 2000 resulted in substantial
accounts receivable balances for production revenue received in 2001. Operating
40
cash flows, before changes in working capital, were $15.9 million for the year
ended December 31, 2000 and $6.3 million for years ended December 31, 1999 and
1998, respectively. This increase was primarily due to higher oil and natural
gas revenues during 2000 as a result of higher average commodity prices that
were partly offset by lower production.
The Company reinvests a substantial portion of its cash flows to increase
its 3-D project portfolio, improve its 3-D seismic interpretation technology and
to fund its drilling program. As a result, the Company used $5.4 million in
investing activities during 2000 including capital expenditures of approximately
$10.7 million. Capital expenditures of $5.7 million were attributed to drilling
of 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, the Company 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, the Company completed a transaction in which
it sold, effective July 1, 1999, its working interests in proved producing and
undeveloped properties within its BTA and Spartan Extension 3-D project areas in
Goliad and Victoria Counties, Texas. Proceeds from the sale were approximately
$4.0 million.
During the year ended December 31, 1998, the Company continued to reinvest a
substantial portion of its cash flows to increase its 3-D project portfolio,
improve its 3-D seismic interpretation technology and fund its drilling program.
As a result, the Company used $28 million in investing activities during 1998
including capital expenditures of approximately $34.8 million for oil and
natural gas property development offset by proceeds from the sale of oil and
natural gas prospects of $7 million. Capital expenditures of $13.5 million were
attributed to the drilling of 83 gross wells, 55 of which were successful, with
the majority of the remaining capital expenditures representing additions to
undeveloped oil and natural gas properties which has expanded and diversified
our portfolio of future drilling opportunities.
Pursuant to a rights offering conducted by Frontera in November 1998, the
Company agreed to purchase 44,027 shares of 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 Frontera Common Stock and $116,672 in
April 1999 for 44,027 shares of Frontera Common Stock bring its total investment
in Frontera to $3,867,233. The Company sold its interest in Frontera in
June 2000 for net proceeds of $3.5 million.
The Company expects capital expenditures in 2001 to be approximately
$23 million including capitalized interest and G&A of approximately
$1.5 million. A substantial portion of capital expenditures in 2001 will be
invested in the Company's portfolio of prospects to fund drilling activities
(approximately 28 gross wells) in an effort to expand its reserve base. In
addition, the Company will seek to continue to expand and improve its
technological and seismic interpretation capabilities.
Cash flows used in financing activities in 2000 were $(4.0) million compared
to cash flows from financing activities of $1.7 million in 1999. Financing
activities during 2000 included borrowings of
41
$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.
Financing activities during 1998 were comprised of borrowings on the Company's
previous revolving credit facility.
Due to the Company's active exploration and development and technology
enhancement programs, the Company has experienced and expects to continue to
experience substantial working capital requirements. The Company intends to fund
its 2001 capital expenditures, commitments and working capital requirements
through cash flows from operations, and to the extent necessary other financing
activities. The projected 2001 cash flows from operations are projected to be
sufficient to fund its budgeted exploration and development program and to
provide additional working capital. The Company believes it will be able to
generate capital resources and liquidity sufficient to fund its capital
expenditures and meet such financial obligations as they come due. In the event
such capital resources are not available to the Company, its 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 "New Credit
Facility") with a new bank. Borrowings under the New Credit Facility bear
interest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%. We borrowed
$4.5 million under the new facility and repaid the $4.65 million outstanding
under our prior facility with a combination of borrowings and cash on hand. In
December 2000, we paid an additional $1.5 million to reduce our outstanding debt
balance to $3.0 million at December 31, 2000. As of March 28, 2001, no
borrowings were outstanding under the New Credit Facility. The New Credit
Facility matures October 2, 2002 and is secured by substantially all of our
assets.
Originally the borrowing base under the New Credit Facility was $5 million
and was subject to automatic reductions at a rate of $300,000 per month
beginning February 28, 2001. In March 2001, the New Credit Facility was amended
to increase the borrowing base to $14 million, and to eliminate the $300,000 per
month automatic reduction. The borrowing base will be redetermined on a
semi-annual basis.
The New 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 New Credit Facility also prohibits dividends
and certain distributions of cash or properties and certain liens. The New
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
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 .40 to 1.0. At December 31, 2000, the Company was in
compliance with the above mentioned covenants.
42
ACCOUNTING CHANGE
The Company uses the full-cost method of accounting for its oil and natural
gas properties. Under this method, all acquisition, exploration and development
costs that are directly attributable to the Company's acquisition, exploration
and development activities are capitalized in a "full-cost pool" as incurred. In
the second quarter of 1998 and effective January 1, 1998, the Company changed
its method of accounting for direct internal geological and geophysical ("G&G")
costs to one of capitalization of such costs, which are directly attributable to
acquisition, exploration and development activities, to oil and natural gas
property. Prior to the change the Company expensed these costs as incurred. The
Company believes the accounting change provides for a better matching of
revenues and expenses and enhances the comparability of its results of
operations with those of other oil and natural gas companies that follow the
full cost method of accounting (see Note 1).
ACCOUNTING PRONOUNCEMENTS
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 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.
The Company will account 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 the Company's natural gas hedge derivative instrument was
approximately ($1.1) million, which is not recorded in the Consolidated Balance
Sheet. The ($1.1) million will be recorded as a liability on the Company's
balance sheet as part of the transition adjustment related to the Company's
adoption of SFAS 133. The offset to this balance sheet adjustment will be a
decrease to "Accumulated other comprehensive income", a component of
stockholders' equity. The entire amount relates to 2001 anticipated transactions
and will be reclassified to earnings during 2001. The Company believes the
adoption of SFAS 133 will result in more volatility in its financial statements
than in the past.
In the fourth quarter of 2000, the Company adopted Emerging Issues Task
Force Issue No. 00-10 ("EITF No. 00-10") accounting for Shipping and Handling
Fees and Costs. EITF No. 00-10 addresses how shipping and handling fees should
be classified in the income statement. The adoption of this standard had no
impact as the Company had historically reported such costs separately.
HEDGING ACTIVITIES
In December 2000, the Company entered into a natural gas collar that covers
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 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.
As of March 28, 2001, the Company has no hedges in place. Edge believes 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
43
respect to hedging opportunities are made by both the financial and marketing
departments to Edge's management committee and Chief Executive Officer for
approval. The administration of hedges, if any, is handled jointly by the
finance and marketing departments.
TAX MATTERS
At December 31, 2000, the Company had cumulative net operating loss
carryforwards ("NOLs") for federal income tax purposes of approximately
$21.9 million that will begin to expire in 2007. The Company anticipates that
all of these NOLs may be utilized in connection with federal income taxes
payable for the year ended December 31, 2001. As a result, the Company's cash
outflows in respect of tax payments may be higher for 2001 and future periods.
NOLs assume that certain items, primarily intangible drilling costs have
been written off 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. Due to the 1997 ownership change of the Company's
predecessors, future utilization of the NOLs is limited by the Internal Revenue
Code Section 382.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
The Company is exposed to market risk from changes in interest rates and
commodity prices. The Company uses a credit facility, which has a floating
interest rate, to finance a portion of its operations. The Company is not
subject to fair value risk resulting from changes in its floating interest
rates. The use of floating rate debt instruments provide a benefit due to
downward interest rate movements but does not limit the Company to exposure from
future increases in interest rates. Based on the year end December 31, 2000
floating interest rate of 9.5%, a 10% change in interest rate would result in an
increase or decrease of interest expense of approximately $27,200 on an annual
basis.
In the normal course of business the Company enters into hedging
transactions, including commodity price collars and swaps, to mitigate its
exposure to commodity price movements, but not for trading or speculative
purposes. During December 2000, due to the instability of prices and to achieve
a more predictable cash flow, the Company put in place a natural gas collar for
a portion of its year 2001 production. While the use of these arrangements
limits the benefit to the Company of increases in the price of oil and natural
gas it also limits the downside risk of adverse price movements. The natural gas
collar covers 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. At December 31, 2000, the fair value of the outstanding hedge was
approximately $(1.1) million. A 10% change in the gas price per MMbtu would
cause the total fair value of the hedge to increase or decrease by approximately
$978,200. 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.
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 DISCLOSURES
None
44
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 2001 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, 2000. 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.
45
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.
3. Exhibits: The following documents are filed as exhibits to this report.
+2.1 -- Amended and Restated Combination Agreement by and among (i)
Edge Group II Limited Partnership, (ii) Gulfedge Limited
Partnership, (iii) Edge Group Partnership, (iv) Edge
Petroleum Corporation, (v) Edge Mergeco, Inc. and (vi) the
Company, dated as of January 13, 1997 (Incorporated by
reference from exhibit 2.1 to the Company's Registration
Statement on Form S-4 (Registration No. 333-17269))
+3.1 -- Restated Certificate of Incorporated of the Company, as
amended (Incorporated by reference from exhibit 3.1 to the
Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).
+3.2 -- Bylaws of the Company (Incorporated by Reference from
exhibit 3.3 to the Company's Quarterly Report on Form 10-Q
for the quarterly period ended September 30, 1999).
+3.3 -- First Amendment to Bylaws of the Company on September 28,
1999 (Incorporated by Reference from exhibit 3.2 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).
+4.1 -- Security Agreement, dated as of April 1, 1998, by and
between the Borrower and Compass Bank, a Texas state
chartered banking institution, as Agent for itself and The
First National Bank of Chicago and other lenders party
thereto the Credit Agreement (Incorporated by Reference
from exhibit 4.1 to the Company's Quarterly Report on Form
10-Q for the quarterly period ended March 31, 1998).
+4.2 -- Security Agreement (Stock Pledge), dated as of April 1,
1998, by and between Edge Petroleum Corporation and
Compass Bank, a Texas state chartered banking institution,
as Agent for itself and The First National Bank of Chicago
and other lenders party thereto the Credit Agreement
(Incorporated by Reference from exhibit 4.1 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended March 31, 1998).
+4.3 -- Second Amended and Restated Credit Agreement dated October
6, 2000 by and between Edge Petroleum Corporation, Edge
Petroleum Exploration Company and Edge Petroleum Operating
Company, Inc. (collectively, the "Borrowers") and Union
Bank Of California, N.A., a national banking association,
as Agent for itself and as lender. (Incorporated by
Reference from exhibit 4.5 to the Company's Quarterly
Report on Form 10-Q for the quarterly period ended
September 31, 2000).
+4.4 -- Letter Agreement dated October 31, 2000 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company
and Edge Petroleum Operating Company, Inc. (collectively,
the "Borrowers") and Union Bank Of California, N.A., a
national banking association, as Agent for itself and as
lender. (Incorporated by Reference from exhibit
46
4.6 to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended September 31, 2000).
*4.5 -- Letter Agreement dated March 23, 2001 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company
and Edge Petroleum Operating Company, Inc. (collectively,
the "Borrowers") and Union Bank Of California, N.A., a
national banking association, as Agent for itself and as
lender.
The Company is a party to several debt instruments under
which the total amount of securities authorized does not
exceed 10% of the total assets of the Company and its
subsidiaries on a consolidated basis. Pursuant to
paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, the
Company agrees to furnish a copy of such instruments to
the Commission upon request.
+4.6 -- Common Stock Subscription Agreement dated as of April 30,
1999 between the Company and the purchasers named therein
(Incorporated by reference from exhibit 4.5 to the
Company's Quarterly Report on Form 10-Q/A for the quarter
ended March 31, 1999).
+4.7 -- Warrant Agreement dated as of May 6, 1999 between the
Company and the Warrant holders named therein
(Incorporated by reference from exhibit 4.5 to the
Company's Quarterly Report on Form 10-Q/A for the quarter
ended March 31, 1999).
+4.8 -- Form of Warrant for the purchase of the Common Stock
(Incorporated by reference from the Common Stock
Subscription Agreement from exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q/A for the quarter ended
March 31, 1999).
+10.1 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership II, dated as of May 10,
1994 (Incorporated by reference from exhibit 10.2 to the
Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).
+10.2 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership, dated as of April 11,
1992(Incorporated by reference from exhibit 10.3 to the
Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).
+10.3 -- Form of Indemnification Agreement between the Company and
each of its directors (Incorporated by reference from
exhibit 10.7 to the Company's Registration Statement on
Form S-4 (Registration No. 333-17269)).
+10.4 -- Consulting Agreement of James C. Calaway dated March 18,
1989 (Incorporated by reference from exhibit 10.12 to the
Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).
+10.5 -- Stock Option Plan of Edge Petroleum Corporation, a Texas
corporation (Incorporated by reference from exhibit 10.13
to the Company's Registration Statement on Form S-4
(Registration No. 333-17269)).
+10.6 -- Employment Agreement dated as of November 16, 1998, by and
between the Company and John W. Elias. (Incorporated by
reference from 10.12 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1998).
+10.7 -- Incentive Plan of Edge Petroleum Corporation as Amended and
Restated Effective as of July 27, 1999. (Incorporated by
reference from exhibit 10.1 to the Company's Quarterly
Report on Form 10-Q for the quarterly period ended
September 30, 1999).
+10.8 -- Edge Petroleum Corporation Incentive Plan "Standard
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Officers named
47
therein. (Incorporated by reference from exhibit 10.2 to
the Company's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 1999).
+10.9 -- Edge Petroleum Corporation Incentive Plan "Director
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Directors named therein.
(Incorporated by reference from exhibit 10.3 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).
+10.10 -- Severance Agreements by and between Edge Petroleum
Corporation and the Officers of the Company named therein.
(Incorporated by reference from exhibit 10.4 to the
Company's Quarterly Report on Form 10-Q for the quarterly
period ended September 30, 1999).
+10.11 -- Severance Agreement dated as of December 17, 1999 by and
between Edge Petroleum Corporation and James D. Calaway.
(Incorporated by reference from exhibit 10.13 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1999).
+10.12 -- Form of Employee Restricted Stock Award Agreement under the
Incentive Plan of Edge Petroleum Corporation (Incorporated
by Reference from exhibit 10.15 to the Company's Quarterly
Report on Form 10-Q/A for the quarterly period ended March
31, 1999).
+10.13 -- Form of Employee Restricted Stock Award Agreement between
the Company and James D. Calaway under the Incentive Plan
of Edge Petroleum Corporation (Incorporated by Reference
from exhibit 10.18 to the Company's Quarterly Report on
Form 10-Q/A for the quarterly period ended March 31,
1999).
+10.14 -- Letter agreement dated November 9, 1999 for the purchase and
sale of working interests in oil and natural gas
properties between the Company and James C. Calaway.
(Incorporated by reference from exhibit 10.16 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1999).
*21.1 -- Subsidiaries of the Company.
*23.1 -- Consent of Deloitte & Touche LLP.
*23.2 -- Consent of Ryder Scott Company.
*99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers as of December 31, 2000 (included as an appendix
to Form 10-K).
- ------------------------
* Filed herewith.
+ Incorporated by reference as indicated.
(b) Reports on Form 8-K: The Company filed no report on Form 8-K during the
quarter ended December 31, 2000.
48
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
Date: March 28, 2001 /s/ JOHN W. ELIAS
---------------------------------
John W. Elias
CHIEF EXECUTIVE OFFICER AND
CHAIRMAN OF THE BOARD
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Date: March 28, 2001 /s/ JOHN W. ELIAS
--------------------------------------------
John W. Elias
CHIEF EXECUTIVE OFFICER AND CHAIRMAN OF THE
BOARD (PRINCIPAL EXECUTIVE OFFICER)
Date: March 28, 2001 /s/ MICHAEL G. LONG
--------------------------------------------
Michael G. Long
SENIOR VICE PRESIDENT AND CHIEF FINANCIAL
OFFICER (PRINCIPAL FINANCIAL AND PRINCIPAL
ACCOUNTING OFFICER)
Date: March 28, 2001 /s/ VINCENT ANDREWS
--------------------------------------------
Vincent Andrews
DIRECTOR
Date: March 28, 2001 /s/ DAVID B. BENEDICT
--------------------------------------------
David B. Benedict
DIRECTOR
Date: March 28, 2001 /s/ NILS P. PETERSON
--------------------------------------------
Nils P. Peterson
DIRECTOR
Date: March 28, 2001 /s/ STANLEY S. RAPHAEL
--------------------------------------------
Stanley S. Raphael
DIRECTOR
Date: March 28, 2001 /s/ JOHN SFONDRINI
--------------------------------------------
John Sfondrini
DIRECTOR
Date: March 28, 2001 /s/ ROBERT W. SHOWER
--------------------------------------------
Robert W. Shower
DIRECTOR
49
EDGE PETROLEUM CORPORATION
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY INFORMATION
CONSOLIDATED FINANCIAL STATEMENTS
Audited Financial Statements:
Independent Auditors' Report.............................. F-2
Consolidated Balance Sheets as of December 31, 2000 and
1999.................................................... F-3
Consolidated Statements of Operations for the Years Ended
December 31, 2000, 1999 and 1998........................ F-4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2000, 1999 and 1998........................ F-5
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 2000, 1999 and 1998............ F-6
Notes to Consolidated Financial Statements................ F-7
Unaudited Information:
Supplementary Information to Consolidated Financial
Statements.............................................. F-24
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
INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors,
Edge Petroleum Corporation
We have audited the accompanying consolidated balance sheets of Edge
Petroleum Corporation (a Delaware Corporation) (the "Company") as of
December 31, 2000 and 1999, and the related consolidated statements of
operations, stockholders' equity and cash flows for each of the three 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 financial statements present fairly, in all material
respects, the financial position of the Company at December 31, 2000 and 1999,
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 2000, in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, effective
January 1, 1998 the Company changed its method of accounting for direct internal
geological and geophysical costs to one of capitalization of such costs, which
are directly attributable to acquisition, exploration and development
activities, to oil and natural gas properties.
/s/ Deloitte & Touche LLP
Houston, Texas
March 19, 2001
F-2
EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
-------------------------
2000 1999
----------- -----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 1,839,438 $ 577,864
Accounts receivable, trade................................ 8,752,871 3,489,709
Accounts receivable, joint interest owners, net of
allowance of $163,000 as of December 31, 2000 and 1999,
respectively............................................ 369,524 1,177,555
Receivables from related parties.......................... 22,410 59,951
Other current assets...................................... 298,973 161,558
----------- -----------
Total current assets.................................... 11,283,216 5,466,637
PROPERTY AND EQUIPMENT, Net--full cost method of accounting
for oil and natural gas properties........................ 47,242,409 45,976,007
INVESTMENT IN FRONTERA...................................... -- 3,867,233
OTHER ASSETS................................................ 7,788 7,788
----------- -----------
TOTAL ASSETS................................................ $58,533,413 $55,317,665
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade................................... $ 1,810,655 $ 1,332,760
Revenue payable........................................... 1,058,242 536,448
Accrued liabilities....................................... 2,484,865 4,458,481
Accrued interest payable.................................. 50,385 16,369
Current portion of long-term debt......................... 3,000,000 4,100,000
----------- -----------
Total current liabilities............................... 8,404,147 10,444,058
LONG-TERM DEBT.............................................. -- 2,700,000
----------- -----------
Total liabilities....................................... 8,404,147 13,144,058
----------- -----------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, $0.01 par value; 5,000,000 shares
authorized; none outstanding
Common stock, $0.01 par value; 25,000,000 shares
authorized; 9,186,071 and 9,182,023 shares issued and
outstanding at December 31, 2000 and 1999,
respectively............................................ 91,861 91,820
Additional paid-in capital................................ 56,247,130 55,223,901
Retained deficit.......................................... (6,209,725) (13,107,890)
Unearned compensation--restricted stock................... -- (34,224)
----------- -----------
Total stockholders' equity.............................. 50,129,266 42,173,607
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.................. $58,533,413 $55,317,665
=========== ===========
See accompanying notes to the consolidated financial statements.
F-3
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
----------------------------------------
2000 1999 1998
----------- ----------- ------------
OIL AND NATURAL GAS REVENUE........................... $23,774,416 $14,485,995 $ 15,463,432
OPERATING EXPENSES:
Oil and natural gas operating expenses including
production and ad valorem taxes................... 3,954,938 3,039,070 3,375,759
Depletion, depreciation and amortization............ 7,640,778 8,511,826 10,002,533
Impairment of oil and natural gas properties........ -- -- 10,012,989
General and administrative expenses................. 3,824,385 4,528,517 4,582,973
Deferred compensation expense....................... 1,004,798 -- --
Unearned compensation expense....................... 22,696 349,623 621,191
Other charge........................................ -- 1,688,227 2,898,125
----------- ----------- ------------
Total operating expenses.......................... 16,447,595 18,117,263 31,493,570
----------- ----------- ------------
OPERATING INCOME (LOSS)............................... 7,326,821 (3,631,268) (16,030,138)
OTHER INCOME AND (EXPENSE):
Interest expense and amortization of deferred loan
costs............................................. (171,783) (130,067) (90,075)
Interest income..................................... 97,860 51,855 132,993
Loss on sale of investment in Frontera.............. (354,733) -- --
----------- ----------- ------------
NET INCOME (LOSS) BEFORE INCOME TAXES AND CUMULATIVE
EFFECT OF ACCOUNTING CHANGE......................... 6,898,165 (3,709,480) (15,987,220)
INCOME TAX BENEFIT.................................... -- -- 982,966
----------- ----------- ------------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE................................... 6,898,165 (3,709,480) (15,004,254)
CUMULATIVE EFFECT OF ACCOUNTING CHANGE................ -- -- 1,780,835
----------- ----------- ------------
NET INCOME (LOSS)..................................... $ 6,898,165 $(3,709,480) $(13,223,419)
=========== =========== ============
BASIC EARNINGS (LOSS) PER SHARE:
Net income (loss) before cumulative effect of
accounting change................................. $ 0.75 $ (0.43) $ (1.93)
Cumulative effect of accounting change.............. -- -- 0.23
----------- ----------- ------------
Basic earnings (loss) per share..................... $ 0.75 $ (0.43) $ (1.70)
=========== =========== ============
DILUTED EARNINGS (LOSS) PER SHARE:
Net income (loss) before cumulative effect of
accounting change................................. $ 0.74 $ (0.43) $ (1.93)
Cumulative effect of accounting change.............. -- -- 0.23
----------- ----------- ------------
Diluted earnings (loss) per share................... $ 0.74 $ (0.43) $ (1.70)
=========== =========== ============
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING......................................... 9,182,737 8,680,369 7,758,667
=========== =========== ============
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING......................................... 9,330,049 8,680,369 7,758,667
=========== =========== ============
See accompanying notes to the consolidated financial statements.
F-4
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
------------------------------------------
2000 1999 1998
------------ ------------ ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss).................................. $ 6,898,165 $ (3,709,480) $(13,223,419)
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Cumulative effect of accounting change........... -- -- (1,780,835)
Depletion, depreciation and amortization......... 7,640,778 8,511,826 10,002,533
Amortization of deferred loan costs.............. 24,720 -- --
Impairment of oil and natural gas properties..... -- -- 10,012,989
Deferred income taxes............................ -- -- (982,966)
Compensation expense............................. 30,000 -- --
Unearned compensation expense.................... 22,696 1,483,211 2,268,610
Deferred compensation expense.................... 1,004,798 -- --
Loss on sale of investment in Frontera........... 354,733 -- --
Changes in current assets and liabilities:
(Increase) decrease in accounts receivable,
trade.......................................... (5,263,162) (1,252,596) 157,384
Decrease in accounts receivable, joint interest
owners, net.................................... 808,031 1,037,541 4,332,523
Decrease in receivable from related parties...... 37,541 168,971 156,270
Decrease in other current assets................. 40,791 152,073 38,940
Decrease in other assets......................... -- -- 9,443
Increase (decrease) in accounts payable, trade... 477,895 (1,616,031) (403,213)
Increase (decrease) in revenue payable........... 521,794 (903,369) 643,247
Increase (decrease) in accrued interest
payable........................................ 34,016 (77,511) 93,880
Increase (decrease) in accrued liabilities....... (1,973,616) 2,118,417 658,012
------------ ------------ ------------
Net cash provided by operating activities........ 10,659,180 5,913,052 11,983,398
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of prospects, property and equipment...... (10,717,839) (14,587,680) (34,823,922)
Proceeds from the sale of prospects and oil and
natural gas properties........................... 1,810,659 7,451,341 6,951,673
Proceeds from the sale of our investment in
Frontera, net.................................... 3,512,500 -- --
Investment in Frontera............................. -- (122,298) (116,671)
------------ ------------ ------------
Net cash used in investing activities............ (5,394,680) (7,258,637) (27,988,920)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from long-term debt..................... 5,350,000 6,750,000 12,500,000
Payments on long-term debt......................... (9,150,000) (12,450,000) --
Net proceeds from issuance of common stock......... -- 7,351,021 --
Loan costs......................................... (202,926) -- --
------------ ------------ ------------
Net cash provided by (used in) financing
activities..................................... (4,002,926) 1,651,021 12,500,000
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS........................................ 1,261,574 305,436 (3,505,522)
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR......... 577,864 272,428 3,777,950
------------ ------------ ------------
CASH AND CASH EQUIVALENTS, END OF YEAR............... $ 1,839,438 $ 577,864 $ 272,428
============ ============ ============
See accompanying notes to the consolidated financial statements.
F-5
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
UNEARNED
COMMON STOCK ADDITIONAL RETAINED COMPENSATION- TOTAL
-------------------- PAID-IN EARNINGS RESTRICTED STOCKHOLDERS'
SHARES AMOUNT CAPITAL (DEFICIT) STOCK EQUITY
------ -------- ----------- ------------ ------------- -------------
BALANCE, DECEMBER 31, 1997.... 7,760,869 $77,609 $47,629,822 $ 3,825,009 $(3,621,276) $ 47,911,164
Issuance of restricted
common stock.............. 12,025 120 148,762 (148,882)
Forfeiture of restricted
common stock.............. (14,227) (143) (9,425) 9,568
Unearned compensation
expense................... 2,268,610 2,268,610
Net loss.................... (13,223,419) (13,223,419)
--------- ------- ----------- ------------ ----------- ------------
BALANCE, DECEMBER 31, 1998.... 7,758,667 77,586 47,769,159 (9,398,410) (1,491,980) 36,956,355
Issuance of restricted
common stock.............. 4,809 48 29,431 (29,479)
Forfeitures of restricted
common stock.............. (325) (3) (4,021) 4,024
Private common stock
offering, net of offering
costs of $261,479......... 1,400,000 14,000 7,337,021 7,351,021
Issuance of common stock for
oil and natural gas
properties................ 18,872 189 92,311 92,500
Unearned compensation
expense................... 1,483,211 1,483,211
Net loss.................... (3,709,480) (3,709,480)
--------- ------- ----------- ------------ ----------- ------------
BALANCE, DECEMBER 31, 1999.... 9,182,023 91,820 55,223,901 (13,107,890) (34,224) 42,173,607
Forfeitures of restricted
common stock.............. (5,600) (56) (11,472) 11,528
Issuance of common stock.... 9,648 97 29,903 30,000
Deferred compensation
expense................... 1,004,798 1,004,798
Unearned compensation
expense................... 22,696 22,696
Net income.................. 6,898,165 6,898,165
--------- ------- ----------- ------------ ----------- ------------
BALANCE, DECEMBER 31, 2000.... 9,186,071 $91,861 $56,247,130 $ (6,209,725) $ -- $ 50,129,266
========= ======= =========== ============ =========== ============
See accompanying notes to the consolidated financial statements.
F-6
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL--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 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 where it currently
controls interests in excess of 90,000 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.
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 8). 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.
Effective November 16, 1998, John E. Calaway resigned as Chairman of the
Board, Chief Executive Officer ("CEO") and Director of the Company. As a result
of his resignation the Company recorded a one-time charge of approximately
$2.9 million to satisfy corporate obligations under his employment contract.
Included in the $2.9 million is a $1.6 million non-cash amount relating to
vesting of the remaining balance of Mr. John Calaway's restricted common stock
award granted concurrent with the Company's Offering (see Note 8). The balance
of the special charge primarily represents cash payments to be paid to
Mr. Calaway from the date of his resignation to January, 2000.
ACCOUNTING CHANGE--The Company uses the full-cost method of accounting for
its oil and natural gas properties. Under this method, all acquisition,
exploration and development costs that are directly attributable to the
Company's acquisition, exploration and development activities are capitalized in
a "full-cost pool" as incurred. In the second quarter of 1998 and effective
January 1, 1998, the Company changed its method of accounting for direct
internal geological and geophysical ("G&G") costs to one of capitalization of
such costs, which are directly attributable to the acquisition, exploration and
development activities, to oil and natural gas properties. Prior to the change
the Company expensed these costs as incurred. The Company believes the
accounting change provides for a better matching of revenues and expenses and
enhances the comparability of it's financial statements with those of other
F-7
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
companies that follow the full-cost method of accounting. The $1,780,835
cumulative effect of the change in prior years (after reduction for income taxes
of $958,910) is included in the net loss for the year ended December 31, 1998.
The effect of the accounting change (reduced G&A offset by increased DD&A) on
the year ended December 31, 1998 was to decrease the net loss by $1,646,187
($0.21 basic and diluted loss per share).
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 PROPERTy--Investments in oil and natural gas properties
are accounted for using the full cost method of accounting. All costs associated
with the acquisition, exploration and development of oil and natural gas
properties are capitalized.
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
indicates 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. The depletion rates per Mcfe for the years ended December 31,
2000, 1999 and 1998 were $1.11, $1.15 and $1.30, 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
at December 31, 2000 or 1999. At December 31, 1998 the Company recorded a full
cost ceiling test write down of its oil and natural gas properties of
approximately $10.0 million.
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 6).
F-8
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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 and collars) for a portion of its oil and natural gas
production to achieve a more predictable cash flow, as well as to reduce
exposure from price fluctuations. While the use of these arrangements limits the
benefit to the Company of increases in the price of oil and natural gas it also
limits 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 revenues
during the period the hedged transactions occur (see Note 4).
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
are 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 Frontera Common Stock and
$116,672 in April 1999 for 44,027 shares of Frontera Common Stock bring its
total investment in Frontera to $3,867,233.
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, or $0.04 per basic share.
STOCK-BASED COMPENSATION--The Company accounts for Stock Based Compensation
in accordance with Financial Accounting Standards Board Statement
No. 123--"Accounting for Stock Based Compensation," ("SFAS No. 123"). Under SFAS
No. 123, the Company is permitted to either record expenses for stock options
and other employee compensation plans based on their fair value at the date of
grant or to continue to apply its current accounting policy under Accounting
Principles Board Opinion No. 25 ("APB No.25") and recognize compensation
expense, if any, based on the intrinsic value of the equity instrument at the
measurement date. The Company elected to continue following APB No. 25. The
adoption of SFAS No. 123 in 1997 had no effect on the Company's results of
operations (see Note 8).
The Company is subject to reporting requirements of FASB Interpretation No.
(FIN) 44, ACCOUNTING FOR CERTAIN TRANSACTIONS INVOLVING STOCK COMPENSATION that
requires a non-cash charge to deferred compensation expense if the price of
Edge'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
F-9
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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.
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 and 1998 the Company reported a net loss, thus the
effects of stock options are antidilutive.
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, 2000 and 1999 approximates fair value and the
fair value, gain (loss), of outstanding hedges was approximately $(1.1) million
and $15,000, respectively.
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 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.
The Company will account 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 the Company's natural gas hedge derivative instrument was
approximately ($1.1) million, which is not recorded in the Consolidated Balance
Sheet. The ($1.1) million will be recorded as a liability on the Company's
balance sheet as part of the transition adjustment related to the Company's
adoption of SFAS 133. The offset to this balance sheet adjustment will be a
decrease to "Accumulated other comprehensive income", a component of
stockholders' equity. The entire amount relates to 2001 anticipated transactions
and will be reclassified to earnings during 2001. 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, 2000, 1999 and 1998, 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
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported
F-10
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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 but the Company can not ensure that such
losses may not be realized in the future.
RECLASSIFICATIONS--Certain prior year balances have been reclassified to
conform to the current year presentation.
2. PROPERTY AND EQUIPMENT
At December 31, 2000 and 1999, property and equipment consisted of the
following:
2000 1999
------------ ------------
Developed oil and natural gas properties......... $ 70,628,009 $ 58,981,484
Undeveloped oil and natural gas properties....... 15,165,748 17,930,027
Computer equipment and software.................. 3,807,722 3,769,489
Other office property and equipment.............. 1,283,897 1,286,669
------------ ------------
Total property and equipment................... 90,885,376 81,967,669
Accumulated depletion, depreciation and
amortization................................... (43,642,967) (35,991,662)
------------ ------------
Property and equipment, net.................... $ 47,242,409 $ 45,976,007
============ ============
Undeveloped oil and natural gas properties are not subject to amortization
and consist of the cost of undeveloped leaseholds, exploratory and developmental
wells in progress, and secondary recovery projects before the assignment of
proved reserves. These costs are reviewed periodically by management for
impairment, with the impairment provision included in the cost of oil and
natural gas properties subject to amortization. Factors considered by management
in its impairment assessment include drilling results by the Company and other
operators, the terms of oil and natural gas leases not held by production,
production response to secondary recovery activities and available funds for
exploration and development.
F-11
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. PROPERTY AND EQUIPMENT (CONTINUED)
The following table summarizes the cost of the properties not subject to
amortization for the year the cost was incurred:
DECEMBER 31,
-------------------------
2000 1999
----------- -----------
Year cost incurred:
1995............................................. $ 49,217 $ 50,116
1996............................................. 268,578 333,077
1997............................................. 789,029 2,276,640
1998............................................. 4,522,603 7,409,175
1999............................................. 2,960,611 7,861,019
2000............................................. 6,575,710
----------- -----------
Total.......................................... $15,165,748 $17,930,027
=========== ===========
During August 1999, the Company completed a transaction in which it sold,
effective July 1, 1999, its working interests in proved producing and
undeveloped properties within its BTA and Spartan Extension 3-D project areas in
Goliad and Victoria Counties, Texas. Proceeds from the sale were approximately
$4 million and associated net proved reserves were approximately 1.4 Bcfe or 6%
of the Company's total proved reserves. The Company uses the full-cost method of
accounting for its oil and natural gas properties. Under this 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. The proceeds from the sale of
these proved producing properties were credited directly to the full cost pool.
3. LONG-TERM DEBT
In October 2000, the Company entered into a new credit facility (the "New
Credit Facility") with a new bank. Borrowings under the New Credit Facility bear
interest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%. The Company
borrowed $4.5 million under the new facility and repaid the $4.65 million
outstanding under the prior facility with a combination of borrowings and cash
on hand. In December 2000, the Company paid an additional $1.5 million to reduce
our outstanding debt balance to $3.0 million at December 31, 2000. As of
March 28, 2001, no borrowings were outstanding under the New Credit Facility.
The New Credit Facility matures October 2, 2002 and is secured by substantially
all of our assets.
Originally the borrowing base under the New Credit Facility was $5 million
and was subject to automatic reductions at a rate of $300,000 per month
beginning February 28, 2001. In March 2001, the New Credit Facility was amended
to increase the borrowing base to $14 million, and to eliminate the $300,000 per
month automatic reduction. The borrowing base will be redetermined on a
semi-annual basis.
The New 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 New Credit Facility also prohibits dividends
and certain distributions of cash or properties and certain liens. The New
Credit Facility also
F-12
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. LONG-TERM DEBT (CONTINUED)
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 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 .40 to 1.0. At December 31, 2000, the Company was in compliance with the
above mentioned covenants.
At December 31, 2000 and 1999, current maturities of long-term debt and
long-term debt consisted of the following:
2000 1999
----------- -----------
Revolving Credit Facility.......................... $ -- $ 6,800,000
New Credit Facility................................ 3,000,000 --
----------- -----------
Total.............................................. 3,000,000 6,800,000
Current portion.................................... (3,000,000) (4,100,000)
----------- -----------
Long-term portion.................................. $ -- $ 2,700,000
=========== ===========
F-13
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. HEDGING ACTIVITIES
The impact on oil and natural gas revenues from hedging activities for the
three years ended December 31, 2000, 1999 and 1998 was as follows:
GAIN (LOSS)
EFFECTIVE DATES PRICE BARRELS FOR THE YEAR ENDED DECEMBER 31,
HEDGE ------------------- PER PRICE PER PER MMBTU ------------------------------------
TYPE BEG. ENDING BARREL MMBTU DAY PER DAY 2000 1999 1998
- ------------ -------- -------- -------- ------------- -------- -------- ----------- ----------- --------
NATURAL GAS:
Collar 02/01/98 04/30/98 $2.25 - $2.75 5,000 $ $ $ 36,700
Collar 04/01/98 06/30/98 $2.15 - $2.37 10,000 30,000
Collar 07/01/98 09/30/98 $2.25 - $2.88 10,000 266,900
Collar 10/01/98 12/31/98 $2.00 - $2.63 5,000 1,500
Collar 10/01/98 12/31/98 $2.11 - $2.60 5,000 33,500
Collar 10/01/98 12/31/98 $2.05 - $2.60 5,000 10,550
Collar 10/01/98 12/31/98 $2.20 - $2.62 5,000 102,375
Swap 03/01/99 10/31/99 $1.957 13,000 (1,096,580)
Swap 05/01/99 09/15/99 $2.145 3,000 (154,124)
Swap 11/01/99 12/31/99 $3.00 3,000 80,070
Swap 12/01/99 12/31/99 $3.00 3,000 82,770
Collar 02/01/00 02/29/00 $2.20 - $2.31 6,000 (70,470)
Collar 03/01/00 04/30/00 $2.20 - $2.50 6,000 (135,900)
Collar 05/01/00 09/30/00 $2.05 - $2.63 9,000 (1,342,320)
OIL:
Swap 01/01/00 03/31/00 $25.60 150 (49,999)
04/01/00 06/30/00 $22.87 125 (65,478)
07/01/00 09/30/00 $21.47 60 (55,635)
10/01/00 12/31/00 $20.46 50 (52,342)
----------- ----------- --------
$(1,772,144) $(1,087,864) $481,525
=========== =========== ========
The Company's 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,
2000 was approximately $(1.5) million, $(1.1) million, and $482,000
respectively, representing net (losses) and net gains 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. At December 31, 2000 and
1999, the fair value of outstanding hedges was approximately $(1.1) million and
$15,000, respectively. 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.
F-14
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. 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.
The Company, as one of three original plaintiffs, has 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 are, 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 seeks to enforce its interest in the prospect and seeks 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, 2000. All parties rested on the plaintiffs'
claims on September 13, 2000. The court took the matter under advisement and has
not yet announced a ruling. 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
F-15
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. COMMITMENTS AND CONTINGENCIES (CONTINUED)
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, 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 loss of the lease development
opportunity, and $308 million for 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. At the conclusion of this trial, the court
took the matter under advisement. The parties have filed overviews of the
evidence, proposed findings of fact and conclusions of law and proposed charges
The court has not yet ruled but has requested that the parties file proposed
forms of judgment.
While the Company believes it has presented sufficient legal and factual
defenses to all of the defendants' counterclaims, and has vigorously defended
itself in this matter, there can be no assurance that the outcome of any portion
of this litigation will be favorable to the Company. In the possible event of a
material adverse outcome on the counterclaims or related matters, there could be
a material adverse effect on the Company. In that event, the Company might well
be required to post a bond in the amount of the judgment (or the portion of the
counterclaim judgment for which it has liability) in order to prevent the
defendants from executing on that judgment. Depending on the amount of such a
judgment, there could be no assurance that the Company could obtain such a bond
or pay the judgment. In the event of an adverse judgment, the Company would
likely appeal such judgment, and the Company is optimistic about its chances for
success on appeal, should such be necessary. However, there can be no assurance
as to the outcome of this matter.
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, 2000, the Company was obligated under noncancelable
operating leases. Following is a schedule of the remaining future minimum lease
payments under these lease:
2001........................................................ $292,131
2002........................................................ 292,131
2003........................................................ 68,200
2004........................................................ 21,636
Remainder................................................... 4,452
--------
Total....................................................... $678,550
========
F-16
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. COMMITMENTS AND CONTINGENCIES (CONTINUED)
Rent expense for the years ended December 31, 2000, 1999 and 1998 was
$499,033, $511,270, and $478,652, respectively.
6. INCOME TAXES
Deferred income taxes reflect the tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts calculated for income tax purposes in accordance with
SFAS No. 109.
Significant components of the Company's deferred tax liabilities and assets
as of December 31, 2000 and 1999 are as follows:
2000 1999
----------- -----------
Deferred tax liability:
Book basis of oil and natural gas properties in
excess of tax basis............................ $(3,398,223) $(2,522,052)
Deferred tax asset:
Other charge not currently deductible for tax
purposes....................................... 97,194 186,585
Net operating loss carryforwards................. 6,118,890 9,069,999
Deferred compensation............................ 351,679 --
Other misc....................................... 57,050 142,056
Valuation allowance.............................. (3,226,590) (6,876,588)
----------- -----------
Total deferred tax asset........................... 3,398,223 2,522,052
----------- -----------
Net deferred tax asset............................. $ -- $ --
=========== ===========
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:
2000 1999 1998
----------- ----------- -----------
Statutory federal income taxes......... $ 2,414,358 $(1,298,318) $(5,595,527)
Expense not deductible for tax
purposes........................... 12,216 9,991 7,266
Cumulative effect of accounting
change............................. -- -- (958,910)
Compensation expense................. 1,223,424 -- --
Other................................ -- -- (24,056)
Change in valuation allowance........ (3,649,998) 1,288,327 5,588,261
----------- ----------- -----------
Income tax (benefit) expense........... $ -- $ -- $ (982,966)
=========== =========== ===========
At December 31, 2000, the Company had cumulative net operating loss
carryforwards ("NOLs") for federal income tax purposes of approximately
$21.9 million that will begin to expire in 2007. The net operating loss
carryforwards assume that certain items, primarily intangible drilling costs
have been written off 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. Due to the 1997 ownership change of Old Edge and
the Joint Venture, future utilization of the NOLs is limited by Internal Revenue
Code Section 382.
F-17
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
7. EMPLOYEE BENEFIT PLANS
Effective July 1, 1997 the Company established a defined-contribution 401(k)
Savings & Profit Sharing Plan Trust (the "Plan") covering employees of the
Company who are age 21 or older. The Company's matching contributions to the
Plan are discretionary. For the years ended December 31, 2000, 1999 and 1998 the
Company contributed $53,926, $81,990 and $68,869, respectively, to the Plan.
8. 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 proceeding 20
consecutive trading days exceeds $10.70. No warrants have been exercised as of
December 31, 2000. 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
355,707 shares were available for future grants at December 31, 2000. Shares of
common stock awarded as restricted stock are subject to restrictions on transfer
and subject to risk of forfeiture until earned by continued employment or
service. During 1999 and 1998, 4,809 and 12,025 shares, respectively, of
restricted stock were awarded having a market value of $6.13 and $12.38,
respectively, per share as of the award date. The total market value of such
awards has been recorded as unearned compensation-restricted stock and is shown
as a separate component of stockholders' equity and is amortized to expense over
the vesting period. 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.
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
F-18
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. EQUITY AND STOCK PLANS (CONTINUED)
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.
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. 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. The charge is
related to the 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 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, and 133,334 are included as options
exercisable, at the end of 2000 in the table below. 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 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 adjustment for the conversion, the option price
per share of common stock for each of the two grants was approximately $4.09 and
$2.04, respectively. Options for the purchase of 48,922 shares of common stock
were exercised during 1997 and 48,922 remain outstanding at December 31, 2000,
1999 and 1998.
UNEARNED COMPENSATION EXPENSE--Unearned compensation expense is amortized to
operations over the corresponding vesting period. Amortization of unearned
compensation expense for the years ended December 31, 2000, 1999 and 1998 was
$22,696, $349,623 and $621,191, respectively.
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
F-19
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. EQUITY AND STOCK PLANS (CONTINUED)
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.
Effective November 16, 1998, Mr. John E. Calaway resigned as Chairman of the
Board, Chief Executive Officer and a Director of the Company. In connection with
his resignation his remaining restricted stock, 106,916 shares, became fully
vested. Included in "Other charge" for 1998 is the amortization of approximately
$1.6 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, 2000 is presented below:
2000 1999 1998
------------------- ------------------- -------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
-------- -------- -------- -------- -------- --------
Outstanding, January 1................... 818,567 $7.74 739,055 $15.17 706,365 $15.63
Granted.................................. 284,100 $3.36 320,800 $ 5.30 107,600 $12.76
Reissued/repriced........................ -- 326,700 $ 7.06
Recalled................................. -- (556,488) $15.84
Forfeited................................ (109,150) $5.20 (11,500) $ 7.06 (74,910) $16.01
Exercised................................ --
-------- -------- -------
Outstanding, December 31................. 993,517 $6.76 818,567 $ 7.74 739,055 $15.17
======== ======== =======
Exercisable, December 31,................ 626,651 $8.24 409,783 $ 9.32 272,785 $14.27
======== ======== =======
A summary of the of the Company's stock options categorized by class of
grant at December 31, 2000 is presented below:
ALL OPTIONS
- ------------------------------------------------------------ OPTIONS EXERCISABLE
WEIGHTED ----------------------------------------
AVERAGE WEIGHTED WEIGHTED
REMAINING AVERAGE RANGE OF AVERAGE
RANGE OF SHARES CONTRACTUAL EXERCISE EXERCISE SHARES EXERCISE
EXERCISE PRICE OUTSTANDING LIFE PRICE PRICE OUTSTANDING PRICE
- --------------------- ----------- ----------- -------- --------------- ----------- --------
$ 2.11 - $6.44 212,100 9.17 $ 3.05 $ 2.11 - $6.44 -- --
$ 4.09 - $4.22 248,922 7.65 $ 4.19 $ 4.09 - $4.22 182 256 $ 4.19
$ 7.06 - $7.28 398,750 8.39 $ 7.07 $ 7.06 - $7.28 310,650 $ 7.06
$13.50 - $16.50 133,745 6.25 $16.50 $13.50 - $16.50 133,745 $16.50
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. Had compensation expense for the
Company's stock options granted during the years ended December 31, 2000, 1999
and 1998 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 reduced to 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
F-20
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. EQUITY AND STOCK PLANS (CONTINUED)
based on the following assumptions for the years ended December 31, 2000, 1999
and 1998: expected volatility based on historical volatility of daily Common
Stock Prices (83%, 70% and 53%, 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 FASB 123 and its impact on net income
(loss) and earnings (loss) per basic and diluted share for the three years ended
December 31, 2000, 1999 and 1998.
YEAR ENDED DECEMBER 31,
---------------------------------------
2000 1999 1998
---------- ----------- ------------
Net income (loss):
As reported.......................................... $6,898,165 $(3,709,480) $(13,223,419)
========== =========== ============
Pro forma............................................ 7,345,506 (4,186,567) (13,743,611)
========== =========== ============
As Reported:
Basic earnings (loss) per share:
Net income (loss) before cumulative effect of
accounting change................................ $ 0.75 $ (0.43) $ (1.93)
Cumulative effect of accounting change............. -- -- 0.23
---------- ----------- ------------
Basic earnings (loss) per share.................... $ 0.75 $ (0.43) $ (1.70)
========== =========== ============
Diluted earnings (loss) per share:
Net income (loss) before cumulative effect of
accounting change................................ $ 0.74 $ (0.43) $ (1.93)
Cumulative effect of accounting change............. -- -- 0.23
---------- ----------- ------------
Diluted earnings (loss) per share.................. $ 0.74 $ (0.43) $ (1.70)
========== =========== ============
Pro Forma:
Basic earnings (loss) per share:
Net income (loss) before cumulative effect of
accounting change................................ $ 0.80 $ (0.49) $ (2.00)
Cumulative effect of accounting change............. -- -- 0.23
---------- ----------- ------------
Basic earnings (loss) per share.................... $ 0.80 $ (0.49) $ (1.77)
========== =========== ============
Diluted earnings (loss) per share:
Net income (loss) before cumulative effect of
accounting change................................ $ 0.79 $ (0.49) $ (2.00)
Cumulative effect of accounting change............. -- -- 0.23
---------- ----------- ------------
Diluted earnings (loss) per share.................. $ 0.79 $ (0.49) $ (1.77)
========== =========== ============
F-21
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. EQUITY AND STOCK PLANS (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.
YEAR ENDED DECEMBER 31, 2000
---------------------------------------
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
BASIC EPS
Income available to common
stockholders.......................... $6,898,165 9,182,737 $ 0.75
EFFECT OF DILUTIVE SECURITIES
Common stock options.................... -- 27,130 --
Restricted stock........................ -- 120,182 (0.01)
---------- ---------- ------
DILUTED EPS
Income available to common
stockholders.......................... $6,898,165 9,330,049 $ 0.74
========== ========== ======
For the year ended December 31, 1999, and 1998, the Company reported a net
loss, thus the effects of stock options and warrants are antidilutive.
9. 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 receives 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, 2000. For the years ended December 31, 1999 and 1998, the
Company recorded management fees totaling $52,560 and $120,000, respectively,
and have recorded these amounts 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. Such amounts invoiced by the Company to the Essex
Joint Ventures for the years ended December 31, 1998 amounted to $3,074. The
Company is no longer the manager for this venture. 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.
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.
10. SUBSEQUENT EVENTS
During the first quarter of 2001, the Company repaid all amounts outstanding
under the credit facility and as of March 28, 2001 has no borrowings
outstanding.
F-22
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUBSEQUENT EVENTS (CONTINUED)
In March 2001, the New Credit Facility was amended so as to increase the
borrowing base to $14 million from $5 million, and to change the terms so as to
eliminate the $300,000 per month commitment reductions. The borrowing base will
be redetermined on a semi-annual base from this point forward.
11. SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
We consider 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 year ended December 31, 2000 and 1999
is presented below:
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 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.
For the year ended December 31, 1998, the issuance of restricted stock was
recorded with respect to 12,025 shares valued at $148,882.
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------
2000 1999 1998
--------- --------- ---------
Cash paid during the period for:
Interest, net of amounts capitalized.......... $133,093 $208,694 $4,820
F-23
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED):
FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
2000
Oil and natural gas revenue.............. $ 9,693 $5,587 $4,683 $3,811
Operating expenses....................... 5,242 3,697 4,087 3,421
Operating income (loss).................. 4,451 1,890 596 390
Other income (expense), net.............. (15) 5 (388) (310
Net income (loss)........................ 4,436 1,895 208 359
Basic earnings (loss) per share.......... $ 0.48 $ 0.21 $ 0.02 $ 0.04
Diluted earnings (loss) per share........ $ 0.47 $ 0.20 $ 0.02 $ 0.04
1999
Oil and natural gas revenue.............. $ 3,699 $3,056 $4,189 $3,542
Operating expenses....................... 6,923 2,960 4,414 3,820
Operating income (loss).................. (3,224) 96 (225) (278)
Other income (expense), net.............. (36) (15) (27)
Net income (loss)........................ (3,260) 96 (240) (305)
Basic earnings (loss) per share.......... $ (0.36) $ 0.01 $(0.03) $(0.04)
Diluted earnings (loss) per share........ $ (0.36) $ 0.01 $(0.03) $(0.04)
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, 2000
is a non-cash charge of $899,548, or $0.10 per share, to compensation expense as
required by FASB Interpretation No. (FIN) 44, ACCOUNTING FOR CERTAIN
TRANSACTIONS INVOLVING STOCK COMPENSATION.
Included in operating expenses for the three months ended December 31, 1999
and 1998 is an other charge of approximately $1.7 million and $2.9 million,
respectively, the majority of which represents one-time charges to satisfy
corporate obligations under the former President's and Chairman's employment
contracts (see Note 1). Included in operating expenses during the three months
ended December 31, 1998 is approximately $10 million representing an impairment
of oil and natural gas properties (see Note 1).
13. 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-24
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED): (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:
DECEMBER 31,
---------------------------
2000 1999
------------ ------------
Developed oil and natural gas properties......... $ 70,628,009 $ 58,981,484
Undeveloped oil and natural gas properties....... 15,165,748 17,930,027
Accumulated depletion, depreciation and
amortization................................... (40,483,154) (33,521,520)
------------ ------------
Net capitalized cost............................. $ 45,310,603 $ 43,389,991
============ ============
COSTS INCURRED--Costs incurred in oil and natural gas property acquisition,
exploration and development activities are summarized below:
YEAR ENDED DECEMBER 31,
---------------------------------------
2000 1999 1997
----------- ----------- -----------
Acquisition Cost:
Unproved projects and prospects..... $ 4,219,936 $ 7,691,947 $20,852,838
Exploration costs..................... 2,707,015 3,334,836 10,236,188
Development costs..................... 3,765,945 3,455,493 3,249,492
----------- ----------- -----------
Gross costs incurred................ 10,692,896 14,482,276 34,338,518
Less proceeds from the sale of
prospects........................... 1,810,659 3,471,247 6,951,673
----------- ----------- -----------
Net cost incurred................... $ 8,882,237 $11,011,029 $27,386,845
=========== =========== ===========
Net costs incurred excludes sales of proved oil and natural gas properties
which are accounted for as adjustments of capitalized costs with no gain or loss
recognized, unless such adjustments would significantly alter the relationship
between capitalized costs and proved reserves.
RESULTS OF OPERATIONS--Results of operations for the Company's oil and
natural gas producing activities are summarized below:
YEAR ENDED DECEMBER 31,
---------------------------------------
2000 1999 1998
----------- ----------- -----------
Oil and natural gas revenue........... $23,774,416 $14,485,995 $15,463,432
Operating expenses:
Oil and natural gas operating
expenses and ad valorem taxes..... 2,152,638 1,954,058 2,438,553
Production taxes.................... 1,802,300 1,085,012 937,206
Depletion, depreciation and
amortization...................... 6,961,634 7,812,533 9,254,412
Impairment of oil and gas
properties........................ -- -- 10,012,989
----------- ----------- -----------
Results of operations............. $12,857,844 $ 3,634,392 $(7,179,728)
=========== =========== ===========
F-25
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED): (CONTINUED)
RESERVES--Proved reserves are estimated quantities of oil and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods. Proved oil and natural gas reserve quantities
and the related discounted future net cash flows before income taxes (see
Standardized Measure) for the periods presented are based on estimates prepared
by Ryder Scott Company, independent petroleum engineers. Such estimates have
been prepared in accordance with guidelines established by the Securities and
Exchange Commission.
The Company's net ownership 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.
NATURAL GAS
(MCF)
YEAR ENDED DECEMBER 31,
------------------------------------
2000 1999 1998
---------- ---------- ----------
Proved developed and undeveloped reserves
Beginning of year...................... 20,761,000 24,235,000 29,123,000
Revisions of previous estimates........ 892,000 (5,011,534) (6,834,982)
Extensions and discoveries............. 9,646,700 8,519,618 8,231,477
Sales of natural gas properties........ (733,700) (1,306,146) --
Production............................. (5,206,000) (5,675,938) (6,284,495)
---------- ---------- ----------
End of Year.......................... 25,360,000 20,761,000 24,235,000
========== ========== ==========
Proved developed reserves at year end.... 21,965,000 15,084,000 15,844,000
========== ========== ==========
OIL, CONDENSATE AND NATURAL GAS LIQUIDS
(BBLS)
YEAR ENDED DECEMBER 31,
-----------------------------------------
2000 1999 1998
--------- --------- ---------
Proved developed and undeveloped reserves
Beginning of year....................... 701,382 444,813 866,186
Revisions of previous estimates......... 7,568 150,207 (401,003)
Extensions and discoveries.............. 197,400 309,246 121,404
Sales of natural gas properties......... (12,500) (15,661) --
Production.............................. (173,760) (187,223) (141,774)
-------- -------- --------
End of Year........................... 720,090 701,382 444,813
======== ======== ========
Proved developed reserves at year end..... 674,845 577,775 308,347
======== ======== ========
F-26
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED): (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, 2000 is shown below:
YEAR ENDED DECEMBER 31,
------------------------------------------
2000 1999 1998
------------ ------------ ------------
Future cash inflows................................. $285,318,442 $ 64,112,983 $ 49,444,900
Future oil and natural gas operating expenses....... (33,271,286) (13,055,050) (11,718,097)
Future development costs............................ (2,921,526) (3,170,357) (3,297,539)
Future income tax expense........................... (73,922,604)
------------ ------------ ------------
Future net cash flows............................... 175,203,026 47,887,576 34,429,264
10% discount factor................................. (49,844,011) (13,826,224) (11,699,510)
------------ ------------ ------------
Standardized measure of discounted future net cash
flows............................................. $125,359,015 $ 34,061,352 $ 22,729,754
============ ============ ============
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-27
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED): (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:
YEAR ENDED DECEMBER 31,
------------------------------------------
2000 1999 1998
------------ ------------ ------------
Changes due to current year
operations:
Sales of oil and natural gas, net
of oil and natural gas operating
expenses........................ $(19,819,478) $(11,446,925) $(12,087,673)
Sales of oil and natural gas
properties...................... (1,274,036) (1,439,355)
Extensions and discoveries........ 80,545,294 16,483,064 6,417,976
Changes due to revisions of
standardized variables:
Prices and operating expenses..... 66,248,224 10,947,292 (9,163,029)
Revisions of previous quantity
estimates....................... 3,881,207 (5,903,857) (9,612,849)
Estimated future development
costs........................... 553,576 164,412 2,659,500
Income taxes...................... (47,083,522) 9,645,975
Accretion of discount............. 3,406,135 2,272,975 4,088,863
Production rates (timing) and
other........................... 4,840,263 253,992 (461,662)
------------ ------------ ------------
Net change.......................... 91,297,663 11,331,598 (8,512,899)
Beginning of year................... 34,061,352 22,729,754 31,242,653
------------ ------------ ------------
End of year......................... $125,359,015 $ 34,061,352 $ 22,729,754
============ ============ ============
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-28