UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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, 1999
Commission file number: 0-22149
EDGE PETROLEUM CORPORATION
(Exact name of Registrant as specified in its charter)
Delaware 76-0511037
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
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)
----------------------------
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to section 12(g) of the Act:
Common Stock, Par Value $.01 Per Share
----------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
The aggregate market value of the voting stock held by non-affiliates of
the Registrant at March 3, 2000, was $25,286,316 (based on a value of $3.00 per
share, the closing price of the Common Stock as quoted by NASDAQ National Market
on such date). 9,182,023 shares of Common Stock, par value $.01 per share, were
outstanding on March 3, 2000.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the registrant's 2000
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.
<PAGE>
TABLE OF CONTENTS
PAGE
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES 1
ITEM 3. LEGAL PROCEEDINGS 23
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 23
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS 25
ITEM 6. SELECTED FINANCIAL DATA 26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 27
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT
MARKET RISK 36
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 37
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURES 37
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 38
ITEM 11. EXECUTIVE COMPENSATION 38
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT 38
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 38
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K 38
<PAGE>
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
98,000 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 3-D prospects drilled to date and to assemble
a portfolio of 3-D based drilling prospects. The Company pursues drilling
opportunities that include a blend of shallower, normally pressured reservoirs
that generally involve moderate costs and risks as well as deeper, 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 is pursing 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. The Company's average
daily production for 1999 was 18.6 MMcfe per day as compared to 19.5 MMcfe per
day in 1998. The Company estimated its average daily production would have been
about 20 MMcfe per day in 1999 had it not sold those properties.
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 the year from falling commodity prices
caused a reduction in the number of wells drilled relative to the Company's
original budget and previous years.
The Company's estimate of proved oil and natural gas reserves, as of
December 31, 1999, was 20.8 Bcf of natural gas and 701 MBbls of oil, or about 25
Bcfe. The property sale, referred to above, reduced reserves by about 1.4 Bcfe.
Reserves at December 31, 1998 were 24.2 Bcf of natural gas and 445 MBbls of oil,
or about 26.9 Bcfe combined.
1
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During 1999, the Company drilled 19 gross wells, (6.31 net wells) and
added proved reserves of 6.3 Bcfe, representing a 93% replacement ratio of 1999
production of 6.8 Bcfe. At December 31, 1999, Edge's estimated proved reserves
before income taxes and discounted to present value at 10% per annum were valued
at $34.1 million, based on pricing at December 31, 1999 of $24.22 per Bbl of oil
and $2.42 per Mcf of natural gas. 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.
The Company's technological success is dependent in part upon hiring and
retaining highly skilled technical personnel. The Company has assembled a
technical team that it believes has the capacity to adapt to the rapidly
changing technological demands in the field of oil and natural gas exploration.
This team consists of seven geoscientists with an average of 15 years industry
experience, most of which have had extensive experience with major oil
companies. The Company provides its technical team with a sophisticated work
environment. 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 approach is to acquire large 3-D seismic data
sets along prolific, producing trends of the onshore Gulf Coast and to utilize
advanced visualization and interpretation techniques to identify or evaluate
prospects and then drill those prospects which meet its economic criteria. The
Company typically seeks to
2
<PAGE>
explore in areas with (i) numerous accumulations of normally pressured reserves
at shallow depths and in geologic traps that are difficult to define without the
use of advanced 3-D data visualization and interpretation and (ii) the potential
for large accumulations of deeper, over-pressured reserves. The Company
typically sells a portion of its interest in the deep, over-pressured prospects
in order to mitigate its exploration risk and fund the anticipated capital
requirements for the interests it retains in such prospects, while retaining all
or the majority of its interest in the prospects with normally-pressured
reservoirs.
The Company emphasizes preplanning in project development to lower capital
and operational costs and to efficiently integrate potential well locations into
the existing and planned infrastructure, including gathering systems and other
surface facilities. In constructing surface facilities, the Company seeks to use
reliable, high quality, used equipment in place of new equipment to achieve cost
savings. The Company also seeks to minimize cycle time from drilling to hook-up
of wells, thereby accelerating cash flow and improving ultimate project
economics.
An important component of the Company's exploration approach is the
acquisition of large 3-D seismic data sets at the lowest possible cost. The
Company has sought to obtain large 3-D data sets either by participating in
large 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 cases when the Company does not have field
operator status, the Company is primarily responsible for identifying prospects
for the operator and, when necessary, asserts its rights under its joint
operating agreements to ensure drilling of such prospects. The Company began
field operations of wells in 1995 and currently operates approximately 75% 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, 1999. 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, 1999. Ryder Scott's estimates were based upon a
review of
3
<PAGE>
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, 1999 and estimated development and production costs
that were in effect during December 1999 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, 1999,
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 11 of Notes to the
Consolidated Financial Statements. See ITEMS 1 AND 2.--BUSINESS AND
PROPERTIES--"FORWARD LOOKING INFORMATION AND RISK FACTORS--Uncertainties of
Reserve Information and Future Net Revenue Estimates."
<TABLE>
<CAPTION>
DEVELOPED(1) UNDEVELOPED(2) TOTAL
------------ -------------- ----------
<S> <C> <C> <C>
Oil and condensate (MBbls)(3) 578 123 701
Natural gas (MMcf) 15,084 5,677 20,761
Total MMcfe 18,551 6,419 24,970
Estimated future net revenues before
income taxes $36,513,215 $11,374,361 $47,887,576
Present value of estimated future net
revenues before income taxes
(discounted 10% annum)(4) $26,528,054 $7,533,298 $34,061,352
</TABLE>
- --------------
(1) Proved developed reserves are proved reserves which are expected to be
recovered from existing wells with existing equipment and operating methods.
(2) Proved undeveloped reserves are proved reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
(3) Includes plant products.
(4) Estimated future net revenue represents estimated future gross revenue to be
generated from the production of proved reserves, net of estimated
production and future development costs, using year end oil and natural gas
prices in effect at December 31, 1999, which were $2.42 per Mcf of natural
gas and $24.22 per Bbl of oil without giving effect to hedging activities.
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 revenues from proved reserves and the present value
thereof are based upon certain assumptions, including future prices, production
levels and costs that may not prove correct.
No estimates of proved reserves comparable to those included herein have
been included in reports to any federal agency other than the Commission.
4
<PAGE>
In accordance with Commission regulations, the Ryder Scott Report used
year end oil and natural gas prices in effect at December 31, 1999. 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, 1999. 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.
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,
-------------------------------
1999 1998 1997
------- ------- -------
PRODUCTION:
Oil and Condensate (MBbls)(1) 187 142 166
Natural gas (MMcf) 5,676 6,284 4,299
Natural gas equivalent (MMcfe) 6,799 7,135 5,293
AVERAGE SALES PRICE:
Oil and Condensate ($ per
Bbl)(1) $14.55 $12.29 $17.21
Natural gas ($ per Mcf)(2) 2.07 2.18 2.47
Natural gas equivalent ($ per
Mcfe)(2) 2.13 2.17 2.54
AVERAGE OIL AND NATURAL GAS OPERATING
EXPENSES INCLUDING PRODUCTION AND
AD VALOREM TAXES ($ per Mcfe)(3) $ 0.45 $ 0.47 $ 0.44
- ----------------
(1) Includes plant products.
(2) Includes the effect of hedging activity.
(3) 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, 1999, the Company incurred total
acquisition, exploration and development costs of approximately $76.3 million
and generated proceeds of approximately $12.7 million from the sale of
undeveloped prospects. Total acquisition, exploration, and development
activities from January 1, 1997 to December 31, 1999, resulted in the addition
of approximately 28.3 Bcfe, net to the Company's interest, of proved reserves at
an average reserve replacement cost of $2.25 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.
5
<PAGE>
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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
(in thousands)
Acquisition Cost:
Unproved projects and prospects $ 7,692 $ 20,853 $ 17,660
Exploration costs 3,335 10,236 8,640
Development costs 3,455 3,250 1,208
--------- --------- ---------
Total cost incurred 14,482 34,339 27,508
Less proceeds from sales of prospects 3,471 6,952 2,325
--------- --------- ---------
Net costs incurred $ 11,011 $ 27,387 $ 25,183
========= ========= =========
</TABLE>
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, 1999. In the table, "gross" refers to the
total wells in which the Company has a working interest and "net" refers to
gross wells multiplied by the Company's working interest therein. Wells in which
the Company holds a reversionary interest are not included in the following
table because such interests had not been earned at the time of drilling. The
percentage of the Company's wells in which it holds solely a reversionary
interest has substantially decreased in the last three years.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------
1999 1998 1997
---------------- ----------------- -----------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
EXPLORATORY:
Productive 9 3.78 43 19.34 60 27.07
Non-productive 4 0.67 23 10.27 22 9.68
----- ---- ----- ----- ----- -----
Total 13 4.45 66 29.61 82 36.75
----- ---- ----- ----- ----- -----
DEVELOPMENT:
Productive 5 1.56 12 3.53 15 2.82
Non-productive 1 0.30 5 2.89 4 1.87
----- ---- ----- ----- ----- -----
Total 6 1.86 17 6.42 19 4.69
----- ---- ----- ----- ----- -----
Grand Total 19 6.31 83 36.03 101 41.44
===== ==== ===== ===== ===== =====
</TABLE>
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, 1999.
<TABLE>
<CAPTION>
COMPANY NON-
OPERATED OPERATED TOTAL
---------------- ---------------- ---------------------
GROSS NET GROSS NET GROSS(1) NET(1)
----- ----- ----- ----- --------- ------
<S> <C> <C> <C> <C> <C> <C>
Oil 16 8.76 22 5.49 38 14.25
Natural Gas 53 33.54 56 11.44 109 44.98
----- ----- ----- ----- --------- ------
Total 69 42.30 78 16.93 147 59.23
----- ----- ----- ----- --------- ------
</TABLE>
- ---------------
(1) Includes 54 gross wells shut in, (21.80 net).
6
<PAGE>
ACREAGE DATA
The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of December 31, 1999. Developed acres
refers to acreage within producing units and undeveloped acres refers to acreage
that has not been placed in producing units.
<TABLE>
<CAPTION>
DEVELOPED ACRES UNDEVELOPED ACRES TOTAL
------------------ ------------------ -------------------
GROSS NET GROSS NET GROSS NET
------ ------ ------ ------ ------- ------
<S> <C> <C> <C> <C> <C> <C>
Texas 53,836 19,799 34,022 9,849 87,858 29,648
Louisiana 1,800 375 9,181 3,186 10,981 3,561
Mississippi 2,660 87 624 38 3,284 125
Alabama 1,116 92 247 16 1,363 108
------ ------ ------ ------ ------- ------
Total 59,412 20,353 44,074 13,089 103,486 33,442
====== ====== ====== ====== ======= ======
</TABLE>
Leases covering approximately 15,559 gross (4,328 net), 16,695 gross
(7,273 net), 1,665 gross (1,052 net) and 96 gross (33 net) undeveloped acres are
scheduled to expire in 2000, 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, 1999. 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. While the Company has
operations in 25 3-D project areas it is currently focusing its operations in 18
project areas. The description below groups those project areas into major play
areas and provides detail on the key areas the Company expects to exploit in
2000. The 3-D surveys the Company is using to analyze its project areas range
from regional non-proprietary group shoots to single field proprietary surveys.
The Company, has 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 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."
7
<PAGE>
TEXAS
SOUTH TEXAS FRIO-VICKSBURG TREND
This trend encompasses the Amazon, Aubrey, Encinitas, Picasso, Everest,
and Santellana 3-D project areas, covering about 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 nine wells drilled in this trend in 1999. At year-end
1999, Edge's net production from this area was approximately 8.9 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 2000.
SOUTH TEXAS FRIO-WILCOX TREND
This trend encompasses the O'Connor Ranch, Leroy, Nita Austin, West
Austin, Spartan and Spartan Extension, BTA, Tyler, Brandon, Hiawatha, Buckeye,
Clayton, Bee County, and Cameron 3-D project areas, covering approximately 805
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 seven wells drilled in this trend during 1999.
At year-end 1999, Edge's net production from this area was approximately 5.4
MMcfe per day. Edge currently plans to drill approximately 20 wells in this area
during 2000, 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 two wells in this field. During 1999
Edge participated in the drilling of three wells in South Louisiana, two of
which were dry holes.
SOUTH LOUISIANA MARGTEX, BOLMEX TREND
This trend is the focus of the Company's Genesis Project area in Acadia,
Vermilion, Lafayette and St. Landry Parishes. The Company has reviewed
approximately 500 square miles of 3-D seismic data covering this prolific
natural gas trend and plans to drill at least one deep, high potential gas
prospect in this area in 2000.
SOUTH LOUISIANA NODOSARIA EMBAYMENT TREND
During 1998 the Company initiated the optioning, permitting and leasing of
a 150 square mile area in St. Landry, Acadia and Lafayette Parishes. In late
1998, the Company brought two partners into the project and contracted for the
acquisition of 3-D seismic data over the area, which was completed in mid-1999.
The Company and its partners will have exclusive rights to this data for a nine
to twelve month period after which the seismic contractor has the right to sell
the data to other interested parties. The seismic contractor paid for 30% of the
permitting and acquisition costs for that marketing right. The Company retained
a 45% working interest in the Nodosaria Embayment Project, while paying for only
20% of optioning and data acquisition costs, and its two partners each have a
27.5% working interest.
The Nodosaria Embayment Project area had never been shot with 3-D seismic
but is a prolific producer from older fields drilled based upon 2-D seismic
data. The exploration focus of the project is balanced between intermediate,
normally pressured 10,000 foot targets and deeper, geopressured 15,000 foot plus
targets. Only five wells have been drilled below 15,000 feet on the northern
half of the survey and only 28 wells have been drilled below 15,000 feet in the
southern half. The Company's interpretation of the data is ongoing. The Company
expects to spud the first well in this area early in the second quarter of 2000.
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 are convertible into
common stock. The Company paid $3.6 million for these shares.
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Frontera develops and operates oil and gas projects in emerging market areas
around the world. Frontera's focus is on known hydrocarbon-bearing basins, where
technical risk is reduced. Frontera's first focus area is the onshore Kura
Basin, along the energy corridor from the Caspian Sea to the Black Sea. Frontera
currently holds interests in three large oil and gas fields in Azerbaijan and
Georgia.
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.
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 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, 1999, the
Company had in place several natural gas commodity collars with a financial
institution covering 5,000 - 20,000 MMbtus per day, or approximately 30% - 100%
of the Company's 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 revenues for the three years ended December 31, 1999 was
approximately $(1.1) million, $482,000, and $33,000 respectively, representing
net (losses) and net gains from hedging activity. During December 1999, the
Company entered into a crude oil fixed price swap. The number of barrels of oil
per day ("BOD") and the related fixed price subject to the oil price swap are as
follows: i) January 1, 2000 - March 31, 2000, 150 BOD, swap at $25.60, ii) April
1, 2000 - June 30, 2000, 125 BOD, swap at $22.87, iii) July 1, 2000 - September
30, 2000, 60 BOD, swap at $21.47, and iv) October 1, 2000 - December 31, 2000,
50 BOD, swap at $ 20.46. At December 31, 1999 and 1998, the fair value, net gain
(loss), of outstanding hedges was approximately $15,000 and $(292,000),
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respectively. Subsequent to December 31, 1999, the Company entered into three
natural gas collars. The natural gas collars cover the following MMbtu per day
and floor and ceiling per MMbtu prices: i) February 1, 2000 - February 29, 2000,
6,000 MMbtu per day, $2.20 floor - $2.31 ceiling, ii) March 1, 2000 - April 30,
2000, 6,000 MMbtu per day, $2.20 floor - $2.50 ceiling, and iii) May 1, 2000 -
September 30, 2000, 9,000 MMbtu per day, $2.05 floor - $2.63 ceiling.
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 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
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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 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
wholesaler marketers of gas to the primary role of gas transporters. 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
all other merchants. As a result of the various omnibus rulemaking proceedings
in the late 1980s and the individual pipeline restructuring proceedings of the
early to mid-1990s, the interstate pipelines are now required to provide open
and nondiscriminatory transportation and transportation-related services to all
producers, gas marketing companies, local distribution companies, industrial end
users and other customers seeking service. Through similar orders affecting
intrastate pipelines that provide similar interstate services, the FERC expanded
the impact of open access regulations to intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (i) the large-scale divestiture
of interstate pipeline-owned gas gathering facilities to affiliated or
non-affiliated companies, (ii) further development of rules governing the
relationship of the pipelines with their marketing affiliates, (iii) the
publication of standards relating to the use of electronic bulletin boards and
electronic data exchange by the pipelines to make available transportation
information on a timely basis and to enable transactions to occur on a purely
electronic basis, (iv) further review of the role of the secondary market for
released pipeline capacity and its relationship to open access service in the
primary market and (v) development of policy and promulgation of orders
pertaining to its authorization of market-based rates (rather than traditional
cost-of-service based rates) for transportation or transportation-related
services upon the pipeline's demonstration of lack of market control in the
relevant service market. 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 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
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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.
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.
Beginning later this year, the FERC will conduct a scheduled review of the
indexing system. Any changes resulting from that review, however, would not take
effect until July 2001. 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.
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
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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,
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.
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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
revenues. There can be no assurance that any insurance obtained by the Company
will be adequate to cover any losses or liabilities. The Company cannot predict
the continued availability of insurance or the availability of insurance at
premium levels that justify its purchase. The occurrence of a significant event
not fully insured or indemnified against could materially and adversely affect
the Company's financial condition and operations.
TITLE TO PROPERTIES
The Company believes it has satisfactory title to all of its producing
properties in accordance with standards generally accepted in the oil and
natural gas industry. The Company's properties are subject to customary royalty
interests, liens incident to operating agreements, liens for current taxes and
other burdens which the Company believes do not materially interfere with the
use of or affect the value of such properties. As is customary in the industry
in the case of undeveloped properties, little investigation of record title is
made at the time of acquisition (other than a preliminary review of local
records). Investigations, including a title opinion of local counsel, are made
before commencement of drilling operations.
EMPLOYEES
At December 31, 1999, the Company had 45 full-time employees, primarily
professionals, including nine geologists/geophysicists, four geo-technicians,
four 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.
On December 31, 1999, but effective January 3, 2000, James D. Calaway,
President and Chief Operating Officer and effective December 31, 1999, Brian
Baumler, Controller and Treasurer, resigned their positions with the Company.
Edge has no plans to replace either person. During December 1999, the Company's
Board of Directors approved a workforce reduction program due to reduced
workflow and staffing redundancies. Twelve existing positions were eliminated
leaving the company with 33 employees.
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 per unit of production basis, increases in
wells operated, future growth, effects of the Frontera investment, 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
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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, resumption of production from
Wheeler Property wells, expectation or timing of reaching payout, effects of
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 revenues 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, significant capital requirements of the Company's
exploration and development and technology development programs, governmental
regulation and liability for environmental matters, management of growth and the
related demands on the Company's resources, competition from larger oil and
natural gas companies, the potential inaccuracy of estimates of oil and natural
gas reserve data, property acquisition risks, the potential impact of foreign
political and economic developments on the Company's foreign investments, and
other factors detailed in this document and the Company's other filings with the
Commission. Should one or more of these risks or uncertainties materialize, or
should underlying assumptions prove incorrect, actual outcomes may vary
materially from those indicated.
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 delivery 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--SIGNIFICANT PROJECT AREAS."
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OIL AND NATURAL GAS PRICES ARE HIGHLY VOLATILE IN GENERAL AND LOW PRICES
NEGATIVELY AFFECT THE COMPANY'S FINANCIAL RESULTS
The Company's revenues, 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. 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--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 revenues 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 REVENUES 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.
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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.
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 are federal, state and local
laws and regulations primarily relating to protection of human health and the
environment are applicable to the development, production, handling, storage,
transportation and
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disposal of oil and natural gas, by-products thereof and other substances and
materials produced or used in connection with oil and natural gas operations. In
addition, 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 MAY HAVE DIFFICULTY MANAGING ITS 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. The Company's growth has placed, and is expected to continue
to place, a significant strain on the Company's financial, technical,
operational and administrative resources. Any future growth will place
additional demands on those resources. The Company's ability to continue its
growth will depend upon a number of factors, including its ability to identify
and acquire new exploratory sites, its ability to develop existing sites, its
ability to continue to retain and attract skilled personnel, the results of its
drilling program, hydrocarbon prices 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 workover and remedial
costs, some or all of these assumptions may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of oil and natural gas attributable to any particular group of
properties, classifications of such reserves based on risk of recovery, and
estimates of the future net cash flows expected therefrom prepared by different
engineers or by the same engineers but at different times may vary
substantially. Accordingly, reserve estimates may be subject to downward or
upward adjustment. Actual production, revenues 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
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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
The limited availability of additional credit under the current terms of
the Company's revolving credit facility reduces the Company's flexibility to
changing business and economic conditions and limits its ability to increase the
Company's capital expenditures. 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 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 are unable to 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--Revolving 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, and 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.
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FOREIGN POLITICAL AND ECONOMIC DEVELOPMENTS MAY HURT THE COMPANY'S FOREIGN
INVESTMENTS
The Company's investment in Frontera Resources Corporation , which
operates in among other places, the former Soviet Republic of Georgia,
Azerbaijan and Bolivia, could expose it to risks related to overseas operations.
Operations in foreign countries can be subject to a variety of local laws and
regulations requiring qualifications, use of local labor, the provision of
financial assurances or other restrictions and conditions on operations. Foreign
operations can also be subject to risks of war, civil disturbances, political
instability, unenforceability of foreign contracts, problems in the relationship
between a foreign country and the United States, fluctuations in currency
exchange rates and governmental activities that may limit or disrupt markets,
restrict the movement of funds or result in the deprivation of contract rights
or the taking of property without fair compensation. Local laws and regulations
and events like those described above could limit Frontera's ability to operate
in foreign countries or otherwise have a material adverse affect on the value of
the Company's investment.
YEAR 2000
The Company completed its assessment of the year 2000 processing issues of
its internal technology systems, considering current financial and accounting,
production, land and geological computer systems and software utilized by the
Company during the third quarter of 1999. Due to the need for improved
management reporting, the Company replaced its existing financial and
accounting, production and land applications with new software, which is year
2000 compliant. As of December 31, 1999, the Company had incurred approximately
$206,000 converting to its new financial and accounting system and software and
production and land applications. These costs have been funded from cash flows
from operations and the cost of the new software and necessary hardware upgrades
have been capitalized.
The Company experienced no Year 2000 problems either internally or as
related to third parties.
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.
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
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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.
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.
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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 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.
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PROVED RESERVES. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
PROVED UNDEVELOPED LOCATION. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
PROVED UNDEVELOPED RESERVES. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
RECOMPLETION. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
RESERVOIR. A porous and permeable underground formation containing a natural
accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
ROYALTY INTEREST. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.
3-D SEISMIC. Advanced technology method of detecting accumulations of
hydrocarbons identified through a three-dimensional picture of the subsurface
created by the collection and measurement of the intensity and timing of sound
waves transmitted into the earth as they reflect back to the surface.
UNDEVELOPED ACREAGE. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
WORKING INTEREST OR WI. The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.
WORKOVER. Operations on a producing well to restore or increase production.
ITEM 3. LEGAL PROCEEDINGS
From time to time 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, management of the Company does not expect that the
Company is currently a party to a proceeding that will have a materially adverse
effect on the Company's financial condition, results of operations or cash
flows.
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
23
<PAGE>
experience in the oil and natural gas exploration and production business. He is
59 years old. Mr. Elias' current term as director of the Company expires in
2000.
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 47 years old.
JAMES D. CALAWAY served as the President and Chief Operating Officer and as a
Director of the Company from December 1996 through December 31, 1999. On
December 31, 1999, but effective January 3, 2000, James D. Calaway resigned as
President, Chief Operating Officer and a director of the Company.
BRIAN C. BAUMLER served as Controller of the Company from June 1997 and as
treasure since August 1997. Effective December 31, 2000, Brian C. Baumler
resigned as Controller and Treasurer of the Company.
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.
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.
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.
24
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
As of March 3, 2000, the Company estimates there were approximately 231
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 3, 2000, the Company had 9,182,023 shares outstanding and its closing
price on NASDAQ was $3.00 per share. The following table sets forth, for the
periods indicated, the high and low closing sales prices for Common Stock of the
Company as listed on NASDAQ.
<TABLE>
<CAPTION>
COMMON STOCK
HIGH LOW
CALENDAR 1999 ($) ($)
- ------------------------------------- ---- ----
<S> <C> <C>
QUARTER:
First........................... 5 3/4 4 1/8
Second.......................... 7 1/2 4 5/8
Third........................... 7 1/4 5 5/8
Fourth.......................... 7 1/4 2 1/2
</TABLE>
<TABLE>
<CAPTION>
COMMON STOCK
HIGH LOW
CALENDAR 1998 ($) ($)
- ------------------------------------- ---- ----
<S> <C> <C>
QUARTER:
First........................... 14 9 1/4
Second.......................... 13 3/4 10 5/8
Third........................... 11 7/8 7 7/8
Fourth.......................... 10 1/8 4 1/8
</TABLE>
- ------------
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--Absence of Dividends on Common Stock."
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.
The issuance of the shares was exempt from the registration requirements of the
Securities Act of 1933, as amended, by virtue of Section 4(2) thereof as a
transaction not involving any public offering.
25
<PAGE>
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:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------
1999 1998 1997 1996(3) 1995(3)
--------- ---------- ---------- ------- -------
<S> <C> <C> <C> <C> <C>
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
STATEMENT OF OPERATIONAL DATA:
Oil and natural gas revenue $ 14,486 $ 15,463 $ 13,468 $ 7,719 $ 2,040
Costs and expenses:
Oil and natural gas operating
expenses including
production and ad valorem
taxes 3,039 3,376 2,331 1,600 686
Depletion, depreciation and
amortization 8,512 10,002 2,876 1,613 813
Impairment of oil and natural
gas properties 10,013
General and administrative
expenses 4,528 4,583 4,641 2,753 2,484
Unearned compensation expense 350 621 513
Other charge 1,688 2,898
--------- ---------- ---------- ------- -------
Total operating expenses 18,117 31,493 10,361 5,966 3,983
--------- ---------- ---------- ------- -------
Operating income (loss) (3,631) (16,030) 3,107 1,753 (1,943)
Interest expense (130) (90) (183) (859) (315)
Interest income 52 133 901
Gain on sale of oil and gas
property 3,337
Other income 233
--------- ---------- ---------- ------- -------
Net income (loss) before income
taxes, minority interest and
cumulative effect of
accounting change (3,709) (15,987) 3,825 1,127 1,079
Net income tax (expense) benefit 983 (394) (397)
Minority interest (433) (576)
--------- ---------- ---------- ------- -------
Net income (loss) before
cumulative effect of
accounting change (3,709) (15,004) 3,825 300 106
Cumulative effect of accounting
change 1,781
--------- ---------- ---------- ------- -------
Net income (loss) $ (3,709) $ (13,223) $ 3,825 $ 300 $ 106
========= ========== ========== ======= =======
Basic income (loss) per
share:(1)
Net income (loss) before
cumulative effect of
accounting change $ (0.43) $ (1.93) $ 0.53 $ 0.06 $ 0.02
Cumulative effect of accounting
change 0.23
--------- ---------- ---------- ------- -------
Basic earnings (loss) per
share $ (0.43) $ (1.70) $ 0.53 $ 0.06 $ 0.02
========= ========== ========== ======= =======
Diluted income (loss) per
share:(1)
Net income (loss) before
cumulative effect of
accounting change $ (0.43) $ (1.93) $ 0.52 $ 0.06 $ 0.02
Cumulative effect of
accounting change 0.23
--------- ---------- ---------- ------- -------
Diluted earnings (loss) per
share $ (0.43) $ (1.70) $ 0.52 $ 0.06 $ 0.02
========= ========== ========== ======= =======
Basic weighted average number of
shares outstanding(1) 8,680 7,759 7,275 4,701 4,701
Diluted weighted average number
of shares outstanding(1) 8,680 7,759 7,320 4,701 4,701
STATEMENT OF CASH FLOW DATA:
EBITDA(2) $ 4,933 $ 4,118 $ 6,884 $ 3,166 $ 1,631
Capital expenditures 14,588 34,824 29,874 10,467 8,512
Net cash provided by (used in)
operating activities 5,913 11,983 4,145 2,278 (927)
Net cash used in investing
activities (7,259) (27,989) (31,177) (5,651) (1,154)
Net cash provided by financing
activities 1,651 12,500 29,266 4,716 1,932
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
------------------------------------------------------
1999 1998 1997 1996(3) 1995(3)
--------- ---------- ---------- ------- -------
<S> <C> <C> <C> <C> <C>
(IN THOUSANDS)
BALANCE SHEET DATA:
Working capital $ (4,977) $ (8,255) $ 7,603 $ 690 $ (947)
Property and equipment, net 45,976 47,259 36,663 11,989 7,911
Total assets 55,318 56,279 53,766 19,556 9,858
Long-term debt including current
maturities 6,800 12,500 11,862 6,214
Stockholders' equity (deficit) 42,174 36,956 47,911 (373) (658)
</TABLE>
26
<PAGE>
---------------
(1) 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
OPERATIOINS--"General Overview" ) were outstanding for all periods prior to
the Combination, effective March 3, 1997.
(2) 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.
(3) The Combination (as defined herein) was accounted for as a reorganization of
entities under common control. Accordingly, as of and for the two years in
the period 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.
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 the initial public offering (the "Offering") and 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
27
<PAGE>
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, 1999 and 1997 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, gains and losses are
included in oil and natural gas revenues during the period the hedged production
occurs. At December 31, 1999 and 1998, the fair value, gain (loss), of
outstanding hedges was approximately $15,000 and $(292,000), respectively (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 recent 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, 1999 COMPARED TO THE YEAR ENDED DECEMBER 31, 1998
REVENUE AND PRODUCTION
Oil and natural gas revenues decreased 6% from $15.5 million in 1998 to
$14.5 million in 1999. Production volumes for oil increased 32% from 141,774
Bbls in 1998 to 187,223 Bbls in 1999. The increase in oil production increased
revenues by approximately $559,000, further increased by an 18% increase in
average oil prices that increased revenues by approximately $423,000. 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 reduced
revenues by approximately $630,000. 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 second half
production 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 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 $0.07 per Mcf for
the year ended December 31, 1998.
28
<PAGE>
The following table summarizes production volumes, average sales prices
and operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 1999 and 1998.
<TABLE>
<CAPTION>
1999 PERIOD COMPARED
TO 1998 PERIOD
DECEMBER 31, ------------------------
------------------------ INCREASE % INCREASE
1999 1998 (DECREASE) (DECREASE)
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Oil and condensate (Bbls) 187,223 141,774 45,449 32%
Natural gas (Mcf) 5,675,938 6,284,495 (608,557) (10)%
Natural gas equivalents (Mcfe) 6,799,276 7,135,139 (335,863) (5)%
AVERAGE SALES PRICES:
Oil and condensate ($ per Bbl) $ 14.55 $ 12.29 $ 2.26 18%
Natural gas ($ per Mcf) 2.07 2.18 (0.11) (5)%
Natural gas equivalent ($ per Mcfe) 2.13 2.17 (0.04) (2)%
OPERATING REVENUES:
Oil and condensate $2,723,505 $1,742,311 $ 981,194 56%
Natural gas 11,762,490 13,721,121 (1,958,631) (14)%
---------- ---------- ----------
Total $14,485,995 $15,463,432 $ (977,437) (6)%
========== ========== ==========
</TABLE>
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.
Depletion, depreciation and amortization expense ("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 Securities and Exchange 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 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.
General and administrative expenses ("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.
29
<PAGE>
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
which 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 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 has 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.
30
<PAGE>
YEAR ENDED DECEMBER 31, 1998 COMPARED TO THE YEAR ENDED DECEMBER 31, 1997
REVENUE AND PRODUCTION
Oil and natural gas revenues increased 15% from $13.5 million in 1997 to
$15.5 million in 1998. Production volumes for oil decreased 14% from 165,640
Bbls in 1997 to 141,774 Bbls in 1998. The decrease in oil production decreased
revenues by approximately $411,000, further decreased by a 29% decrease in
average oil prices that reduced revenues by approximately $698,000. Production
volumes for natural gas increased 46% from 4,298,859 Mcf in 1997 to 6,284,495
Mcf in 1998. The increase in natural gas production increased revenues by
approximately $4.9 million. A 12% decrease in average natural gas prices
decreased revenues by approximately $1.8 million. The overall net increase in
oil and natural gas production was due to 55 new gross, (22.87 net), producing
exploratory and development wells drilled and completed since December 31, 1997
partially offset by production declines from existing wells. Included within
natural gas revenues for the two years ended December 31, 1998 and 1997 was
approximately $482,000 and $33,000, respectively, representing net gains from
collar activity. The collar settlements increased the effective average natural
gas prices by $0.07 per Mcf and $0.01 per Mcf, respectively, for the two years
ended December 31, 1998 and 1997.
The following table summarizes production volumes, average sales prices
and operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 1998 and 1997.
<TABLE>
<CAPTION>
1998 PERIOD COMPARED
TO 1997 PERIOD
DECEMBER 31, -------------------------
------------------------- INCREASE % INCREASE
1998 1997 (DECREASE) (DECREASE)
----------- ----------- ----------- ----------
<S> <C> <C> <C> <C>
PRODUCTION VOLUMES:
Oil and condensate (Bbls) 141,774 165,640 (23,866) (14)%
Natural gas (Mcf) 6,284,495 4,298,859 1,985,636 46%
Natural gas equivalents (Mcfe) 7,135,139 5,292,699 1,842,440 35%
AVERAGE SALES PRICES:
Oil and condensate ($ per Bbl) $ 12.29 $ 17.21 $ (4.92) (29)%
Natural gas ($ per Mcf) 2.18 2.47 (0.29) (12)%
Natural gas equivalent ($ per Mcfe) 2.17 2.54 (0.37) (15)%
OPERATING REVENUES:
Oil and condensate $ 1,742,311 $ 2,850,600 $(1,108,289) (39)%
Natural gas 13,721,121 10,617,442 3,103,679 29%
----------- ----------- -----------
Total $15,463,432 $13,468,042 $ 1,995,390 15%
=========== =========== ===========
</TABLE>
COSTS AND OPERATING EXPENSES
Oil and natural gas operating expenses, including production and ad
valorem taxes, increased 45% from $2.3 million in 1997 to $3.4 million in 1998
due to increased production generated from new oil and natural gas wells drilled
and completed in 1998. Oil and natural gas operating expenses, including
production and ad valorem taxes, on a unit of production basis were $0.47 per
Mcfe and $0.44 per Mcfe for the years ended December 31, 1998 and 1997,
respectively.
Depletion, depreciation and amortization expense ("DD&A") increased 248%
from $2.9 million in 1997 to $10.0 million in 1998. Included within DD&A for the
years ended December 31, 1997 and 1998 was $2.48 million and $9.3 million,
respectively, representing depletion expense of oil and natural gas properties.
A 177% increase in the overall depletion rate increased depletion expense by
approximately $5.9 million. The increase in the depletion rate was primarily due
to revisions of oil and natural gas reserve estimates as of December 31, 1998
and the abandonment during the fourth quarter of 1998 of certain projects,
portions of projects and prospects located in non-core areas. Additionally, the
depletion rate was further increased due to the change in accounting method (see
Note 1 to the Consolidated Financial Statements) which increased depletion
expense by approximately $608,000 during the year ended December 31, 1998.
Increased oil and natural gas production further increased depletion expense by
approximately $865,000. Depletion on a unit of production basis for the years
ended December 31, 1998 and 1997 was $1.30 per Mcfe and $0.47 per Mcfe,
respectively. The remaining increase in DD&A was due primarily to depreciation
of new computer hardware and software and office furniture purchased during the
fourth quarter of
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1997 and the amortization of deferred loan costs incurred as a result of a new
credit facility executed during April 1998.
The Securities and Exchange Commission requires that the carrying cost of
proved reserves be assessed periodically for ceiling test impairment. At
December 31,1998 the discounted future net revenues of the Company's proved
reserves were $22.7 million. 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 cost ceiling test write down of its oil and
natural gas properties of approximately $10.0 million. There have been no write
downs of its oil and natural gas properties in prior years.
General and administrative expenses ("G&A") was $4.6 million for each of
the years ended December 31, 1998 and 1997. Excluding the effects of the change
in accounting method (referred to in Note 1 to the Consolidated Financial
Statements), G&A increased by $2.3 million which was primarily attributable to
the hiring of additional employees to support the Company's increased level of
exploration activities and 3-D project generation and costs associated with
being a public company and general office overhead. Included as a reduction in
G&A for the years ended December 31, 1998 and 1997, was approximately $743,000
and $802,000, respectively, of overhead reimbursements and management fees
received from various management, operating and seismic agreements. General and
administrative expenses on a unit of production basis for the years ended
December 31, 1998 and 1997 were $0.64 per Mcfe and $0.88 per Mcfe, respectively.
Unearned compensation expense for the year ended December 31, 1998 and
1997 was $621,191 and $513,393, respectively due to the amortization of unearned
compensation expense recognized from restricted stock granted to executives at
the completion of the Offering. Unearned compensation expense will continue to
be recognized in the future, amortized over a vesting period of five to ten
years.
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, 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, of which $623,000 was paid during 1998.
Interest expense for the year ended December 31, 1998 was $90,075, net of
interest capitalized to oil and natural gas properties of approximately
$411,000, as compared to interest expense of $183,028 for the year ended
December 31, 1997. The weighted average debt was $7.0 million for the year ended
December 31, 1998 compared to $2 million for the same period in 1997.
Interest income for the year ended December 31, 1998 was $132,993 compared
to $900,867 for the same period in 1997. A majority of the interest earned
during 1997 was earned from short-term investments purchased with unused
proceeds from the Offering. The Offering proceeds were 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
which 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 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, 1997. As
of December 31, 1998, the Company has 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, 1998, the Company had an operating loss of
$16.0 million as compared to operating income of $3.1 million in 1997. The
significant decrease in operating income was primarily attributable to
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increased depletion expense, a full cost ceiling test write down, and the other
charge, referred to above, which was further reduced by increased operating
costs and expenses related to the new well additions (55 gross, 22.87 net) and
lower average commodity prices for both oil and natural gas. These decreases in
operating income were partially offset by higher levels of production from new
well additions. Net loss for the year ended December 31, 1998 was $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, as compared to net income of $3.8
million, or basic and diluted earnings per share of $0.53 and $0.52,
respectively for 1997.
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, 1999. 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 SEC 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, 1999 of $577,864
consisting primarily of short-term money market investments, as compared to
$272,428 at December 31, 1998. Working capital was $(5.0) million as of December
31, 1999 as compared to $(8.3) million at December 31, 1998.
Cash flows provided by operations were $5.9 million, $12.0 million and
$4.1 million, for the years ended December 31, 1999, 1998 and 1997,
respectively. The significant decrease in cash flows provided by operations for
the year ended December 31, 1999 is primarily due to significant amount of
collections of accounts receivable from joint interest owners during 1998.
Correspondingly for the year ended December 31, 1997 cash flows provided by
operations were negatively impacted due to an increase in accounts receivable
from joint interest owners. The increase in accounts receivable from joint
interest owners was due to the significant number of wells that were drilled
during 1997 in which Edge was the operator. During early 1998, the Company
transitioned its focus, in an attempt to balance its drilling program, to South
Louisiana to search for drilling opportunities with higher risk/reward while
significantly reducing its South Texas drilling which generated the majority of
Edges drilling program during 1997. Operating cash flows, before changes in
working capital were $6.3 million for both years ended December 31, 1999 and
1998. Operating cash flows, before changes in working capital were $7.2 million
for the year ended December 31, 1997. Lower cash flows during 1998 as compared
to 1997 were due to higher lease operating expenses, John Calaway's resignation
settlement and lower interest income, offset by higher oil and natural gas
revenues. Higher oil and natural gas revenues during 1998 were due to higher
production offset by lower average commodity prices.
During the year ended December 31, 1999, 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 $7.3 million in investing activities during 1999
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
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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 it's 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.
During the year ended December 31, 1997, the Company used $31.2 million in
investing activities including capital expenditures of approximately $29.9
million for oil and natural gas property development offset by proceeds from the
sale of oil and natural gas prospects of $2.3 million. Capital expenditures of
$9.8 million were attributed to the drilling of 101 gross wells, 75 of which
were successful, with the majority of the remaining capital expenditures
representing additions to undeveloped oil and natural gas property, as the
Company made significant investments in future drilling opportunities.
Additionally during 1997, the Company purchased shares of Preferred Stock of
Frontera at a price of $3.6 million which were initially convertible into
approximately 10% of the common stock of Frontera.
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 expects capital expenditures in 2000 to be approximately $13.5
million including capitalized interest and G&A of $1.7 million. A substantial
portion of capital expenditures in 1999 will be invested in the Company's
portfolio of 3-D prospects to fund drilling activities (approximately 35 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 3-D seismic
interpretation capabilities.
Cash flows from financing activities in 1999 were $1.7 million compared to
$12.5 million in 1998. Financing activities during 1999 were comprised of a
private offering of common stock which generated net proceeds of $7.4 million
offset by a repayment of debt of $5.7 million. Financing activities during 1998
were comprised of borrowings on the Company's Revolving Credit Facility. The
significant amount of cash flows from financing activities in 1997 was due to
the completion of the Company's Offering in March 1997 which generated net
proceeds of $41.0, million offset by the repayment Company debt of approximately
$11.7 million.
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 2000 capital expenditures, commitments and working capital requirements
through cash flows from operations, possible available borrowings under its
existing Revolving Credit Facility, and to the extent necessary other financing
activities. The projected 2000 cash flows from operations are not projected to
be sufficient to fund its budgeted exploration and development program. To
provide additional working capital the Company continues to market a portion of
its interest in various Company generated drill ready prospects. Additionally,
the Company is currently evaluating various financing and refinancing options as
well as divestiture of certain non-core and under performing assets. 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
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ITEMS 1 AND 2.--BUSINESS AND PROPERTIES--"FORWARD LOOKING INFORMATION AND RISK
FACTORS--Significant Capital Requirements."
REVOLVING CREDIT FACILITY
During July 1995, the Company entered into a revolving credit facility
(the "Revolving Credit Facility") with a bank to finance temporary working
capital requirements. The Revolving Credit Facility originally provided up to
$20 million in borrowings limited by a borrowing base, as defined by the
Revolving Credit Facility. Effective April 1, 1998, the Company amended and
restated its Revolving Credit Facility to provide a revolving line of credit of
up to $100 million bearing interest at a rate equal to prime or LIBOR plus 1.5%
- - 2% depending on the level of borrowing base utilization. The Company's initial
borrowing base authorized by the banks was approximately $15 million. The
Revolving Credit Facility is secured by substantially all the assets of the
Company.
Effective March 1, 1999, the Company and the bank amended the Revolving
Credit Facility to include the following terms: 1) the initial borrowing base
was $12 million comprised of two tranches, a $9 million Revolving Credit
Facility and a $3 million term facility; 2) beginning May 1, 1999, and on the
first day of each month thereafter, the Revolving Credit Facility borrowing base
was required to be reduced by $400,000; and 3) 75% of prospect sales proceeds
were to be used to pay down the term facility with the remaining unpaid term
facility balance maturing on August 31, 1999. On May 8, 1999, from proceeds
generated by the Private Offering (see Note 8 to the consolidated financial
statements), the Company repaid the $3 million term loan in addition to $1.9
million of the Revolving Credit Facility.
Each quarter, at the election of the Company or the bank, the borrowing
base can be redetermined. At December 31, 1999 and 1998, the borrowing base
originally authorized by the bank was $9.0 million and $15.0 million,
respectively. The borrowing base is also subject to mandatory reductions which
are subject to revision each time the Revolving Credit Facility is redetermined.
At December 31, 1999 and 1998, the borrowing base was required to be reduced on
the first day of each subsequent month by $450,000 and $550,000, respectively.
Total reductions from the original borrowing base were $450,000 and $1,650,000
as of December 31, 1999 and 1998, respectively.
At December 31, 1999, borrowings under this facility totaled $6.8 million
with approximately $1.8 million available for future borrowings. At March 1,
2000, total borrowings under the Revolving Credit Facility were $7.2 million
with no additional borrowings available under this facility. The terms of the
Revolving Credit facility require the borrowing base to be reduced by $450,000
on the first day of each subsequent month . For the years ended December 31,
1999 and 1998, the weighted average debt was $8.4 million and $7 million,
respectively, and the weighted average interest rate was 7.6% and 7.3%,
respectively.
The Revolving Credit Facility provides for certain restrictions, including
but not limited to, limitations on additional borrowings and issues of capital
stock, sales of its oil and natural gas properties or other collateral,
engaging in merger or consolidation transactions and prohibitions of dividends
and certain distributions of cash or properties and certain liens. The
Revolving Credit Facility also contains certain financial covenants. The
Tangible Net Worth Covenant requires that at the end of each quarter the
Company's Tangible Net Worth be at least 90% of the Company's actual tangible
net worth as reported at December 31, 1998 (or $33,260,720) plus 50% of
positive net income and 100% of other increases in equity for all fiscal
quarters ending subsequent to December 31, 1998. The Fixed Charge Covenant
requires that at the end of each quarter beginning June 30, 1999, the ratio of
annualized EBITDA (as defined) to the sum of annualized interest expense plus
50% of the quarter end loans outstanding must be at least 1.25 to 1.00. At
December 31, 1999 the Company was in compliance with the above mentioned
covenants.
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
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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).
YEAR 2000
The Company completed its assessment of the year 2000 processing issues of
its internal technology systems, considering current financial and accounting,
production, land and geological computer systems and software utilized by the
Company during the third quarter of 1999. Due to the need for improved
management reporting, the Company replaced its existing financial and
accounting, production and land applications with new software, which is year
2000 compliant. As of December 31, 1999, the Company had incurred approximately
$206,000 converting to its new financial and accounting system and software and
production and land applications. These costs have been funded from cash flows
from operations and the cost of the new software and necessary hardware upgrades
have been capitalized.
The Company experienced no Year 2000 problems either internally or as
related to third parties.
ACCOUNTING PRONOUNCEMENTS
DERIVATIVES - In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133, "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS No. 133"). SFAS No. 133 establishes
accounting and reporting standards for derivative instruments and hedging
activities that require an entity to recognize all derivatives as an asset or
liability measured at fair value. Depending on the intended use of the
derivatives, changes in its fair value will be reported in the period of change
as either a component of earnings or a component of other comprehensive income.
In June 1999, the Financial Accounting Standards Board issued SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133" ("SFAS No. 137"). SFAS No. 137 delays
the effective date for implementation of SFAS No. 133 for one year making SFAS
No. 133 effective for all fiscal quarters of all fiscal years beginning after
June 15, 2000. Retroactive application to periods prior to adoption is not
allowed. The Company has not quantified the impact of adoption on its financial
statements or the date it intends to adopt. Earlier application of SFAS No. 133
is encouraged, but not prior to the beginning of any fiscal quarter that begins
after issuance of SFAS No. 137.
HEDGING ACTIVITIES
Subsequent to December 31, 1999, the Company entered into three natural
gas collars. The natural gas collars cover the following MMbtu per day and floor
and ceiling per MMbtu prices: i) February 1, 2000 - February 29, 2000, 6,000
MMbtu per day, $2.20 floor - $2.31 ceiling, ii) March 1, 2000 - April 30, 2000,
6,000 MMbtu per day, $2.20 floor - $2.50 ceiling, and iii) May 1, 2000 -
September 30, 2000, 9,000 MMbtu per day, $2.05 floor - $2.63 ceiling. Total
production covered by these hedges is approximately 1.9 Bcfe or approximately
35% of the Company's estimated 2000 production.
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 Revolving 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, 1999
floating interest rate of 8%, a 10% change in interest rate would result in an
increase or decrease of interest expense of approximately $52,000 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 1999, due to the instability of oil prices and to
achieve a more predictable cash flow, the Company has put in place a fixed price
oil swap for a portion of its year 2000 oil and
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condensate 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 number of barrels of oil per day
("BOD") and the related fixed price subject to the oil price swap are as
follows: i) January 1, 2000 - March 31, 2000, 150 BOD, swap at $25.60, ii) April
1, 2000 - June 30, 2000, 125 BOD, swap at $22.87, iii) July 1, 2000 - September
30, 2000, 60 BOD, swap at $21.47, and iv) October 1, 2000 - December 31, 2000,
50 BOD, swap at $ 20.46. At December 31, 1999, the fair value of the outstanding
hedge was approximately $15,000. A 10% change in the oil price per barrel would
cause the total fair value of the swap to increase or decrease by approximately
$79,000. Subsequent to December 31, 1999, the Company entered into three natural
gas collars. The natural gas collars cover the following MMbtu per day and floor
and ceiling per MMbtu prices: i) February 1, 2000 - February 29, 2000, 6,000
MMbtu per day, $2.20 floor - $2.31 ceiling, ii) March 1, 2000 - April 30, 2000,
6,000 MMbtu per day, $2.20 floor - $2.50 ceiling and iii) May 1, 2000 -
September 30, 2000, 9,000 MMbtu per day, $2.05 floor - $2.63 ceiling.
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
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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 2000 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, 1999. 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.
Mr. William H. White resigned as a director in February 2000.
ITEM 11. EXECUTIVE COMPENSATION
The information required by ITEM 11. will be contained in the Proxy
Statement under the heading "Executive Compensation and Other Information" and
is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by ITEM 12. will be contained in the Proxy
Statement under the heading "Security Ownership of Management and Certain
Beneficial Owners" and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by ITEM 13. will be contained in the Proxy
Statement under the heading "Transactions with Management and Certain
Shareholders" and "Executive Compensation and Other Information" and is
incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial Statements and Schedules:
1. Financial Statements: See Index to the Consolidated Financial Statements and
Supplementary Information immediately following the signature page of this
report.
2. Financial Statement Schedule: See Index to the Consolidated Financial
Statements and Supplementary Information immediately following the signature
page of this report.
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)).
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+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 -- Amended and Restated Credit Agreement, dated April 1, 1998, by
and between Edge Petroleum Corporation and Edge Petroleum
Exploration Company (collectively the "Borrower") and Compass Bank,
a Texas state chartered banking institution, as Agent for itself and
First National Bank of Chicago and other lenders party thereto.
(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 -- First Amendment dated September 29, 1998 to the Amended and
Restated Credit Agreement, dated as of April 1, 1998, by and between
the Borrower and the First National Bank of Chicago as agent and a
Lender thereto (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 -- 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).
+4.4 -- 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).
-- 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.
+4.5 -- 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 form 10-Q/A for the
quarter ended March 31, 1999).
+4.6 -- Warrant agreement dated as of May 6, 1999 between the Company and
the Warrant holders named therein (Included in and incorporated by
reference from exhibit 4.5 to the Company's for 10-Q/A for the
quarter ended March 31, 1999).
+4.7 -- Form of Warrant for the purchase of the Common Stock (Included in
and incorporated by reference from the Common Stock Subscription
Agreement from exhibit 4.5 to the Company's for 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)).
39
<PAGE>
+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 -- Employment Agreement dated February 25, 1997 between Edge
Petroleum Corporation and James D. Calaway (Incorporated by
reference from exhibit 10.5 Company's Quarterly Report on Form 10-Q
for the quarter ended June 30, 1997).
+10.5 -- 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)).
+10.6 -- 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)).
+10.7 -- 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 10K for the year
ended December 31, 1998).
+10.8 -- Agreement dated as of November 16, 1998 by and between the
Company and John E. Calaway. (Incorporated by Reference from exhibit
10.13 to the Company's Annual Report on Form 10K for the year ended
December 31, 1998).
+10.9 -- 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).
+10.10 -- Edge Petroleum Corporation Incentive Plan "Standard Non-Qualified
Stock Option Agreement" by and between Edge Petroleum Corporation
and the Officers named therein. (Incorporated by Reference from
exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 1999).
+10.11 -- Edge Petroleum Corporation Incentive Plan "Director Non-Qualified
Stock Option Agreement" by and between Edge Petroleum Corporation
and the Directors named therein. (Incorporated by Reference from
exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 1999).
+10.12 -- Severance Agreements by and between Edge Petroleum Corporation
and the Officers of the Company named 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).
10.13 -- Severance Agreement dated as of December 17, 1999 by and between
Edge Petroleum Corporation and James D. Calaway.
+10.14 -- 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).
+10.15 -- 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).
10.16 -- 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.
40
<PAGE>
21.1 -- Subsidiaries of the Company.
23.1 -- Consent of Deloitte & Touche LLP.
23.2 -- Consent of Ryder Scott Company.
27.1 -- Financial Data Schedule.
99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers as of December 31, 1999 (included as an appendix to this
Form 10-K).
- -------------------
+ 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, 1999.
41
<PAGE>
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 22, 2000 /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 22, 2000 /s/ JOHN W. ELIAS
John W. Elias
Chief Executive Officer and
Chairman of the Board
(Principal Executive Officer)
DATE MARCH 22, 2000 /s/ MICHAEL G. LONG
Michael G. Long
Senior Vice President and
Chief Financial Officer
(Principal Financial Officer
and Controller)
DATE MARCH 22, 2000 /s/ VINCENT ANDREWS
Vincent Andrews
Director
DATE MARCH 22, 2000 /s/ DAVID B. BENEDICT
David B. Benedict
Director
DATE MARCH 22, 2000 /s/ NILS P. PETERSON
Nils P. Peterson
Director
DATE MARCH 22, 2000 /s/ STANLEY S. RAPHAEL
Stanley S. Raphael
Director
DATE MARCH 22, 2000 /s/ JOHN SFONDRINI
John Sfondrini
Director
DATE MARCH 22, 2000 /s/ ROBERT W. SHOWER
Robert W. Shower
Director
42
<PAGE>
EDGE PETROLEUM CORPORATION
Index to Consolidated Financial Statements and Supplementary Information
Page
CONSOLIDATED FINANCIAL STATEMENTS
Audited Financial Statements:
Independent Auditors' Report......................................... F-2
Consolidated Balance Sheets as of December 31, 1999 and 1998......... F-3
Consolidated Statements of Operations for the Years Ended
December 31, 1999, 1998 and 1997................................... F-4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1999, 1998 and 1997................................... F-5
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1999, 1998 and 1997................................... F-6
Notes to Consolidated Financial Statements........................... F-7
Unaudited Information:
Supplementary Information to Consolidated Financial Statements....... F-19
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.
<PAGE>
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, 1999 and 1998, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1999. 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 generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of the Company at December 31, 1999 and 1998,
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 1999, in conformity with generally accepted
accounting principles.
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.
Houston, Texas
February 18, 2000
F-2
<PAGE>
DECEMBER 31,
----------------------------
1999 1998
------------- -------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 577,864 $ 272,428
Accounts receivable, trade 3,489,709 2,237,113
Accounts receivable, joint
interest owners, net of
allowance of $163,000 and
$250,000 at December 31, 1999
and 1998, respectively 1,177,555 2,215,096
Receivables from related parties 59,951 228,922
Other current assets 161,558 313,631
------------- -------------
Total current assets 5,466,637 5,267,190
PROPERTY AND EQUIPMENT, Net -- full
cost method of accounting for oil
and natural gas properties 45,976,007 47,258,993
INVESTMENT IN FRONTERA 3,867,233 3,744,935
OTHER ASSETS 7,788 7,789
------------- -------------
TOTAL ASSETS $ 55,317,665 $ 56,278,907
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 1,332,760 $ 2,948,791
Accrued liabilities 4,994,929 3,779,881
Accrued interest payable 16,369 93,880
Current portion of long-term
debt 4,100,000 6,700,000
------------- -------------
Total current
liabilities 10,444,058 13,522,552
------------- -------------
LONG-TERM DEBT 2,700,000 5,800,000
------------- -------------
Total liabilities 13,144,058 19,322,552
------------- -------------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, $.01 par value;
5,000,000 shares authorized;
none outstanding
Common stock, $.01 par value;
25,000,000 shares authorized;
9,182,023 and 7,758,667 shares
issued and outstanding at
December 31, 1999 and 1998,
respectively 91,820 77,586
Additional paid-in capital 56,223,901 47,769,159
Retained earnings (deficit) (13,107,890) (9,398,410)
Unearned
compensation -- restricted
stock (34,224) (1,491,980)
------------- -------------
Total stockholders'
equity 42,173,607 36,956,355
------------- -------------
TOTAL LIABILITIES AND STOCKHOLDERS'
EQUITY $ 55,317,665 $ 56,278,907
============= =============
See accompanying notes to the consolidated financial statements.
F-3
<PAGE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1999 1998 1997
------------- -------------- -------------
<S> <C> <C> <C>
OIL AND NATURAL GAS REVENUES $ 14,485,995 $ 15,463,432 $ 13,468,042
OPERATING EXPENSES:
Oil and natural gas operating
expenses including production
and ad valorem taxes 3,039,070 3,375,759 2,330,648
Depletion, depreciation, and
amortization 8,511,826 10,002,533 2,875,457
Impairment of oil and natural
gas properties 10,012,989
General and administrative
expenses 4,528,517 4,582,973 4,641,374
Unearned compensation expense 349,623 621,191 513,393
Other charge 1,688,227 2,898,125
------------- -------------- -------------
Total operating expenses 18,117,263 31,493,570 10,360,872
------------- -------------- -------------
OPERATING INCOME (LOSS) (3,631,268) (16,030,138) 3,107,170
OTHER INCOME AND (EXPENSE):
Interest expense (130,067) (90,075) (183,028)
Interest income 51,855 132,993 900,867
------------- -------------- -------------
NET INCOME (LOSS) BEFORE INCOME TAXES
AND CUMULATIVE EFFECT OF ACCOUNTING
CHANGE (3,709,480) (15,987,220) 3,825,009
INCOME TAX BENEFIT 982,966
------------- -------------- -------------
NET INCOME (LOSS) BEFORE CUMULATIVE
EFFECT OF ACCOUNTING CHANGE (3,709,480) (15,004,254) 3,825,009
CUMULATIVE EFFECT OF ACCOUNTING
CHANGE 1,780,835
------------- -------------- -------------
NET INCOME (LOSS) $ (3,709,480) $ (13,223,419) $ 3,825,009
============= ============== =============
BASIC EARNINGS (LOSS) PER SHARE:
Net income (loss) before
cumulative effect of
accounting change $ (0.43) $ (1.93) $ 0.53
Cumulative effect of accounting
change 0.23
------------- -------------- -------------
Basic earnings (loss) per share $ (0.43) $ (1.70) $ 0.53
============= ============== =============
DILUTED EARNINGS (LOSS) PER SHARE:
Net income (loss) before
cumulative effect of
accounting change $ (0.43) $ (1.93) $ 0.52
Cumulative effect of accounting
change 0.23
------------- -------------- -------------
Diluted earnings (loss) per
share $ (0.43) $ (1.70) $ 0.52
============= ============== =============
BASIC WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 8,680,369 7,758,667 7,274,617
============= ============== =============
DILUTED WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 8,680,369 7,758,667 7,320,400
============= ============== =============
</TABLE>
See accompanying notes to the consolidated financial statements.
F-4
<PAGE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------
1999 1998 1997
----------- ------------ -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $(3,709,480) $(13,223,419) $ 3,825,009
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 8,511,826 10,002,533 2,875,457
Impairment of oil and
natural gas properties 10,012,989
Deferred income taxes (982,966)
Unearned compensation
expense 1,483,211 2,268,610 513,393
Changes in assets and
liabilities:
Accounts receivable, trade (1,252,596) 157,384 (355,608)
Accounts receivable, joint
interest owners, net 1,037,541 4,332,523 (3,888,594)
Receivable from related
parties 168,971 156,270 (198,630)
Other current assets 152,073 38,940 (238,115)
Other assets 9,443 1,088
Accounts payable, trade (1,616,031) (403,213) 2,292,013
Accrued interest payable (77,511) 93,880 (74,354)
Accrued liabilities 1,215,048 1,301,259 (606,292)
----------- ------------ -----------
Net cash provided by
operating activities 5,913,052 11,983,398 4,145,367
------------ ------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of prospects,
property and equipment (14,587,680) (34,823,922) (29,874,155)
Proceeds from the sale of
prospects and oil and natural
gas properties 7,451,341 6,951,673 2,325,418
Investment in Frontera (122,298) (116,671) (3,628,264)
------------ ------------ -----------
Net cash used in
investing activities (7,258,637) (27,988,920) (31,177,001)
------------ ------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable 12,500,000 867,350
Payment on notes payable (5,700,000) (11,017,348)
Payment on long-term notes
payable (411,904)
Payment on related party
subordinated loans (1,300,000)
Net proceeds from issuance of
common stock 7,351,021 41,028,258
Net proceeds from exercise of
common stock options 100,000
------------ ------------ -----------
Net cash provided by
financing activities 1,651,021 12,500,000 29,266,356
------------ ------------ -----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 305,436 (3,505,522) 2,234,722
CASH AND CASH EQUIVALENTS, BEGINNING
OF PERIOD 272,428 3,777,950 1,543,228
------------ ------------ -----------
CASH AND CASH EQUIVALENTS, END OF
PERIOD $ 577,864 $ 272,428 $ 3,777,950
============ ============ ===========
SUPPLEMENTAL CASH FLOW
DISCLOSURES --
Cash paid for interest $ 740,694 $ 415,820 $ 257,382
NON-CASH TRANSACTIONS:
Combination transactions $ 3,599,635
Deferred offering costs at
December 31, 1996 capitalized
to equity $ 1,006,379
Tax benefit from exercise of
common stock options $ 224,617
Issuance of restricted common
stock $ 29,479 $ 148,882
Issuance of common stock for oil
and natural gas properties $ 92,500
</TABLE>
See accompanying notes to the consolidated financial statements.
F-5
<PAGE>
<TABLE>
<CAPTION>
OLD EDGE
COMMON STOCK COMMON STOCK ADDITIONAL
---------------------- ------------------- PAID-IN TREASURY RETAINED
SHARES AMOUNT SHARES AMOUNT CAPITAL STOCK EARNINGS(DEFICIT)
------------ ------ --------- ------- ----------- -------- ------------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE,
JANUARY 1, 1997 ................... 105,263 $ 1,053 $ 634,695 $(42,000) $ (967,117)
Combination ....................... (105,263) (1,053) 4,701,361 $47,014 2,544,557 42,000 967,117
Public common stock offering, net
of offering costs of $5.4 million 2,760,000 27,600 39,994,279
Issuance of restricted common stock 250,586 2,506 4,132,163
Proceeds from the exercise of
common stock options ............ 48,922 489 99,511
Tax benefit from exercise of common
stock options ................... 224,617
Unearned compensation expense
Net income ........................ 3,825,009
------------ ------ --------- ------- ----------- -------- ------------
BALANCE
DECEMBER 31, 1997 ................. -- -- 7,760,869 77,609 47,629,822 -- 3,825,009
Issuance of restricted common stock 12,025 120 148,762
Forfeiture of restricted common
stock ........................... (14,227) (143) (9,425)
Unearned compensation expense
Net loss .......................... (13,223,419)
------------ ------ --------- ------- ----------- -------- ------------
BALANCE
DECEMBER 31, 1998 ................. -- -- 7,758,667 77,586 47,769,159 -- (9,398,410)
Issuance of restricted common stock 4,809 48 29,431
Forfeiture of restricted common
stock ........................... (325) (3) (4,021)
Private common stock offering, net
of offering costs of $261,479 ... 1,400,000 14,000 7,337,021
Issuance of common stock for oil
and natural gas properties ...... 18,872 189 92,311
Unearned compensation expense
Net loss .......................... (3,709,480)
------------ ------ --------- ------- ----------- -------- ------------
BALANCE,
DECEMBER 31, 1999 ................. -- $ -- 9,182,023 $91,820 $55,223,901 $ -- $(13,107,890)
============ ====== ========= ======= =========== ======== ============
</TABLE>
UNEARNED
COMPENSATION - TOTAL
RESTRICTED STOCKHOLDERS'
STOCK EQUITY (DEFICIT)
------------ ------------
BALANCE,
JANUARY 1, 1997 $ (373,369)
Combination 3,599,635
Public common stock offering, net
of offering costs of $5.4 million 40,021,879
Issuance of restricted common stock $ (4,134,669)
Proceeds from the exercise of
common stock options 100,000
Tax benefit from exercise of common
stock options 224,617
Unearned compensation expense 513,393 513,393
Net income 3,825,009
------------ ------------
BALANCE
DECEMBER 31, 1997 (3,621,276) 47,911,164
Issuance of restricted common stock (148,882)
Forfeiture of restricted common
stock 9,568
Unearned compensation expense 2,268,610 2,268,610
Net loss (13,223,419)
------------ ------------
BALANCE
DECEMBER 31, 1998 (1,491,980) 36,956,355
Issuance of restricted common stock (29,479)
Forfeiture of restricted common
stock 4,024
Private common stock offering, net
of offering costs of $261,479 7,351,021
Issuance of common stock for oil
and natural gas properties 92,500
Unearned compensation expense 1,483,211 1,483,211
Net loss (3,709,480)
------------ ------------
BALANCE,
DECEMBER 31, 1999 $ (34,224) $ 42,173,607
============ ============
See accompanying notes to the consolidated financial statements.
F-6
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL (Y) The Company was organized as a Delaware corporation in August
1996 in connection with the Offering and 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 (Y) 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 98,000 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
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).
F-7
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The following pro forma amounts reflect the effect of retroactive
application of the accounting change on general and administrative expenses,
depletion and related income taxes.
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
--------------------------------------------
1999 1998 1997
------------- -------------- -------------
Net income (loss):
<S> <C> <C> <C>
As reported $ (3,709,480) $ (13,223,449) $ 3,825,009
============= ============== =============
Pro forma $ (3,709,480) $ (15,004,254) $ 4,005,275
============= ============== =============
Basic earnings (loss) per share:
As reported $ (0.43) $ (1.70) $ 0.53
============= ============== =============
Pro forma $ (0.43) $ (1.93) $ 0.55
============= ============== =============
Diluted earnings (loss) per share:
As reported $ (0.43) $ (1.70) $ 0.52
============= ============== =============
Pro forma $ (0.43) $ (1.93) $ 0.55
============= ============== =============
Basic weighted average number of
common shares outstanding 8,680,269 7,758,667 7,274,617
============= ============== =============
Diluted weighted average number of
common shares outstanding 8,680,269 7,758,667 7,320,400
============= ============== =============
</TABLE>
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 (Y) 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,
1999, 1998 and 1997 were $1.15, $1.30 and $0.47, 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. 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.
F-8
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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).
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 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 (Y) 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. Frontera's focus is on known hydrocarbon-bearing basins,
where technical risk is reduced. Frontera's first focus area is the onshore Kura
Basin, along the energy corridor from the Caspian Sea to the Black Sea. Frontera
currently holds interests in three large oil and gas fields in Azerbaijan and
Georgia.
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 believes that the fair market value of its investment in Frontera
is in excess of its carrying value.
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).
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
F-9
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 (Y) 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, 1999 and 1998 approximates fair value and the
fair value, gain (loss), of outstanding hedges was approximately $15,000 and
$(292,000), respectively.
DERIVATIVES - In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 133, "Accounting for Derivative
Instruments and Hedging Activity" ("SFAS No. 133"). SFAS No. 133 establishes
accounting and reporting standards for derivative instruments and hedging
activities that require an entity to recognize all derivatives as an asset or
liability measured at fair value. Depending on the intended use of the
derivatives, changes in its fair value will be reported in the period of change
as either a component of earnings or a component of other comprehensive income.
In June 1999, the Financial Accounting Standards Board issued SFAS No. 137,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133" ("SFAS No. 137"). SFAS No. 137 delays
the effective date for implementation of SFAS No. 133 for one year making SFAS
No. 133 effective for all fiscal quarters of all fiscal years beginning after
June 15, 2000. Retroactive application to periods prior to adoption is not
allowed. The Company has not quantified the impact of adoption on its financial
statements or the date it intends to adopt.
COMPREHENSIVE INCOME - As of December 31, 1999, 1998 and 1997, there were no
adjustments ("Other Comprehensive Income") to net income (loss) in deriving
comprehensive income.
USE OF ESTIMATES (Y) The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities 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 (Y) 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, 1999 and 1998, property and equipment consisted of the
following:
----------------------------
1999 1998
----------- -----------
Developed oil and natural gas
properties $58,981,484 $48,441,741
Undeveloped oil and natural gas
properties 17,930,027 21,388,831
Computer equipment and software 3,769,489 3,663,335
Other office property and equipment 1,286,669 1,282,273
----------- -----------
Total property and equipment 81,967,669 74,776,180
Accumulated depletion, depreciation
and amortization (35,991,662) (27,517,187)
----------- -----------
Property and equipment, net $45,976,007 $47,258,993
=========== ===========
F-10
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
The following table summarizes the cost of the properties not subject to
amortization for the year the cost was incurred:
DECEMBER 31,
---------------------------
1999 1998
----------- -----------
Year cost incurred:
Remainder $ 172,991
1995 $ 50,116 182,210
1996 333,077 943,055
1997 2,276,640 4,489,822
1998 7,409,175 15,600,753
1999 7,861,019
----------- -----------
Total $17,930,027 $21,388,831
=========== ===========
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 it's 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, shall be 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
During July 1995, the Company entered into a revolving credit facility
(the "Revolving Credit Facility") with a bank to finance temporary working
capital requirements. The Revolving Credit Facility originally provided up to
$20 million in borrowings limited by a borrowing base, as defined by the
Revolving Credit Facility. Effective April 1, 1998, the Company amended and
restated its Revolving Credit Facility to provide a revolving line of credit of
up to $100 million bearing interest at a rate equal to prime or LIBOR plus 1.5%
- - 2% depending on the level of borrowing base utilization. The Company's initial
borrowing base authorized by the banks was approximately $15 million. The
Revolving Credit Facility is secured by substantially all the assets of the
Company.
Effective March 1, 1999, the Company and the bank amended the Revolving
Credit Facility to include the following terms: 1) the initial borrowing base
was $12 million comprised of two tranches, a $9 million Revolving Credit
Facility and a $3 million term facility; 2) beginning May 1, 1999, and on the
first day of each month thereafter, the Revolving Credit Facility borrowing base
was required to be reduced by $400,000; and 3) 75% of prospect sales proceeds
were to be used to pay down the term facility with the remaining unpaid term
facility balance maturing on August 31, 1999. On May 8, 1999, from proceeds
generated by the Private Offering (see Note 8), the Company repaid the $3
million term loan in addition to $1.9 million of the Revolving Credit Facility.
Each quarter, at the election of the Company or the bank, the borrowing
base can be redetermined. At December 31, 1999 and 1998, the borrowing base
originally authorized by the bank was $9.0 million and $15.0 million,
respectively. The borrowing base is also subject to mandatory reductions which
are subject to revision each time the Revolving Credit Facility is redetermined.
At December 31, 1999 and 1998, the borrowing base was
F-11
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
required to be reduced on the first day of each subsequent month by $450,000 and
$550,000, respectively. Total reductions from the original borrowing base were
$450,000 and $1,650,000 as of December 31, 1999 and 1998, respectively.
At December 31, 1999, borrowings under this facility totaled $6.8 million
with approximately $1.8 million available for future borrowings. At March 1,
2000, total borrowings under the Revolving Credit Facility were $7.2 million
with no additional borrowings available under this facility. The terms of the
Revolving Credit facility require the borrowing base to be reduced by $450,000
on the first day of each subsequent month. For the years ended December 31, 1999
and 1998, the weighted average debt was $8.4 million and $7 million,
respectively, and the weighted average interest rate was 7.6% and 7.3%,
respectively.
The Revolving Credit Facility provides for certain restrictions, including
but not limited to, limitations on additional borrowings and issues of capital
stock, sales of its oil and natural gas properties or other collateral, engaging
in merger or consolidation transactions and prohibitions of dividends and
certain distributions of cash or properties and certain liens. The Revolving
Credit Facility also contains certain financial covenants. The Tangible Net
Worth Covenant requires that at the end of each quarter the Company's Tangible
Net Worth be at least 90% of the Company's actual tangible net worth as reported
at December 31, 1998 (or $33,260,720) plus 50% of positive net income and 100%
of other increases in equity for all fiscal quarters ending subsequent to
December 31, 1998. The Fixed Charge Covenant requires that at the end of each
quarter beginning June 30, 1999, the ratio of annualized EBITDA (as defined) to
the sum of annualized interest expense plus 50% of the quarter end loans
outstanding must be at least 1.25 to 1.00. At December 31, 1999 the Company was
in compliance with the above mentioned covenants.
At December 31, 1999 and 1998, current maturities of long-term debt and
long-term debt consisted of the following:
1999 1998
---------- -----------
Revolving credit facility $6,800,000 $12,500,000
Current portion (4,100,000) (6,700,000)
---------- -----------
Long-term portion $2,700,000 $ 5,800,000
========== ===========
4. HEDGING ACTIVITIES
The impact on oil and natural gas revenues from hedging activities for the
three years ended December 31, 1999, 1998 and 1997 was as follows:
<TABLE>
<CAPTION>
GAIN (LOSS)
--------------------------------
EFFECTIVE DATES MMBTU DECEMBER 31,
HEDGE ---------------------- PRICE PER VOLUMES --------------------------------
TYPE BEGINNING ENDING MMBTU PER DAY 1999 1998 1997
- ------- --------- -------- -------------- ------- ----------- -------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
Collar 10/1/97 1/31/98 $ 2.50 - $3.15 5,000 $33,150
Collar 2/1/98 4/30/98 $ 2.25 - $2.75 5,000 $ 36,700
Collar 4/1/98 6/30/98 $ 2.15 - $2.37 10,000 30,000
Collar 7/1/98 9/30/98 $ 2.25 - $2.88 10,000 266,900
Collar 10/1/98 12/31/98 $ 2.00 - $2.63 5,000 1,500
Collar 10/1/98 12/31/98 $ 2.11 - $2.60 5,000 33,500
Collar 10/1/98 12/31/98 $ 2.05 - $2.60 5,000 10,550
Collar 10/1/98 12/31/98 $ 2.20 - $2.65 5,000 102,375
Swap 3/1/99 10/31/99 $1.957 13,000 $(1,096,580)
Swap 5/1/99 9/15/99 $2.145 3,000 (154,124)
Swap 11/1/99 12/31/99 $3.000 3,000 80,070
Swap 12/1/99 12/31/99 $3.000 3,000 82,770 -- --
----------- -------- -------
Total $(1,087,864) $481,525 $33,150
=========== ======== =======
</TABLE>
F-12
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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 revenues for the three years ended December
31, 1999 was approximately $(1.1) million, $482,000, and $33,000 respectively,
representing net (losses) and net gains from hedging activity. During December
1999, the Company entered into a crude oil fixed price swap. The number of
barrels of oil per day ("BOD") and the related fixed price subject to the oil
price swap are as follows: i) January 1, 2000 - March 31, 2000, 150 BOD, swap at
$25.60, ii) April 1, 2000 - June 30, 2000, 125 BOD, swap at $22.87, iii) July 1,
2000 - September 30, 2000, 60 BOD, swap at $21.47, and iv) October 1, 2000 -
December 31, 2000, 50 BOD, swap at $ 20.46. At December 31, 1999 and 1998, the
fair value of outstanding hedges was approximately $15,000 and $(292,000),
respectively. Subsequent to December 31, 1999, the Company entered into three
natural gas collars. The natural gas collars cover the following MMbtu per day
and floor and ceiling per MMbtu prices: i) February 1, 2000 - February 29, 2000,
6,000 MMbtu per day, $2.20 floor - $2.31 ceiling, ii) March 1, 2000 - April 30,
2000, 6,000 MMbtu per day, $2.20 floor - $2.50 ceiling and iii) May 1, 2000 -
September 30, 2000, 9,000 MMbtu per day, $2.05 floor - $2.63 ceiling.
5. COMMITMENTS AND CONTINGENCIES
From time to time, the Company is party to certain lawsuits and claims
arising in the ordinary course of business. While the outcome of lawsuits and
claims cannot be predicted with certainty, management does not expect these
matters to have a materially adverse effect on the Company's financial
condition, results of operations or cash flows. The Company is not currently a
party to any litigation that it believes could have a material adverse effect on
the financial position of the Company.
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, 1999, the Company was obligated under noncancelable
operating leases. Following is a schedule of the remaining future minimum lease
payments under these lease:
2000 $283,969
2001 283,969
2002 283,969
2003 60,671
2004 16,012
--------
Total $928,590
========
Rent expense for the years ended December 31, 1999, 1998 and 1997 was
$511,270, $478,652, and $214,143, 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.
F-13
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Significant components of the Company's deferred tax liabilities and
assets as of December 31, 1999 and 1998 are as follows:
1999 1998
----------- -----------
Deferred tax liability:
Book basis of oil and natural
gas properties in excess of
tax basis $(2,522,052) $(2,633,825)
Deferred tax asset:
Other charge not currently
deductible for tax purposes 186,585 792,708
Net operating loss carryforwards 9,069,999 7,142,358
Statutory depletion carryforward 140,390
Other misc. 142,056 146,630
Valuation allowance (6,876,588) (5,588,261)
----------- -----------
Total deferred tax asset 2,522,052 2,633,825
----------- -----------
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:
1999 1998 1997
---------- ---------- ----------
Statutory federal income taxes $(1,298,318) $(5,595,527) $1,338,753
Permanent differences:
Expense not deductible for tax
purposes 9,991 7,266 10,483
Income not taxable to the
company (66,961)
Temporary differences:
Non-Statutory stock options (224,617)
Cumulative effect of accounting
change (958,910)
Other (24,056)
Change in valuation allowance 1,288,327 5,588,261 (1,057,658)
---------- ---------- ----------
Income tax (benefit) expense $ -- $ (982,966) $ --
========== ========== ==========
At December 31. 1999, the Company had cumulative net operating loss
carryforwards ("NOL") for federal income tax purposes of approximately $25.3
million which 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.
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, 1999, 1998 and 1997 the
Company contributed $81,990, $68,869 and $40,954, respectively, to the Plan.
8. EQUITY AND STOCK PLANS
EQUITY OFFERINGS - On March 3, 1997 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
F-14
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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, 1999. 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.
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 ("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 335,866 shares were available for future grants at
December 31, 1999 (these shares include only those issued under the Incentive
Plan). 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 or achievement of certain performance
milestones. During 1999, 1998 and 1997, 4,809, 12,025 and 250,586 shares,
respectively, of restricted stock were awarded having a market value of $6.13,
$12.38 and $16.50, 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.
Effective May 21, 1999, the Company amended and restated the Incentive
Plan. In conjunction with those and other amendments of the Incentive Plan, the
Company exchanged, on a voluntary basis, 556,488 outstanding Nonqualified Stock
options of certain employees and Directors of the Company for 326,700 new common
stock options in replacement of those options. The exercise price of the
replacement options was $7.06, which represents the fair market value on the
date of grant. The replaced options have a ten-year term with 50% of the options
vesting immediately on the date of grant with the remaining 50% vesting on May
21, 2000. On May 21, 1999, 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
vesting 100% on June 1, 2001.
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, and 66,666 options exercisable, during 1999 in
the table below.
In addition, as of the date of the Combination, Old Edge had in place a
stock incentive plan which 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. These amounts are included within options granted
during 1997 in the table below. Of these shares 48,922 were exercised during
1997 and 48,922 remain outstanding at December 31, 1999, 1998 and 1997.
F-15
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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, 1999, 1998 and 1997 was
$349,623, $621,191 and $513,393, 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 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, 1999 is presented below:
<TABLE>
<CAPTION>
1999 1998 1997
--------------------------- -------------------------- --------------------------
WEIGHTED AVG. WEIGHTED AVG. WEIGHTED AVG.
SHARES EXERCISE PRICE SHARES EXERCISE PRICE SHARES EXERCISE PRICE
-------- --------------- ------- --------------- ------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Outstanding, January 1 739,055 $ 15.17 706,365 $ 15.63
Granted 320,800 $ 5.30 107,600 $ 12.76 783,040 $ 14.80
Reissued/repriced 326,700 $ 7.06
Recalled (556,488) $ 15.84
Forfeited (11,500) $ 7.06 (74,910) $ 16.01 (27,753) $ 16.50
Exercised (48,922) $ 2.04
-------- ------- -------
Outstanding, December 31 818,567 $ 7.74 739,055 $ 15.17 706,365 $ 15.63
======== ======= =======
Exercisable, December 31 409,783 $ 9.32 272,785 $ 14.27 48,922 $ 4.09
======== ======= =======
</TABLE>
A summary of the of the Company's stock options categorized by class of
grant at December 31, 1999 is presented below:
<TABLE>
<CAPTION>
ALL OPTIONS OPTIONS EXERCISABLE
- ---------------------------------------------------------------- -----------------------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
RANGE OF SHARES REMAINING EXERCISE RANGE OF SHARES EXERCISE
EXERCISE PRICE OUTSTANDING CONTRACTUAL LIFE PRICE EXERCISE PRICE OUTSTANDING PRICE
- -------------- ----------- --------------- -------- -------------- ----------- --------
<S> <C> <C> <C> <C> <C> <C>
$4.09 - $4.22 248,922 8.64 $ 4.19 $4.09 - $4.22 115,588 $ 4.17
$7.06 - $7.28 436,800 9.41 $ 7.07 $7.06 - $7.28 160,550 $ 7.06
$16.50 133,645 7.17 $16.50 $16.50 133,645 $16.50
</TABLE>
F-16
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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, 1999, 1998
and 1997 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 based on the
following assumptions for the years ended December 31, 1999, 1998 and 1997:
expected volatility based on historical volatility of daily Common Stock Prices
(70%, 53% and 41%, 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 both 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, 1999, 1998 and 1997.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1999 1998 1997
------------- -------------- -------------
<S> <C> <C> <C>
Net income (loss):
As reported $ (3,709,480) $ (13,223,419) $ 3,825,009
============= ============== =============
Pro forma $ (4,186,567) $ (13,743,611) $ 3,454,671
============= ============== =============
As Reported:
Basic earnings (loss) per share:
Net income (loss) before
cumulative effect of
accounting change $ (0.43) $ (1.93) $ 0.53
Cumulative effect of accounting
change -- 0.23 --
------------- -------------- -------------
Basic earnings (loss) per share $ (0.43) $ (1.70) $ 0.53
============= ============== =============
Diluted earnings (loss) per share:
Net income (loss) before
cumulative effect of
accounting change $ (0.43) $ (1.93) $ 0.52
Cumulative effect of accounting
change -- 0.23 --
------------- -------------- -------------
Diluted earnings (loss) per
share $ (0.43) $ (1.70) $ 0.52
============= ============== =============
Pro forma:
Basic earnings (loss) per share:
Net income (loss) before
cumulative effect of
accounting change $ (0.49) $ (2.00) $ 0.47
Cumulative effect of accounting
change -- 0.23 --
------------- -------------- -------------
Basic earnings (loss) per share $ (0.49) $ (1.77) $ 0.47
============= ============== =============
Diluted earnings (loss) per share:
Net income (loss) before
cumulative effect of
accounting change $ 0.49 $ (2.00) $ 0.47
Cumulative effect of accounting
change -- 0.23 --
------------- -------------- -------------
Diluted earnings (loss) per
share $ (0.49) $ (1.77) $ 0.47
============= ============== =============
</TABLE>
F-17
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
COMPUTATION OF EARNINGS PER SHARE - The following is presented as a
reconciliation of the numerators and denominators of basic and diluted earnings
per share computations, in accordance with SFAS No. 128.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
-----------------------------------------
INCOME SHARES PER-SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
----------- ------------- ---------
<S> <C> <C> <C>
BASIC EPS
Income available to common
stockholders $ 3,825,009 7,274,617 $ 0.53
EFFECT OF DILUTIVE SECURITIES
Common stock options -- 45,783 (0.01)
----------- ------------- ---------
DILUTED EPS
Income available to common
stockholders $ 3,825,009 7,320,400 $ 0.52
=========== ============= =========
</TABLE>
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. For the years ended December 31, 1999, 1998
and 1997, the Company recorded management fees totaling $52,560, $120,000 and
$120,000, respectively, and have recorded these amounts as a reduction of
general and administrative expenses. In addition, these agreements stipulate
that the Company is 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
and 1997 amounted to $3,074 and $61,746, respectively. At December 31, 1999 and
1998, the Company had a receivable from the Essex Joint Ventures of $58,651 and
$167,971, 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.
F-18
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
10. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED):
<TABLE>
<CAPTION>
4TH 3RD 2ND 1ST
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
<S> <C> <C> <C> <C>
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
1999
Oil and natural gas revenues $ 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 and (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)
1998
Oil and natural gas revenues $ 3,847 $3,981 $3,849 $3,786
Operating expenses 19,865 4,538 3,812 3,279
Operating income (loss) (16,017) (556) 37 506
Other income and (expense), net (44) (3) 44 46
Income tax (expense) benefit 1,020 191 (34) (194)
Net income (loss) (13,260) (368) 47 358
Basic earnings (loss) per share:
Net income (loss) before
cumulative effect of
accounting change $ (1.71) $(0.05) $ 0.01 $ 0.05
Cumulative effect of
accounting change 0.23
Basic earnings (loss) per
share (1.71) (0.05) 0.01 0.28
Diluted earnings (loss) per
share:
Net income (loss) before
cumulative effect of
accounting change $ (1.71) $(0.05) $ 0.01 $ 0.05
Cumulative effect of
accounting change 0.23
Diluted earnings (loss) per
share: (1.71) (0.05) 0.01 0.28
</TABLE>
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,
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).
F-19
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
11. 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."
CAPITALIZED COSTS (Y) 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,
----------------------------
1999 1998
----------- -----------
Developed oil and natural gas
properties $58,981,484 $48,441,741
Undeveloped oil and natural gas
properties 17,930,027 21,388,831
Accumulated depletion, depreciation
and amortization (33,521,520) (25,708,987)
----------- -----------
Net capitalized cost $43,389,991 $44,121,585
=========== ===========
COSTS INCURRED (Y) Costs incurred in oil and natural gas property
acquisition, exploration and development activities are summarized below:
YEAR ENDED DECEMBER 31,
--------------------------------------
1999 1998 1997
----------- ----------- -----------
Acquisition Cost:
Unproved projects and prospects $ 7,691,947 $20,852,838 $17,659,706
Exploration costs 3,334,836 10,236,188 8,640,530
Development costs 3,455,493 3,249,492 1,207,771
----------- ----------- -----------
Gross costs incurred 14,482,276 34,338,518 27,508,007
Less proceeds from the sales of
prospects 3,471,247 6,951,673 2,325,418
----------- ----------- -----------
Net cost incurred $11,011,029 $27,386,845 $25,182,589
=========== =========== ===========
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,
---------------------------------------
1999 1998 1997
----------- ----------- -----------
Oil and natural gas revenues $14,485,995 $15,463,432 $13,468,042
Operating expenses:
Oil and natural gas operating
expenses and ad valorem taxes 1,954,058 2,438,553 1,459,291
Production taxes 1,085,012 937,206 871,357
Depletion, depreciation and
amortization 7,812,533 9,254,412 2,483,539
Impairment of oil and natural
gas properties 10,012,989
----------- ----------- -----------
Results of operations $ 3,634,392 $(7,179,728) $ 8,653,855
=========== =========== ===========
F-20
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
RESERVES (-) Proved reserves are estimated quantities of oil and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods. Proved oil and natural gas reserve quantities
and the related discounted future net cash flows before income taxes (see
Standardized Measure) for the periods presented are based on estimates prepared
by Ryder Scott Company, independent petroleum engineers. Such estimates have
been prepared in accordance with guidelines established by the Securities and
Exchange Commission.
The Company's net ownership 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,
----------------------------------------
1999 1998 1997
------------ ------------ ------------
Proved developed and undeveloped
reserves
Beginning of year 24,235,000 29,123,000 13,417,000
Revisions of previous estimates (5,011,534) (6,834,982) (5,397,141)
Extensions and discoveries 8,519,618 8,231,477 25,402,000
Sales of natural gas properties (1,306,146)
Production (5,675,938) (6,284,495) (4,298,859)
------------ ------------ ------------
End of Year 20,761,000 24,235,000 29,123,000
============ ============ ============
Proved developed reserves at year end 15,084,000 15,844,000 17,866,000
============ ============ ============
OIL, CONDENSATE AND NATURAL GAS
LIQUIDS
(BBLS)
YEAR ENDED DECEMBER 31,
----------------------------------
1999 1998 1997
---------- ---------- ----------
Proved developed and undeveloped
reserves
Beginning of year 444,813 866,186 642,714
Revisions of previous estimates 150,207 (401,003) (147,917)
Extensions and discoveries 309,246 121,404 537,029
Sales of oil properties (15,661)
Production (187,223) (141,774) (165,640)
---------- ---------- ----------
End of Year 701,382 444,813 866,186
========== ========== ==========
Proved developed reserves at year end 577,775 308,347 646,009
========== ========== ==========
STANDARDIZED MEASURE (Y) 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, 1999 is
shown below:
YEAR ENDED DECEMBER 31,
---------------------------------------
1999 1998 1997
----------- ----------- -----------
Future cash inflows $64,112,983 $49,444,900 $83,454,087
Future oil and natural gas operating
expenses (13,055,050) (11,718,097) (16,228,391)
Future development costs (3,170,357) (3,297,539) (5,957,039)
Future income tax expenses (16,575,185)
----------- ----------- -----------
Future net cash flows 47,887,576 34,429,264 44,693,472
10% discount factor (13,826,224) (11,699,510) (13,450,819)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows $34,061,352 $22,729,754 $31,242,653
=========== =========== ===========
F-21
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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.
CHANGES IN STANDARDIZED MEASURE (Y) Changes in Standardized Measure of
Discounted Future Net Cash Flows relating to proved oil and gas reserves are
summarized below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
Changes due to current year operations:
Sales of oil and natural gas, net of
oil and natural gas operating
expenses $(11,446,925) $(12,087,673) $(11,137,394)
Sales of oil and natural gas
properties (1,439,355)
Extensions and discoveries 16,483,064 6,417,976 34,003,639
Changes dues to revisions in
standardized variables:
Prices and operating expenses 10,947,292 (9,163,029) (15,703,096)
Revisions of previous quantity
estimates (5,903,857) (9,612,849) (8,897,696)
Estimated future development costs 164,412 2,659,500 (4,974,436)
Income taxes 9,645,975 3,116,093
Accretion of discount 2,272,975 4,088,863 3,942,563
Production rates (timing) and other 224,021 (461,662) 692,811
------------ ------------ ------------
Net change 11,301,627 (8,512,899) 1,042,484
Beginning of year 22,729,754 31,242,653 30,200,169
------------ ------------ ------------
End of year $ 34,061,352 $ 22,729,754 $ 31,242,653
============ ============ ============
</TABLE>
Sales of oil and natural gas, net of oil and natural gas operating
expenses are based on historical pre-tax results. Sales of oil and 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-22
EXHIBIT 10.18
December 17, 1999
Mr. James D. Calaway
Edge Petroleum Corporation
1111 Bagby, Suite 2100
Houston, Texas 77002
Dear James:
In connection with your separation from Edge Petroleum Corporation
(Company) and in consideration of your service to the Company, the Company
agrees to the terms, conditions and mutual undertakings contained in this Letter
Agreement concerning your election to resign from employment effective as of
January 3, 2000.
1. CASH COMPENSATION AND MEDICAL AND DENTAL COVERAGE
A. CASH COMPENSATION
As soon as reasonably practical after December 17, 1999, but not before
January 3, 2000, provided the payment is seven days after you execute and
return this Letter Agreement to the Company, the Company will pay you a
lump sum amount equal to the sum of (i) $200,000 plus (ii) $17,692.31
representing accrued unused vacation pay for the calendar year 2000. Such
lump sum payment will be subject to all applicable federal and FICA
withholding taxes. In addition any amounts owing to the Company at the
time of such payment shall be netted from such final lump sum amount.
Commencing on the last business day of January, 2000 and thereafter on the
last business day of each succeeding calendar month in 2000 the Company
shall pay you an amount equal to 1/12 (one twelfth) of $150,000 or
$12,500. Such payment shall be subject to all applicable federal and FICA
withholding taxes.
B. MEDICAL AND DENTAL
Beginning January 2000 and continuing for thirty-six (36) months
thereafter, the Company will pay on your behalf the medical and dental
insurance coverage for Elaine Calaway under the terms of the Company's
medical and dental plans available to you on December 31, 1999, pursuant
to COBRA. The cost of such coverage is $235.91 per month or $8,492.76 in
total over the 36-month term. Also, beginning January 2000, continuing for
eighteen (18) months, the Company will pay on your behalf the medical and
dental insurance for yourself and your children (Caroline and Katherine)
under the terms of the Company's medical and dental plans available to you
on December 31, 1999 pursuant to COBRA. The cost of said coverage is
$480.21 per month before your required employee dependent care
contribution amount of $61.08 per month. The Company will pay the full
coverage amount on your behalf and deduct your required contribution for
dependent care coverage of $61.08 for 18 months, or $1,099.44, from the
lump sum cash compensation amount, paragraph 1.(a)(i) above. For the
eighteen (18) following months, for which COBRA is not available, the
Company will pay to you monthly beginning the last business day of January
2000 and thereafter on the last business day of each succeeding month in
2000 an amount equal to one-twelfth (1/12) of the sum of (i) $419.13 times
18 or $7,544.34 plus (ii) a tax gross-up of 28% or $2,112.42 plus (iii)
$5,343.24 for a total of $15,000. Thus, the total monthly payment to you
<PAGE>
(including the monthly amount in paragraph 1.(a) above) during 2000 before
any applicable taxes, would be 1/12 of $165,000 or $13,750.
2. LIFE INSURANCE AND AD&D
Your term life insurance coverage of $2,000,000 will continue to be paid by the
Company until January 3, 2003. The premiums for such coverage are $3,155 per
year and the Company will also pay any increases in such premiums during such
period.
You will have a 31-day period after January 3, 2000, to exercise the conversion
options for your group life insurance and AD&D, according to the terms and
conditions in effect at that time. It will be your responsibility and at your
expense to complete the conversion process if you so desire.
3. STD/LTD
Short-term and long-term disability coverage is not in effect after your
separation date of January 3, 2000.
4. STOCK OPTIONS
All of the Company stock options you hold as of December 17, 1999 (options on
116,940 shares of Company stock) will be converted effective January 3, 2000, to
70,200 new options exercisable at $7.0625 per share which options will vest
one-half on June 1, 1999 and one-half on January 3, 2000. All such vested
options (together with the old options you hold covering 48,922 shares at an
exercise price of $4.09) to the extent not theretofore exercised, will remain
exercisable following December 16, 1999 as if you had continued in employment
until the expiration of the applicable 10-year term of the options.
5. RESTRICTED STOCK AWARD
93,552 shares of presently unvested Restricted Stock granted to you by the
Company pursuant to Section 2(b)(x) of your Employment Agreement (hereinafter
defined) with the Company shall be fully vested and non-forfeitable as of
January 3, 2003. You will be responsible for remitting to the Company by
certified or cashier's check contemporaneous with receipt by you of the payment
in paragraph 1.(a)(i) and (ii) above, the applicable FICA and withholding taxes
due (29.45% federal withholding rate) by reason of the vesting of such
Restricted Stock. Should you fail to make such payment, you authorize the
Company to withhold same from any amounts due you under this Letter Agreement,
and such Restricted Stock will remain unvested until the withholding and FICA
taxes are collected from you.
6. REIMBURSEMENT OF CERTAIN EXPENSES CHARGED TO COMPANY
Prior to December 31, 1999, you shall reimburse the Company all cash advances
and expenses charged to the Company relating to your recent trip abroad in
connection with your board membership on Frontera Corporation, as well as all
charges for any personal and vacation-related expenses charged to the Company
while on such trip or otherwise. Should you fail to make such payments, you
hereby authorize the Company to withhold same, plus any other amounts you may
owe the Company, from amounts due you under this Letter Agreement.
7. REIMBURSEMENT OF ESSEX II
Prior to December 31, 1999, you shall reimburse Essex Royalty Joint Venture II
$4,800 relating to certain overpayments made to you on the Paris and Corsica
Prospect in connection with ORRI's you sold to Essex Royalty Joint Venture II in
such prospects. The Company is the managing partner of Essex Royalty Joint
Venture II and has a fiduciary duty to collect the amount owed on behalf of the
joint venture. Should you fail to make such payments, you hereby authorize the
Company to withhold same from amounts due you under this Letter Agreement.
8. PAYMENT OF JOINT INTEREST BILLINGS
<PAGE>
Prior to December 31, 1999, you shall pay the Company all outstanding JIB
amounts owed by you or KCP Interests Inc. Should you fail to make such payments,
you hereby authorize the Company to withhold same from amounts due you under
this Letter Agreement. The Company reserves the right to net any future JIB's
against amounts owed you if such JIB's are not timely paid .
9. 1999 BONUS
As soon as practical after the end of 1999 you will be paid a bonus, if any,
based on the Company's determinations of its performance based on the
performance criteria discussed in the employee-wide meeting on May 21, 1999,
with a bonus range of -0- to 90%, with a targeted bonus of 45%, as determined by
the Chairman & CEO.
10. EXPENSE REPORT
Any remaining corporate expenses incurred by you that have not been reimbursed
must be turned in using the standard Company Travel and Entertainment Expense
Form no later than December 31, 1999 in order to be considered for
reimbursement. There shall be no usage of your Corporate American Express credit
card from the date of signing this agreement forward.
In consideration of the Company's agreement to provide the benefits,
payments, and other items described above, the receipt and sufficiency of which
are hereby acknowledged:
(a) You hereby release and forever discharge the Company and its
parents, subsidiaries and affiliates, and their officers, directors,
agents, servants, employees, consultants, attorneys,
representatives, successors, assigns, and insurers from any and all
damage, losses, causes of action, expenses, demands, liabilities,
and claims on behalf of yourself, your heirs, executors,
administrators, and assigns with respect to all matters relating to
the Company or your employment with the Company and you hereby
accept the cash payments, benefits, and other items described herein
in full settlement of all such damages, losses, causes of action,
expenses, demands, liabilities, and claims you now have or may have
with respect to such matters; provided, however, that,
notwithstanding the foregoing release and discharge, you shall
retain all rights to (1) coverage, if any, under directors' or
officers' fiduciary errors and omissions and other liability
insurance policies that by their terms would apply to your acts or
omissions while serving the Company, its subsidiaries and affiliates
and their respective officers, directors, agents, servants,
employees, consultants, attorneys, representatives, successors and
assigns, (ii) you and your dependents rights to payment, coverage,
benefits and other protections in the Company's medical and dental
plans as set forth herein, (iii) your rights under the Company's
Employees' Savings and Profit Sharing (401K) Plan Trust, and (iv)
your rights under this Agreement.
This release includes, but is not limited to, claims arising
under the Age Discrimination in Employment Act, the Older Workers'
Benefit Protection Act, Title VII of the Civil Rights Acts of 1964,
the Americans with Disabilities Act, the Family and Medical Leave
Act, the Texas Labor Code, any state or federal statue, regulation
or common law pertaining to "whistleblowers," any claims for breach
of contract, tort or personal injury of any sort, and any claim
under any other state or federal statute or regulation, in equity or
at common law. Further, by accepting the payments described in this
Agreement, you agree not to sue the Company or the related persons
and entities described above on account of any matters released
hereby. You affirm and agree that your employment relationship has
ended on your separation date, January 3, 2000, and you withdraw
unequivocally, completely, and finally from your employment, you
resign all positions, titles, responsibilities, and authority as an
officer, director or employee of the Company and its affiliates, and
waive all rights in connection with such relationship except to
vested benefits and the payments and benefits described in this
Agreement. You agree that you will not seek and are not eligible for
re-employment with the Company. You agree that this Agreement is
valid, fair, adequate and reasonable, was with your full knowledge
and consent, and was not procured through fraud, duress, or mistake.
You shall have forty-five days to decide whether to sign the
Agreement and be bound by its terms. You shall have the right to
revoke or cancel it within seven days after you have signed it. This
cancellation or revocation can be accomplished by delivery of
<PAGE>
a written notification to me. In the event that this Agreement is
canceled or revoked, the Company shall have no obligation to furnish
the payments and benefits described, except for any rights under the
Company's Savings and Investment (401K) Plan, stock option plans,
and other benefit plans that are vested as of your separation date,
January 3, 2000, and the Employment Agreement (defined below) will
remain in effect. Notwithstanding the revocation letter, your
termination of employment shall nevertheless remain effective,
including your resignation as both a member of the Company's Board
of Directors and an officer of the Company or its affiliates. You
acknowledge that you have been advised in writing to consult with an
attorney prior to signing this Agreement and have had an adequate
opportunity to seek advice of your own choosing. You acknowledge
that you have read this Agreement, have had an opportunity to ask
questions and have it explained to you and that you understand that
this Agreement will have the effect of knowingly and voluntarily
waiving and releasing any action you might pursue, including breach
of contract, personal injury, retaliation, discrimination on the
basis of race, age, sex, national origin, or disability and any
other claims arising prior to the date of this Agreement, including
any claims under the Employment Agreement between the Company and
you dated as of February 25, 1997 (Employment Agreement).
(b) You agree to hold for the benefit of the Company all secret or
confidential information or data relating to the Company or any of
its affiliates, and their respective businesses, which shall have
been obtained by you during your employment by the Company or any of
its affiliates and which shall not be or become public knowledge
(other than acts by you or representatives of you in violation of
this Agreement or the other terms and conditions of your employment
by the Company). You agree that you will not, without the prior
written consent of the Company or as may be otherwise required by
law or legal process, communicate or divulge any such secret or
confidential information or data relating to the Company or any of
its affiliates and their respective businesses to anyone other than
the Company and those designated by it.
(c) You hereby agree for the period commencing January 3, 2000 and ending June
30, 2000 you will provide to the Company your best reasonable efforts as
an independent contractor and not as an employee to cause to sell the
Company's stock ownership in Frontera Corporation. The minimum price the
Company will accept for such stock is $3.9mm cash. As compensation for
your services in selling such stock, you will receive a commission based
on the excess of the sale price over $3.9 mm, as follows:
25% of excess over $3.9mm up to $4.0mm
30% of amount between $4,000,001 and $4,500,000
40% of amount over $4,500,001
(There will be no commission if the sale price is $3.9mm or
less.)
You will be responsible for paying for any travel or other business
expenses related to your efforts to sell such stock, and the Company will not
reimburse you for same. This arrangement shall be on an exclusive basis with you
through March 1, 2000 so that regardless of whether the Company's stock in
Frontera is sold through your efforts or the Company's efforts, you will receive
the commission compensation stated above as long as such stock is sold or an
arrangement to sell such stock is entered into prior to March 1, 2000. After
March 1, 2000 this arrangement shall no longer be exclusive, and the Company
shall be free to make other arrangements to sell such stock without owing you a
commission, except that if the Company consummates a sale with a potential buyer
who you contacted prior to June 30, 2000 and with respect to whom you advised
the Company in writing prior to June 30, 2000, you shall nevertheless be
entitled to receive the above commission, if any, based on the closing price of
such sale.
The purpose of the arrangements described in this Agreement is to arrive
at a mutually agreeable and amicable basis upon which to separate your
employment with the Company. You and the Company agree to refrain from any
criticisms or disparaging comments about each other or in any way relating to
your employment with or separation from the Company, except in the context of
any disclosure or examination necessary in connection with the enforcement of
your rights under this Agreement or as may be required by law or judicial
process. Furthermore,
<PAGE>
you agree that you have returned or will return immediately, any proprietary or
confidential information or documents relating to the business and affairs of
the Company and its affiliates, together with all Company property, including
office keys, security cards, building/garage passes and corporate American
Express card.
You further agree that the existence and all terms of this Agreement shall
be kept strictly confidential and that any disclosure to anyone for any purpose
whatsoever (save and except disclosure to your spouse, to financial institutions
as part of a financial statement, to immediate family members and/or heirs, to
financial, tax and legal advisors, disclosure necessary in connection with the
enforcement of your rights under this Agreement or as may be required by law,
regulation or judicial process; in the event confirmation of any such
information is requested, the request should be directed to the chief financial
officer of the Company) by you or your agents, representatives, heirs, children,
spouse, employees or spokespersons shall be a breach of this Agreement. In the
event that either party feels that the other has breached any provision of this
Agreement or the attachment, that party shall give the other written notice and
the parties shall endeavor in good faith for not less than 20 days after such
notice to resolve the alleged breach prior to exercising or seeking any other
remedy.
This agreement constitutes the entire agreement between the parties hereto
with respect to the subject hereof and shall supersede any prior agreements,
negotiations or undertakings between the parties hereto, whether written or
oral, relating to the subject hereof. Furthermore, this Agreement represents,
collectively, the final Agreement among the parties thereto and may not be
contradicted by evidence of prior, contemporaneous, or subsequent oral
agreements of such parties. There are no unwritten oral agreements among such
parties.
By signing in the space below, you and the Company evidence your consent
and agreement to all of the terms and conditions hereof.
Very truly yours,
John W. Elias
Chairman & CEO of
Edge Petroleum Corporation
AGREED TO AND ACCEPTED
this _____ day of December, 1999.
_______________________________
James D. Calaway
EXHIBIT 21.1
SUBSIDIARIES OF THE COMPANY
Edge Petroleum Exploration Company (a Delaware corporation)
Edge Petroleum Operating Company, Inc. (a Texas corporation)
EXHIBIT 23.1
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in Registration Statement No.
333-22571 of Edge Petroleum on Form S-8 of our report dated February 18, 2000,
appearing in the Annual Report on Form 10-K of Edge Petroleum Corporation for
the year ended December 31, 1999.
/S/ Deloitte & Touche LLP
Houston, Texas
March 20, 2000
EXHIBIT 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the incorporation by reference in Edge Petroleum
Corporation's previously filed Registration Statement on Form S-8 No. 22571 of
our summary report dated February 15, 2000 included as Exhibit 99.1 to this
Annual Report on Form 10-K and the data extracted from our reports and the
references to our firm appearing in "Items 1 and 2. "Business and Properties"
under the caption "Oil and Natural Gas Reserves" and in Supplemental Financial
Information on Oil and Natural Gas Exploration, Development and Production
Activities (unaudited) in such Annual Report on Form 10-K.
/S/ RYDER SCOTT COMPANY
PETROLEUM ENGINEER...
---------------------------
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
March 20, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 577,864
<SECURITIES> 0
<RECEIVABLES> 4,667,264
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 5,466,637
<PP&E> 81,967,669
<DEPRECIATION> (35,991,662)
<TOTAL-ASSETS> 55,317,665
<CURRENT-LIABILITIES> 10,444,058
<BONDS> 2,700,000
0
0
<COMMON> 91,820
<OTHER-SE> 42,081,787
<TOTAL-LIABILITY-AND-EQUITY> 55,317,665
<SALES> 0
<TOTAL-REVENUES> 14,485,995
<CGS> 0
<TOTAL-COSTS> 18,117,263
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 130,067
<INCOME-PRETAX> (3,709,480)
<INCOME-TAX> 0
<INCOME-CONTINUING> (3,709,480)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (3,709,480)
<EPS-BASIC> (0.43)
<EPS-DILUTED> (0.43)
</TABLE>
EXHIBIT 99.1
February 15, 2000
Edge Petroleum Corporation
2100 Texaco Heritage Plaza
Houston, Texas 77002
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold and royalty interests
of Edge Petroleum Corporation (Edge) as of December 31, 1999. The subject
properties are located in the states of Alabama, Louisiana, Mississippi, and
Texas. The income data were estimated using the Securities and Exchange
Commission (SEC) guidelines for future price and cost parameters.
The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. December 1999 hydrocarbon prices were used in
the preparation of this report as required by SEC guidelines; however, actual
future prices may vary significantly from December 1999 prices. Therefore,
volumes of reserves actually recovered and amounts of income actually received
may differ significantly from the estimated quantities presented in this report.
The results of this study are summarized below.
SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
EDGE PETROLEUM CORPORATION
As of December 31, 1999
-------------------------------------------------------------
<TABLE>
<CAPTION>
PROVED
----------------------------------------------------------
DEVELOPED
---------------------------- TOTAL
PRODUCING NON-PRODUCING UNDEVELOPED PROVED
----------- -------------- ------------ -----------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate - 173,821 187,833 72,855 434,509
Plant Products - 110,300 105,821 50,752 266,873
Gas - MMCF 6,680 8,404 5,677 20,761
INCOME DATA
Future Gross Revenue $20,005,796 $24,491,354 $15,056,721 $59,553,871
Deductions 3,537,946
----------- -------------- ------------ -----------
Future Net Income $15,559,807 $20,953,408 $11,374,361 $47,887,576
Discounted FNI @ 10% $12,544,092 $13,983,962 $7,533,298 $34,061,352
</TABLE>
<PAGE>
Edge Petroleum Corporation
February 15, 2000
Page 2
PROBABLE
----------------------------------------------------
DEVELOPED TOTAL
--------------------------
PRODUCING NON-PRODUCING UNDEVELOPED PROBABLE
---------- ------------- ----------- ----------
NET REMAINING RESERVES
Oil/Condensate -
Barrels 7,039 43,223 10,517 60,779
Plant Products - 17,635 8,467 17,635 43,737
Gas - MMCF 330 173 487 990
INCOME DATA
Future Gross Revenue $1,131,841 $1,509,038 $1,557,321 $4,198,200
Deductions 68,264 309,151 144,964 522,379
---------- ---------- ---------- ----------
Future Net Income (FNI) $1,063,577 $1,199,887 $1,412,357 $3,675,821
Discounted FNI @ 10% $ 420,672 $ 615,261 $ 540,143 $1,576,076
POSSIBLE
-------------------------------------------
DEVELOPED TOTAL
NON-PRODUCING UNDEVELOPED POSSIBLE
---------- -------- ----------
NET REMAINING RESERVES
Oil/Condensate - 22,017 2,514 24,531
Plant Products - 13,521 0 13,521
Gas - MMCF 239 36 275
INCOME DATA
Future Gross Revenue $1,203,378 $130,905 $1,334,283
Deductions 216,446 8,661 225,107
---------- -------- ----------
Future Net Income $ 986,932 $122,244 $1,109,176
Discounted FNI @ 10% $ 378,484 $ 99,477 $ 477,961
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes are sales gas expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas in which the gas reserves are
located.
The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs, and development costs. The future net income
is before the deduction of state and federal income taxes and general
administrative overhead, and has not been adjusted for outstanding loans that
may exist nor does it include any adjustment for cash on hand or undistributed
income. No attempt was made to quantify or otherwise account for any accumulated
gas production imbalances that may exist. Gas reserves account for approximately
78 percent and liquid hydrocarbon reserves account for the remaining 22 percent
of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded monthly. Future net income was
discounted at four other discount rates which were also compounded monthly.
These results are shown on each estimated projection of future production and
income presented in a later section of this report and in summary form below.
<PAGE>
Edge Petroleum Corporation
February 15, 2000
Page 3
DISCOUNTED FUTURE NET INCOME
AS OF DECEMBER 31, 1999
----------------------------------------------
Discount Rate Total Total Total
Percent Proved Probable Possible
------------- ----------- ---------- --------
8 $36,046,605 $1,799,622 $539,132
12 $32,307,866 $1,397,071 $431,282
20 $26,892,683 $ 935,802 $322,800
25 $24,374,416 $ 759,545 $285,552
The results shown above are presented for your information and should not
be construed as our estimate of fair market value.
RESERVES INCLUDED IN THIS REPORT
The PROVED RESERVES included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission Staff Accounting Bulletins. The PROBABLE
RESERVES and POSSIBLE RESERVES included herein conform to definitions of
probable and possible reserves approved by the SPE/WPC using the deterministic
methodology. The definitions of proved, probable, and possible reserves are
included under the tab "Reserve Definitions and Pricing Assumptions" in this
report.
We have included probable and possible reserves and income in this report
at the request of Edge. These data are for Edge's information only and should
not be included in reports to the SEC according to the SEC guidelines. The
probable reserves are less certain to be recovered than the proved reserves and
reserves classified as possible are less certain to be recovered than those in
the probable category. The reserves and income quantities attributable to the
different reserve classifications that are included herein have not been
adjusted to reflect the varying degrees of risk associated with them and thus
are not comparable.
The proved and probable developed non-producing reserves included herein
are comprised of shut-in and behind pipe categories. The possible developed
non-producing reserves included herein are comprised of the behind pipe
category. The various reserve status categories are defined under the tab
"Reserve Definitions and Pricing Assumptions" in this report.
ESTIMATES OF RESERVES
In general, the reserves included herein were estimated by performance
methods or the volumetric method; however, other methods were used in certain
cases where characteristics of the data indicated such other methods were more
appropriate in our opinion. The reserves estimated by the performance method
utilized extrapolations of various historical data in those cases where such
data were definitive. Reserves were estimated by the volumetric method in those
cases where there were inadequate historical performance data to establish a
definitive trend or where the use of production performance data as a basis for
the reserve estimates was considered to be inappropriate.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.
<PAGE>
Edge Petroleum Corporation
February 15, 2000
Page 4
FUTURE PRODUCTION RATES
Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
which are not currently producing. If no production decline trend has been
established, future production rates were held constant, or adjusted for the
effects of curtailment where appropriate, until a decline in ability to produce
was anticipated. An estimated rate of decline was then applied to depletion of
the reserves. If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
Edge.
In general, we estimate that future gas production rates limited by
allowables or marketing conditions will continue to be the same as the average
rate for the latest available 12 months of actual production until such time
that the well or wells are incapable of producing at this rate. The well or
wells were then projected to decline at their decreasing delivery capacity rate.
Our general policy on estimates of future gas production rates is adjusted when
necessary to reflect actual gas market conditions in specific cases.
The future production rates from wells now on production may be more or
less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
HYDROCARBON PRICES
Edge furnished us with prices in effect at December 31, 1999 and these
prices were held constant except for known and determinable escalations. In
accordance with Securities and Exchange Commission guidelines, changes in liquid
and gas prices subsequent to December 31, 1999 were not taken into account in
this report. Future prices used in this report are discussed in more detail
under the tab "Reserve Definitions and Pricing Assumptions" in this report.
COSTS
Operating costs for the leases and wells in this report are based on the
operating expense reports of Edge and include only those costs directly
applicable to the leases or wells. When applicable, the operating costs include
a portion of general and administrative costs allocated directly to the leases
and wells under terms of operating agreements. No deduction was made for
indirect costs such as general administration and overhead expenses, loan
repayments, interest expenses, and exploration and development prepayments that
are not charged directly to the leases or wells.
Development costs were furnished to us by Edge and are based on
authorizations for expenditure for the proposed work or actual costs for similar
projects. The estimated net cost of abandonment after salvage was included for
properties where abandonment costs net of salvage are significant. At the
request of Edge, their estimate of zero abandonment costs after salvage value
for onshore properties was used in this report. Ryder Scott has not performed a
detailed study of the abandonment costs nor the salvage value and makes no
warranty for Edge's estimate.
Current costs were held constant throughout the life of the properties.
<PAGE>
Edge Petroleum Corporation
February 15, 2000
Page 5
GENERAL
Table A presents a one line summary of proved reserve and income data for
each of the subject properties which are ranked according to their future net
income discounted at 10 percent per year. Table B presents a one line summary of
gross and net reserves and income data for each of the subject properties. Table
C presents a one line summary of initial basic data for each of the subject
properties. Tables 1 through 407 present our estimated projection of production
and income by years beginning January 1, 2000, by state, county, field, and
lease or well for fields in existence in the December 31, 1996 report. Prospect
areas drilled between 1997 and the beginning of 1999 are shown next in
alphabetical order and prospect areas drilled in late 1999 are shown at the end
of this report.
While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration in
making this evaluation.
The estimates of reserves presented herein were based upon a detailed study
of the properties in which Edge owns an interest; however, we have not made any
field examination of the properties. No consideration was given in this report
to potential environmental liabilities which may exist nor were any costs
included for potential liability to restore and clean up damages, if any, caused
by past operating practices. Edge has informed us that they have furnished us
all of the accounts, records, geological and engineering data, and reports and
other data required for this investigation. The ownership interests, prices, and
other factual data furnished by Edge were accepted without independent
verification. The estimates presented in this report are based on data available
through December 1999.
Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation is
contingent on our estimates of reserves and future income for the subject
properties.
This report was prepared for the exclusive use and sole benefit of Edge
Petroleum Corporation. The data, work papers, and maps used in this report are
available for examination by authorized parties in our offices. Please contact
us if we can be of further service.
Very truly yours,
/S/ RYDER SCOTT COMPANY, L.P.
Michael F. Stell, P.E.
Vice President
<PAGE>
Edge Petroleum Corporation
February 15, 2000
Page 6
DEFINITIONS OF RESERVES
PROVED RESERVES (SEC DEFINITION)
PROVED RESERVES of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalation based on
future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. In certain instances,
proved reserves are assigned on the basis of a combination of core analysis and
electrical and other type logs which indicate the reservoirs are analogous to
reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir considered
proved includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Proved natural gas reserves are comprised of non-associated, associated
and dissolved gas. An appropriate reduction in gas reserves has been made for
the expected removal of natural gas liquids, for lease and plant fuel, and for
the exclusion of non-hydrocarbon gases if they occur in significant quantities
and are removed prior to sale. Estimates of proved reserves do not include crude
oil, natural gas, or natural gas liquids being held in underground or surface
storage.
Proved reserves are estimates of hydrocarbons to be recovered from a given
date forward. They may be revised as hydrocarbons are produced and additional
data become available.
<PAGE>
Edge Petroleum Corporation
February 15, 2000
Page 7
UNPROVED RESERVES (SPE/WPC DEFINITIONS)
Unproved reserves are based on geologic and/or engineering data similar to
that used in estimates of proved reserves; but technical, contractual, economic,
or regulatory uncertainties preclude such reserves being classified as proved.
Unproved reserves may be further classified as probable reserves and possible
reserves.
Unproved reserves may be estimated assuming future economic conditions
different from those prevailing at the time of the estimate. The effect of
possible future improvements in economic conditions and technological
developments can be expressed by allocating appropriate quantities of reserves
to the probable and possible classifications.
PROBABLE RESERVES
Probable reserves are those unproved reserves which analysis of geological
and engineering data suggests are more likely than not to be recoverable. In
this context, when probabilistic methods are used, there should be at least a 50
percent probability that the quantities actually recovered will equal or exceed
the sum of estimated proved plus probable reserves.
In general, probable reserves may include (1) reserves anticipated to be
proved by normal step-out drilling where sub-surface control is inadequate to
classify these reserves as proved, (2) reserves in formations that appear to be
productive based on well log characteristics but lack core data or definitive
tests and which are not analogous to producing or proved reserves in the area,
(3) incremental reserves attributable to infill drilling that could have been
classified as proved if closer statutory spacing had been approved at the time
of the estimate, (4) reserves attributable to improved recovery methods that
have been established by repeated commercially successful applications when (a)
a project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics appear favorable for commercial application, (5)
reserves in an area of the formation that appears to be separated from the
proved area by faulting and the geologic interpretation indicates the subject
area is structurally higher than the proved area, (6) reserves attributable to a
future workover, treatment, re-treatment, change of equipment, or other
mechanical procedures, where such procedure has not been proved successful in
wells which exhibit similar behavior in analogous reservoirs, and (7)
incremental reserves in proved reservoirs where an alternative interpretation of
performance or volumetric data indicates more reserves than can be classified as
proved.
POSSIBLE RESERVES
Possible reserves are those unproved reserves which analysis of geological
and engineering data suggests are less likely to be recoverable than probable
reserves. In this context, when probabilistic methods are used, there should be
at least a 10 percent probability that the quantities actually recovered will
equal or exceed the sum of estimated proved plus probable plus possible
reserves.
In general, possible reserves may include (1) reserves which, based on
geological interpretations, could possibly exist beyond areas classified as
probable, (2) reserves in formations that appear to be petroleum bearing based
on log and core analysis but may not be productive at commercial rates, (3)
incremental reserves attributed to infill drilling that are subject to technical
uncertainty, (4) reserves attributed to improved recovery methods when (a) a
project or pilot is planned but not in operation and (b) rock, fluid, and
reservoir characteristics are such that a reasonable doubt exists that the
project will be commercial, and (5) reserves in an area of the formation that
appears to be separated from the proved area by faulting and geological
interpretation indicates the subject area is structurally lower than the proved
area.
<PAGE>
Edge Petroleum Corporation
February 15, 2000
Page 8
RESERVE STATUS CATEGORIES (SEC)
Reserve status categories define the development and producing status of
wells and/or reservoirs.
PROVED DEVELOPED
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
Developed reserves may be subcategorized as producing or non-producing
using the SPE/WPC Definitions:
PRODUCING
Reserves sub-categorized as producing are expected to be recovered from
completion intervals which are open and producing at the time of the
estimate. Improved recovery reserves are considered producing only after
the improved recovery project is in operation.
NON-PRODUCING
Reserves sub-categorized as non-producing include shut-in and behind pipe
reserves. Shut-in reserves are expected to be recovered from (1) completion
intervals which are open at the time of the estimate but which have not
started producing, (2) wells which were shut-in for market conditions or
pipeline connections, or (3) wells not capable of production for mechanical
reasons. Behind pipe reserves are expected to be recovered from zones in
existing wells, which will require additional completion work or future
recompletion prior to the start of production.
PROVED UNDEVELOPED
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
reasonable certainty that there is continuity of production from the existing
productive formation. Estimates for proved undeveloped reserves are attributable
to any acreage for which an application of fluid injection or other improved
technique is contemplated, only when such techniques have been proved effective
by actual tests in the area and in the same reservoir.
<PAGE>
HYDROCARBON PRICING PARAMETERS
SECURITIES AND EXCHANGE COMMISSION PARAMETERS
OIL AND CONDENSATE
Edge furnished us with oil and
condensate prices in effect at December 31, 1999 and these prices were held
constant to depletion of the properties. In accordance with Securities and
Exchange Commission guidelines, changes in liquid prices subsequent to December
31, 1999 were not considered in this report.
PLANT PRODUCTS
Edge furnished us with plant
product prices in effect at December 31, 1999 and these prices were held
constant to depletion of the properties.
GAS
Edge furnished us with gas
prices in effect at December 31, 1999 and with its forecasts of future gas
prices which take into account SEC guidelines, current spot market prices,
contract prices, and fixed and determinable price escalations where applicable.
In accordance with SEC guidelines, the future gas prices used in this report
make no allowances for future gas price increases which may occur as a result of
inflation nor do they make any allowance for seasonal variations in gas prices
which may cause future yearly average gas prices to be somewhat lower than
December 31, 1999 gas prices. For gas sold under contract, the contract gas
price including fixed and determinable escalations, exclusive of inflation
adjustments, was used until the contract expires and then was adjusted to the
current market price for the area and held at this adjusted price to depletion
of the reserves.
