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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, 1997
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 20, 1998, was $73,286,256 on a value of $12.00 per
share, the closing price of the Common Stock as quoted by NASDAQ National Market
on such date). 7,760,869 shares of Common Stock, par value $.01 per share, were
outstanding on March 20, 1998.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the registrant's 1998 Annual
Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III of
this report.
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TABLE OF CONTENTS
PAGE
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES 1
ITEM 3. LEGAL PROCEEDINGS 24
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 24
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS 26
ITEM 6. SELECTED FINANCIAL DATA 27
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 28
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT
MARKET RISK 35
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 35
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURES 35
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 35
ITEM 11. EXECUTIVE COMPENSATION 35
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT 35
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 35
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS
ON FORM 8-K 36
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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
236,000 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 largest databases of onshore South Texas Gulf Coast
3-D seismic data of any independent oil and natural gas company, and is
continuously acquiring substantial additional data within this core region.
The Company acquires 3-D seismic data by organizing and designing regional
data acquisition surveys for its proprietary use, as well as through selective
participation in regional non-proprietary 3-D surveys. The Company negotiates
seismic options for a substantial majority of the areas encompassed by its
proprietary surveys, thereby allowing it to secure identified prospect leasehold
interests on a non-competitive, pre-arranged basis. In the Company's non-
proprietary 3-D survey areas, the Company's technical capabilities allow it to
rapidly and comprehensively evaluate large volumes of regional 3-D seismic data,
facilitating its ability to identify attractive prospects within a surveyed
region and to secure the corresponding leasehold interests ahead of other
industry participants.
The Company's extensive technical expertise has enabled it to internally
generate substantially all of its 3-D prospects drilled to date and to assemble
a large portfolio of 3-D based drilling prospects. The Company pursues drilling
opportunities that include a blend of shallower, normally pressured reservoirs
that generally involve moderate costs and risks as well as deeper, over-
pressured reservoirs that generally involve greater costs and risks, but have
higher economic potential. The Company mitigates its exposure to exploration
costs and risk by conducting its operations with industry partners, including
major oil companies and large independents, that generally pay a
disproportionately greater share of seismic acquisition and, in many instances,
leasing and drilling costs than the Company.
The Company has experienced rapid increases in reserves, production and
cash flow since early 1995 due to the growth of its 3-D based drilling
activities and the retention of progressively larger interests in its
exploration projects. The Company's average daily production increased from 2.5
MMcfe in 1995 to 14.5 MMcfe in 1997. While experiencing this rapid growth, the
Company has maintained a low cost structure and has been profitable in each of
the last four years. At December 31, 1997, the Company's estimated proved oil
and natural gas reserves consisted of 29.1 Bcf of natural gas and 866 MBbls of
oil. During 1997, the Company drilled 101 gross wells, (41.44 net wells) and
added proved reserves of 28.6 Bcfe, before oil and natural gas revisions and
production, representing a 540% replacement ratio of 1997 production of 5.3
Bcfe. At December 31, 1997, Edge's estimated proved reserves before income
taxes and discounted to present value at 10% per annum was $40.9 million, based
on weighted average prices at December 31, 1997 of $16.23 per Bbl of oil and
$2.40 per Mcf of natural gas.
EXPLORATION TECHNOLOGY
Since 1992, as a result of the advent of economic onshore 3-D seismic
surveys and the improvement and
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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 collectively
large volumes of information contained within the 3-D seismic data. This
improves the geoscientist's ability to recognize certain important patterns or
attributes in the data which may indicate hydrocarbon traps and which, if viewed
incorrectly or with the application of improper techniques, could go undetected.
Visualization techniques also enable the geoscientist to quickly identify and
prioritize key areas from the large volumes of data reviewed in order to realize
the greatest early benefit. The Company's sophisticated computing resources and
unique visualization and data analysis techniques allow its geoscientists to
more easily identify features such as shallow amplitude anomalies, complex
channel systems, sharp structural details and fluid contacts, which might have
been overlooked using less sophisticated 3-D seismic data interpretation
techniques.
The application of advanced 3-D exploration technology requires large scale
information processing and graphic visualization, made possible by the rapid
improvements in computing technology. The Company has made a significant
investment in its 3-D seismic data visualization technology, which is closely
linked with the Company's well-log database and other geoscience application
software. Additionally, the Company has developed a fully integrated, client-
server environment utilizing 14 scientific workstation nodes. For large scale
visualization, the Company uses a Silicon Graphics Onyx R10000 server with the
SGI Reality Engine-2. The Company uses a comprehensive suite of Landmark
Graphics geoscience applications in its interpretation environment, including
Landmark's EarthCube software, which is designed specifically to integrate
visualization and 3-D geologic interpretation. In addition, the Company
utilizes Cogniseis' Voxel Geo technology in its visualization efforts.
The Company's technological success is dependent in part upon hiring and
retaining highly skilled technical personnel. The Company has assembled a
technical team that it believes has the capacity to adapt to the rapidly
changing technological demands in the field of oil and natural gas exploration.
This team consists of ten 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 increasingly large quantities of data without a
commensurate increase in the number of employees. Additionally, the expertise
of the Company's team of geoscientists reduces its dependence on outside
technical consultants and enables the Company to internally generate
substantially all of its prospects.
EXPLORATION AND OPERATING APPROACH
The Company's exploration approach is to acquire large 3-D seismic data
sets along prolific, producing trends of the onshore Gulf Coast and to utilize
advanced visualization and interpretation techniques to identify or evaluate
prospects and then drill the prospects which it believes provide the potential
for significant returns. The Company typically seeks to explore in areas with
(i) numerous accumulations of normally pressured reserves at shallow depths and
in geologic traps that are difficult to define without the use of advanced 3-D
data visualization and interpretation and (ii) the potential for large
accumulations of deeper, over-pressured reserves. The Company typically sells a
portion of its interest in the deep, over-pressured prospects in order to
mitigate its exploration risk and fund the anticipated capital requirements for
the interests it retains in such prospects, while retaining all or the majority
of its interest in the prospects with normally pressured reservoirs.
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The Company emphasizes preplanning in project development to lower capital
and operational costs and to efficiently integrate potential well locations into
the existing and planned infrastructure, including gathering systems and other
surface facilities. In constructing surface facilities, the Company seeks to
use reliable, high quality, used equipment in place of new equipment to achieve
cost savings. The Company also seeks to minimize cycle time from drilling to
hook-up of wells, thereby accelerating cash flow and improving ultimate project
economics.
An important component of the Company's exploration approach is the
acquisition of large 3-D seismic data sets at the lowest possible cost. The
Company has sought to obtain large 3-D data sets either by participating in
large seismic data acquisition programs through joint venture arrangements with
other energy companies or group shoots in which the Company shares the costs and
results of seismic surveys. The Company believes its technical capabilities
allow it to rapidly evaluate these large 3-D data sets and identify and secure
drilling opportunities prior to the other participants in these group shoots.
In both the joint ventures and the group shoots, the Company's partners have
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 producing oil and
natural gas wells in South Texas, Louisiana and Alabama. These wells range in
depth from 3,000 feet to greater than 14,000 feet.
The Company has developed extensive experience in the development and
management of projects along the Gulf Coast. 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 drilling prospects that may result 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, 1997. 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, 1997. Ryder Scott's estimates were based upon a
review of production histories and other geologic, economic, ownership and
engineering data provided by the Company. In estimating the reserve quantities
that are economically recoverable, Ryder Scott used selling prices and estimated
development and production costs that were in effect during December 1997
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, 1997, see the reserve report included as an exhibit to this
Annual Report on Form 10-K (the "Ryder Scott Report"). The present value of
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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 10 of Notes to Consolidated Financial Statements. See ITEMS 1
AND 2.--BUSINESS AND PROPERTIES--"FORWARD LOOKING INFORMATION AND RISK FACTORS--
Uncertainties of Estimates of Oil and Natural Gas Reserves."
<TABLE>
<CAPTION>
Proved Reserves
-----------------------------------------------
Developed (1) Undeveloped (2) Total
------------- --------------- -----
(Dollars in thousands)
<S> <C> <C> <C>
Oil and condensate (MBbls) (3) 646 220 866
Natural gas (MMcf) 17,866 11,257 29,123
Total MMcfe 21,742 12,578 34,320
Estimated future net revenues before income taxes $ 39,947 $ 21,322 $ 61,269
Present value of estimated future net revenues
before income taxes (discounted 10% annum) (4) $ 27,846 $ 13,043 $ 40,889
</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 weighted average prices at
December 31, 1997, which were $2.40 per Mcf of natural gas and $16.23 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.
In accordance with Commission regulations, the Ryder Scott Report used oil
and natural gas prices in effect at December 31, 1997. 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, 1997. 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.
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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.
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------
1997 1996 1995
-------- ------- -------
<S> <C> <C> <C>
Production:
Oil and Condensate (MBbls) (1) 166 109 64
Natural gas (MMcf) 4,299 2,316 513
Total MMcfe 5,293 2,970 897
Average Sales Price:
Oil and Condensate ($ per Bbl) (1) $ 17.21 $ 19.31 $ 15.96
Natural gas ($ per Mcf) (2) 2.47 2.42 1.99
Average oil and natural gas operating expense ($ per Mcfe) (3) 0.44 0.54 0.77
</TABLE>
________________
(1) Includes plant products.
(2) Includes the effect of hedging activity for the year ended December 31,
1997.
(3) Includes direct lifting costs (labor, repairs and maintenance, materials and
supplies), workover costs and the administrative costs of production
offices, insurance and property and severance taxes.
RESERVE REPLACEMENT
From January 1, 1995 to December 31, 1997, the Company incurred total net
acquisition, exploration and development costs of approximately $44.6 million
and generated proceeds of approximately $8.6 million from the sale of
undeveloped prospects. Total acquisition, exploration, and development
activities from January 1, 1995 to December 31, 1997, resulted in the addition
of approximately 46.2 Bcfe (before downward reserve revisions of approximately
6.3 Bcfe), net to the Company's interest, of proved reserves at an average
reserve replacement cost of $0.43 per Mcfe. 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.
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,
---------------------------------
1997 1996 1995
-------- ------- -------
<S> <C> <C> <C>
Acquisition Cost:
Unproved prospects $ 17,660 $ 4,490 $ 3,659
Proved properties 36 91
Exploration costs 8,640 2,633 2,642
Development costs 1,208 2,343 1,150
-------- ------- -------
Total costs incurred 27,508 9,502 7,542
Less proceeds from sales of prospects 2,325 2,230 4,008
-------- ------- -------
Net costs incurred $ 25,183 $ 7,272 $ 3,534
-------- ------- -------
</TABLE>
Net costs incurred do not reflect sales of proved 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.
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DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company for the
three years ended December 31, 1997. 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,
-----------------------------------------------------------
1997 1996 1995
--------------- --------------- ---------------
GROSS NET GROSS NET GROSS NET
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
EXPLORATORY:
Productive 60 27.07 32 15.82 17 8.66
Non-productive 22 9.68 12 3.76 12 4.64
-- ----- -- ----- -- -----
Total 82 36.75 44 19.58 29 13.30
DEVELOPMENT:
Productive 15 2.82 5 0.20
Non-productive 4 1.87 1 0.20 1 0.10
-- ----- -- ----- -- -----
Total 19 4.69 1 0.20 6 0.30
</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, 1997.
<TABLE>
<CAPTION>
Company Non-
Operated Operated Total
--------------- -------------- ------------------
Gross Net Gross Net Gross (1) Net (1)
----- --- ----- --- --------- ------
<S> <C> <C> <C> <C> <C> <C>
Oil 10 5.55 32 6.34 42 11.89
Natural gas 63 36.34 50 9.25 113 45.59
-- ----- -- ----- --- -----
Total 73 41.89 82 15.59 155 57.48
-- ----- -- ----- --- -----
</TABLE>
_______________
(1) Includes 38 gross wells shut in, (13.13 net).
ACREAGE DATA
The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of December 31, 1997. 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 61,157 20,507 82,970 33,850 144,127 54,357
Louisiana 1,728 584 2,029 1,486 3,757 2,070
Mississippi 2,660 87 3,814 665 6,474 752
Alabama 2,933 158 4,720 715 7,653 873
------ ------ ------ ------ ------- ------
Total 68,478 21,336 93,533 36,716 162,011 58,052
------ ------ ------ ------ ------- ------
</TABLE>
Leases covering approximately 33,713 gross (13,964 net), 17,983 gross (7,978
net), 20,162 gross (11,396 net) and 967 gross (811 net) undeveloped acres are
scheduled to expire in 1998, 1999, 2000 and 2001, 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 91,944 gross (51,336 net) acres that the Company
has a right to acquire pursuant
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to various seismic option agreements at December 31, 1997. 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.
SIGNIFICANT PROJECT AREAS
Set forth below are descriptions of the Company's key project areas where
it is actively exploring for potential oil and natural gas prospects and in many
cases currently has oil and natural gas production. The 3-D surveys the Company
is using to analyze its project areas range from regional non-proprietary group
shoots to single field proprietary surveys. The Company has participated in
these project areas with industry partners under agreements that typically
provide for the industry partners to bear a 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."
TEXAS
AMAZON PROJECT AREA, Frio/Vicksburg Formations: (75% WI, 56% NRI, Operator:
Edge)
The Amazon Project Area is a 100 square mile, non-proprietary 3-D seismic
survey being shot in South Texas on spec by a major seismic company. The Company
has agreed to purchase 100 square miles of data in this survey area. Edge
expects to receive the 3-D data in late 1998. The Company expects the primary
exploration objectives for this area to be shallow Frio and to a lessor extent
the deeper Vicksburg. Drilling is expected to begin in early 1999.
AUBREY PROJECT AREA, Frio/Vicksburg Formations: (75% WI, 56% NRI, Operator:
Edge)
The Aubrey Project Area is a 51 square mile, proprietary 3-D seismic survey
in South Texas. The Company is currently acquiring the data and has the majority
of the prospective acreage under its control through lease or option. Based on
its nearby activities, Edge expects a mix of both shallow Frio and deeper
Vicksburg wells will be drilled in this area. Drilling is expected to begin in
second quarter of 1998 and the first well is expected to spud in May 1998.
BELCO TARGET AREA 2, Frio Trend and Yegua and Wilcox FormationS: (50% WI, 39.5%
NRI, Operator: Edge)
The Belco Project Area is located in Goliad, Bee and Victoria Counties,
Texas where the Company controls 36,657 acres through lease or option. The
primary exploration objectives for this project area, like the Nita/Austin
Project Area and the Spartan Project Area, are the shallow Frio gas
accumulations, with the secondary objectives being the deeper Yegua and Wilcox
formations. The Company and its partner on this project area, Belco Oil & Gas
Corp. ("Belco"), acquired a total of 44 square miles of proprietary 3-D seismic
data. The Company drilled six wells in this project area in 1997 resulting in
six discoveries and plans to drill in excess of ten additional wells in 1998.
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BRANDON PROJECT AREA, Hockley, Pettus, Yegua, and Wilcox Formations: (50% WI,
38.5% NRI, Operator: Edge)
The Brandon Project Area is an 80 square mile, proprietary 3-D seismic
survey located in Live Oak and Duval Counties in South Texas. The Brandon area
is located near Edge's successful Buckeye project area where the Company made 15
successful discoveries from 19 wells drilled during 1997. The Company expects
the primary exploration objectives for this area to be shallow Hockley, Pettus
and Yegua sands, and potentially some deeper Wilcox targets. Drilling is
expected to begin in April 1998, and to continue throughout the year. Edge has
approximately 49,334 gross acres under option in this project area.
BUCKEYE/CLAYTON/BEE COUNTY PROJECT AREAS, Hockley, Pettus, Yegua and Wilcox,
Formations (50-100% WI, 37.5% - 81% NRI, Operator: Edge)
The Buckeye Project/Clayton/Bee County Project Areas are located in Live
Oak and Bee Counties, Texas adjacent to the Company's Tyler Project Area. The
Company currently holds approximately 51224 gross acres under option or lease
and has acquired an approximate 97 square mile 3-D seismic survey of the area.
As with the Tyler Project Area, the exploration objectives for these project
areas are the shallow zones of the Hockley, Pettus and Yegua formations and the
deep zones of the expanded upper Wilcox formation. This area continues to be
one of the Company's most active areas. The Company drilled 25 wells in this
area during 1997, with 18 discoveries. The Company has expanded the target in
this project area and has budgeted to drill at least 18 more wells in the area
during 1998.
CAMERON PROJECT AREA, Jackson, Yegua and Wilcox Formations: (50% WI, 37.5% NRI,
Operator: Edge)
The Cameron Project Area is located in Webb and Duval Counties, Texas in
the prolific structurally complex Wilcox trend and the highly stratigraphic
Jackson, Yegua trend. The Company and a partner have underwritten approximately
325 square miles of non-proprietary 3-D seismic data in this project area. The
Company has received the first phase of the data and expects most of the
remaining data to come in throughout 1998. Although much of the acreage is held
by production, Edge has budgeted to drill two shallow and two deeper prospects
during 1998. The Company is entitled to 50% of any interests acquired by the
Company and its partner in prospects developed in this project area.
EAST MCFADDIN PROJECT AREA, Frio Formation: (20% WI, 16.5% NRI, Operator:
Pennzoil Company)
The East McFaddin Project Area is located in Victoria County, Texas. In
1995, the Company obtained a 40% working interest in a 4,680 acre lease in the
project area by agreeing to conduct and pay for a 3-D seismic survey of the
project area. Subsequently, the Company expanded its leasehold acreage and
purchased options for 1,760 acres. The Company then obtained a partner to fund
an approximately 11 square mile 3-D seismic survey in exchange for 50% of the
Company's 40% interest. Two successful wells and three dry holes have been
drilled on this lease since acquisition of the 3-D seismic data.
ENCINITAS/KELSEY PROJECT AREA, Frio/Vicksburg Formations: (22.5% WI, 19% NRI,
Operator: Texaco Inc. ("Texaco")
The Encinitas/Kelsey Project Area is located in Brooks County, Texas in the
geologically complex Frio/Vicksburg trend. The Company acquired 9,110 acres in
this project area in December 1994 to re-develop the property. Upon acquisition
of its interests in this project area, the Company undertook a comprehensive
petrophysical study and a 32 square mile 3-D survey over the area which has
resulted in the identification of numerous prospects. Four of these prospects
were drilled between January and June 1996, resulting in four new field
discoveries. During 1997, six of eight wells drilled were discoveries.
Although the survey is largely complete, the Company is currently reprocessing
its 3-D seismic survey. Edge has budgeted to drill several additional shallow
wells and possibly a Vicksburg prospect in 1998 and 1999.
EVEREST PROJECT AREA, Frio/Vicksburg Formations: (5%-50% WI, 3.8% - 37.5% NRI,
Operator: Varies)
The Everest Project Area is located in Starr and Hidalgo Counties, Texas in
the prolific Frio/Vicksburg Formations. The Company and a partner licensed
approximately 340 square miles of non-proprietary 3-D seismic data in this
project area in August 1995 and June 1996. To date, the Company has identified
64 prospects in the shallow Frio trend, the deeper structurally complex
Vicksburg trend, and in the relatively unexplored Eocene Trend. During 1996,
eight of these prospects were drilled (five Frio prospects and three Vicksburg
prospects), resulting in
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six new field discoveries, one field extension and one dry hole. During 1997,
seven of 15 wells drilled were discoveries. The Company has budgeted to drill up
to nine additional wells during 1998.
HIAWATHA PROJECT AREA, Pettus and Yegua Formations: (50% WI, 36.4% NRI,
Operator: Edge)
The Hiawatha Project Area is located in Duval County, Texas. The Company
has leased 15,514 acres in this project area. The Company has drilled 13 wells
resulting in seven producers in this project area and has budgeted to drill two
additional wells in 1998. This project area is substantially developed and the
Company does not expect a significant amount of drilling activity in this area
in the future.
NITA/AUSTIN PROJECT AREA: (0-91% WI, average of 60% NRI, Operator: Varies)
Nita/Austin Project Area: Wilcox Formation. The Nita/Austin Project Area is
located in Goliad County, Texas. The Company has identified and drilled two
large Wilcox prospects in this project area. The first of these prospects
resulted in a discovery by the Company called the Bego Field. An initial test
well drilled in 1991 based on 2-D seismic data resulted in a new field
discovery. A second well in the Bego Field was drilled in 1994 and experienced
mechanical failure and was plugged. In early 1995 the Company acquired a 42
square mile 3-D seismic survey covering this project area. A third Bego Field
well was drilled in 1995 using the 3-D seismic data.
Both Texaco and TransTexas Gas Corporation ("Trans Texas") have had
significant discoveries on Edge generated prospects in the area. Texaco drilled
the Simmons #1, which was a significant discovery, and is currently drilling two
additional wells along the same fault line and is expected to drill a fourth.
Edge has a 2.3% working interest and a 18.75% back-in working interest after
payout in these wells.
TransTexas has drilled a series of successful wells along the same fault.
The Strong Nos. 1, 2 and 3 are currently producing at a combined 10-15 MMcf/d
and TransTexas is preparing to complete the Strong No. 4 which is expected to be
on production early in the second quarter of 1998. Edge has a 2.8% back-in
working interest after payout in the Strong No. 1 and 2 and a proportionally
reduced 2.8% working interest in the Strong No. 3 And 4. TransTexas has also
drilled the successful Bego No. 1 well which is currently producing at a rate of
7MMcf/d. Edge has a 16% working interest and a 17.5% back-in working interest
after payout in the Bego No.1 well.
The Company continues to work the seismic data in this area and expects
during 1998 to uncover more deep leads as well as additional shallow plays.
Edge anticipates retaining a larger interest in any additional deep prospects it
develops.
Nita/Austin Project Area: Shallow Frio Trend. In mid-1995, the Company, through
its analysis of the Nita/Austin 3-D seismic survey, identified 26 prospects in
the shallow Frio trend. From mid-1995 to the end of 1997, 23 of these prospects
were drilled, resulting in 17 discoveries. The Company has an approximate
average 80% working interest and an approximate average 60% net revenue interest
in the properties in the shallow Frio trend portion of this project area. The
Company has budgeted to drill up to two additional wells during 1998.
PICASSO PROJECT AREA: (50% WI, 37.5% NRI, Operator: Edge)
The Picasso Project Area is located in Brooks and Jim Well Counties, Texas.
A proprietary 95 square mile 3-D seismic survey is expected to be received in
the third quarter of 1998 and results are expected to be available during the
second half of 1998, from which the Company has budgeted to drill the first well
in the area during the fourth quarter of 1998.
SPARTAN/SPARTAN EXTENSION PROJECT AREAS, Frio/Vicksburg Formation: (50% WI,
39.5% NRI, Operator: Edge)
Spartan Project Area: The Spartan Project Area is a 23 square mile 3-D seismic
project area located adjacent to the Nita/Austin Project Area in Goliad and
Victoria Counties, Texas. The Company currently has approximately 6,224 gross
acres under lease or option in this project area. The objective for this
project area is primarily the shallow Frio/Vicksburg trend, with additional
potential in the deeper Queen City and Wilcox formations. Drilling began in
1997 and as of December 31, 1997, 12 of 14 wells drilled have resulted in
discoveries.
Spartan Extension Project Area: The Spartan Extension Project Area is a 52.6
square mile extension of the Spartan Project. The Company currently has
approximately 11,234 gross acres under lease or option in this project area. As
of December 31, 1997, six of 10 wells drilled have been discoveries with up to
ten additional shallow wells budgeted for 1998. In addition, the Company is
working to assemble several deep Wilcox prospects in this area.
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SANTELLANA PROJECT AREA: (100% WI, 75% NRI, Operator: Edge)
The Santellana Project Area is located in Hidalgo County, Texas where the
Company controls 2500 acres of shallow leasehold. The Company obtained 15
square miles of 3-D seismic data and certain leases effective December 1997 from
Texaco in a property exchange. Edge has budgeted to drill at least three deeper
Frio wells in this project area in 1998. The Company has reprocessed the
seismic data obtained from Texaco and expects this reprocessing to uncover
additional leads.
TYLER PROJECT AREA, Hockley, Pettus, Wilcox and Yegua Formations: (0%-100% WI,
0%-72% NRI, Operator: varies)
The Tyler Project Area is located in Live Oak County, Texas where the
Company currently has approximately 3,750 gross acres under lease. The
Company's exploration objectives in this area are the deep, over-pressured zones
of the expanded Upper Wilcox formation and the shallow zones of the Hockley,
Pettus and Yegua formations. A 25 square mile proprietary 3-D seismic survey
over the project area was acquired in 1994, from which an approximately 3,500
acre Wilcox prospect was identified. An initial well drilled on the project
area in 1995 was temporarily abandoned for mechanical reasons, but the Company
reentered and completed the well in 1996. One deep prospect was drilled in 1997
and two additional wells are budgeted to be drilled in 1998. The Company has a
0.3% working interest and a 15.2% after payout working interest in these wells.
In addition, in the shallow zones of the Hockley and Pettus formations, the
Company has drilled and developed seven producing wells in 1996 and 1997 and has
budgeted for two additional wells in 1998.
LOUISIANA
SOUTH LOUISIANA PROSPECT AREAS
During 1997, Edge began to reassert itself in South 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 South Maurice Field,
a field that has produced over 100 Bcfe since its discovery in 1987.
GENESIS PROJECT AREA: (27.5%-100% WI, 20%-78% NRI, Operator: Varies)
In the fourth quarter of 1997, the Company acquired from Seitel Inc. an
interest in a 167 square mile 3-D spec survey in Lafayette Parish near its South
Maurice Field. The South Maurice Field was an Edge generated prospect and the
Company's largest discovery to date. The Company has acquired acreage and plans
to spud a development well in April 1998 based on the new 3-D seismic data. The
Company is planning to develop prospects in this area and to sell down its
interest to selective industry partners to lower its overall risk in this
project area. The Company has leased and sold two high-potential high-risk deep
prospects which are budgeted to be drilled in 1998. The Company retained a
27.5% working interest in these two prospects. In addition, evaluation of the
data has resulted in a number of potential leads for prospects that could result
in long term activity in this area. Based on the results of the initial survey,
the Company will participated in an adjacent 247 square mile survey.
NODOSARIA EMBAYMENT PROJECT AREA: (100% WI, 75%NRI, Operator: Edge)
The Company is currently permitting a proposed 139 square mile proprietary 3-D
data shoot in South Louisiana. The Company plans to selectively seek a partner
on a promoted basis to share the cost and risk associated with this project.
Based on the surrounding exploration activities, Edge expects the project area
to have a mix of shallow and deep prospect potential. Drilling is expected to
begin in late 1998 or early 1999.
SOUTH MERMENTAU FIELD: (15.8% WI, 10.4% - 11.3% NRI, Operator: Cody Energy
Inc.)
The South Mermentau Field is located in Acadia Parish, Louisiana. The
Company discovered a natural gas reservoir in this field by drilling an initial
exploration well in 1991. A total of three successful wells have been drilled
by the Company on this field since its initial discovery.
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MISSISSIPPI
QUITO PROSPECT, Cotton Valley and Smackover Formations: (20% WI, 15% NRI,
Operator: Louis Dryfus)
The Quito Prospect is located in Wayne County, Mississippi, where the
Company currently holds approximately 2,760 acres under lease. The Company
identified the prospect using 2-D seismic data and acquired 3-D seismic data in
November 1996 to better delineate the prospect. The Company will begin
development of this project area in 1998 and expects the first well to be
drilled by the second quarter of 1998.
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
approximately 10% of the fully diluted outstanding shares of common stock of
Frontera (excluding employee stock options). The Company paid $3.6 million for
these shares. Frontera is a privately held international energy company based
in Houston, Texas, that is seeking to develop upstream and downstream energy
projects in emerging international markets. Frontera is one of the first
western companies to invest in oil and natural gas rights in the former Soviet
Republic of Georgia and has entered into a production sharing contract and
refinery study with Saknavtobi, the Georgian state oil company, covering acreage
in the Dura Basin in Block 12, eastern Georgia. In addition, Frontera is
pursuing projects in Azerbaijan and Bolivia. In July, 1997, Frontera announced
a strategic alliance with Baker Hughes Solutions, a subsidiary of Baker Hughes
Incorporated, with a view to developing oil and natural gas exploration and
development opportunities in the onshore Jura Basin of Azerbaijan. In
connection with the Frontera investment, Frontera elected James D. Calaway to
serve as a member of its board of directors. There can be no assurance as to
the results of any of Frontera's projects.
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 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 of 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. Effective October 1, 1997, and continuing through January 31, 1998,
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the Company had in place a natural gas commodity collar with a financial
institution covering 5,000 MMbtus per day, or approximately 30% of the Company's
daily production. Prices received float between a floor price of $2.50 per
MMbtu and a cap price of $3.15 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 year ended December 31, 1997 was $33,150
representing a net settlement gain from current collar activity. Subsequent to
December 31, 1997, the Company has entered into two additional collar
arrangements with a financial institution that begin February 1, 1998 and April
1, 1998, respectively, and expire on April 30, 1998 and June 30, 1998,
respectively. These collar arrangements cover 5,000 MMbtus per day with
floating floor and ceiling prices ranging between $2.15 and $2.75 per MMbtu.
There was no material hedging activity during the years ended December 31, 1996
and 1995.
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 prospects and to
acquire additional properties in the future will be dependent upon its ability
to conduct its operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. 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
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wells, the method of drilling and casing wells, the surface use and restoration
of properties upon which wells are drilled, the plugging and abandoning of wells
and the disposal of fluids used in connection with operations. The Company's
operations are also subject to various conservation laws and regulations. These
include the regulation of the size of drilling and spacing units or proration
units and the density of wells that may be drilled in and the unitization or
pooling of oil and natural gas properties. In this regard, some states allow the
forced pooling or integration of tracts to facilitate exploration while other
states rely primarily or exclusively on voluntary pooling of lands and leases.
In areas where pooling is voluntary, it may be more difficult to form units, and
therefore more difficult to develop a project if the operator owns less than
100% of the leasehold. In addition, state conservation laws establish maximum
rates of production from oil and natural gas wells, generally prohibit the
venting or flaring of natural gas and impose certain requirements regarding the
ratability of production. The effect of these regulations may limit the amount
of oil and natural gas the Company can produce from its wells and may limit the
number of wells or the locations at which the Company can drill. For example,
during August 1997, the Texas Railroad Commission curtailed production on the
Company's Wheeler property resulting in lost production of approximately 605
MMcfe as of December 31, 1997, based on historical production rates at the time
of curtailment. Production is expected to resume in late 1998 or early 1999. 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. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the Natural
Gas Policy Act of 1978 (the "NGPA") and the regulations promulgated thereunder
by the Federal Energy Regulatory Commission (the "FERC"). Maximum selling
prices of certain categories of natural gas sold in "first sales," whether sold
in interstate or intrastate commerce, were regulated pursuant to the NGPA. The
Natural Gas Wellhead Decontrol Act (the "Decontrol Act") removed, as of not
later than January 1, 1993, all remaining federal price controls from natural
gas sold in "first sales." The FERC's jurisdiction over natural gas
transportation was unaffected by the Decontrol Act. Although sales by
producers, such as the Company, of natural gas and all sales of crude oil,
condensate and natural gas liquids can currently be made at market prices,
Congress could reenact price controls in the future.
The Company's sales of natural gas are affected by the availability, terms
and cost of transportation. The price and terms for access to pipeline
transportation are subject to extensive regulation. In recent years, the FERC
has undertaken various initiatives to increase competition within the natural
gas industry. As a result of initiatives like FERC Order 636, issued in April
1992, the interstate natural gas transportation and marketing system has been
substantially restructured to remove various barriers and practices that
historically limited non-pipeline natural gas sellers, including producers, from
effectively competing with interstate pipelines for sales to local distribution
companies and large industrial and commercial customers. The most significant
provisions of Order No. 636 require that interstate pipelines provide
transportation separate or "unbundled" from their sales service, and require
that pipelines provide firm and interruptible transportation service on an open
access basis that is equal for all natural gas supplies. In many instances, the
result has been to substantially reduce or eliminate the interstate pipelines'
traditional role as wholesalers of natural gas in favor of providing only
storage and transportation services.
The FERC has announced several important transportation-related policy
statements and proposed rule changes, including a statement of policy and a
request for comments concerning alternatives to its traditional cost-of-service
rate-making methodology to establish the rates interstate pipelines may charge
for their services. A number of pipelines have obtained FERC authorization to
charge negotiated rates as one such alternative. In February 1997, the FERC
announced a broad inquiry into issues facing the natural gas industry to assist
the FERC in establishing regulatory goals and priorities in the post-Order No.
636 environment. Similarly, the Texas Railroad Commission has been reviewing
changes to its regulations governing transportation and gathering services
provided by intrastate pipelines and gatherers and recently implemented a code
of conduct intended to prevent undue discrimination by intrastate pipelines and
gatherers in favor of their marketing affiliates. Although the changes being
considered by these federal and state regulators would affect the Company only
indirectly, they are intended to further enhance competition in natural gas
markets.
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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.
The Company cannot predict what further action the FERC or state regulators
will take on these matters; however, the Company does not believe that it will
be affected by any action taken materially differently than other natural gas
producers with which it competes.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC, state commissions and the
courts. The natural gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent regulatory approach
recently pursued by the FERC and Congress will continue.
Oil Price Controls and Transportation Rates. Sales of crude oil,
condensate and gas liquids by the Company are not currently regulated and are
made at market prices. The price the Company receives from the sale of these
products may be affected by the cost of transporting the products to market.
Effective January 1995, the FERC implemented regulations establishing an
indexing system under which oil pipelines will be able to change their
transportation rates, subject to prescribed ceiling limits. The indexing system
generally indexes such rates to inflation, subject to certain conditions and
limitations. 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 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
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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.
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
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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, 1997, the Company had 43 full-time employees, primarily
professionals, including ten geologists/geophysicists, four geo-technicians,
three landmen and two engineers. The Company believes that its relationships
with its employees are good. None of the Company's employees are covered by a
collective bargaining agreement. From time to time, the Company utilizes the
services of independent consultants and contractors to perform various
professional services, particularly in the areas of construction, design, well
site surveillance, permitting and environmental assessment. Field and on-site
production operation services, such as pumping, maintenance, dispatching,
inspection and testing, are generally provided by independent contractors.
OFFICE AND EQUIPMENT
The Company maintains its executive offices at Texaco Heritage Plaza, 1111
Bagby, Suite 2100, Houston, Texas. During 1997 the Company entered into a
lease, expiring February 3, 2003, for these offices covering 28,206 square feet
of office space.
FORWARD LOOKING INFORMATION AND RISK FACTORS
Certain of the statements contained in all parts of this document
(including the portion, if any, to which this Form 10-K is attached), including,
but not limited to, those relating to the Company's drilling plans, its 3-D
project portfolio, future G&A on 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, additional reserves and reserve
increases, enhancement of visualization and interpretation strengths, expansion
and improvement of capabilities, new credit facilities, attraction of new
members to the exploration team, new prospects and drilling locations, use of
offering proceeds, 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. 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. Such statements involve risks and uncertainties, including,
but
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not limited to, those relating to the Company's dependence on its exploratory
drilling activities, the volatility of oil and natural gas prices, the need to
replace reserves depleted by production, operating risks of oil and natural gas
operations, the Company's dependence on its key personnel, the Company's
reliance on technological development and possible obsolescence of the
technology currently used by the Company, significant capital requirements of
the Company's exploration and development and technology development programs,
the potential impact of government regulations, litigation and environmental
matters, the Company's ability to manage its growth and achieve its business
strategy, competition, the uncertainty of reserve information and future net
revenue estimates, property acquisition risks, risks of foreign operations 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.
DEPENDENCE ON EXPLORATORY DRILLING ACTIVITIES
The success of the Company will be materially dependent upon the continued
success of its 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 often uncertain, and drilling operations may be
curtailed, delayed or cancelled as a result of a variety of factors, including
unexpected drilling conditions, pressure or irregularities in formations,
equipment failures or accidents, adverse weather conditions, compliance with
governmental requirements and shortages or delays in the availability of
drilling rigs 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.
The Company may choose not to acquire option and lease rights prior to acquiring
seismic data and, in many cases, the Company may identify a prospect or drilling
location before seeking option or lease rights in the prospect or location and
in which prospects the Company may not have any option or lease rights.
Although the Company has identified or budgeted for numerous drilling prospects,
there can be no assurance that such prospects will be leased or drilled (or
drilled within the scheduled or budgeted time frame) or that natural gas or oil
will be produced from any such identified prospects or any other prospects.
Prospects may initially be identified through a number of methods, some of which
do not include interpretation of 3-D or other seismic data. Wells that are
currently included in the Company's capital budget may be based upon statistical
results of drilling activities in other 3-D project areas that the Company
believes are geologically similar, rather than on analysis of seismic or other
data. Actual drilling and results are likely to vary from such statistical
results and such variance may be material. 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."
VOLATILITY OF OIL AND NATURAL GAS PRICES
The Company's revenues, profitability, future growth and ability to borrow
funds or obtain additional capital, as well as the carrying value of its
properties, are substantially dependent upon prevailing prices of oil and
natural gas. 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 in the Middle
East, 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
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certainty. Declines in oil and natural gas prices may materially adversely
affect the Company's financial condition, liquidity, ability to finance planned
capital expenditures and results of operations. Lower oil and natural gas prices
also may reduce the amount of oil and natural gas that the Company can produce
economically. See ITEM 7.--"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--General" and ITEMS 1 AND 2.--"BUSINESS AND
PROPERTIES--MARKETING."
The Company periodically reviews the carrying value of its oil and natural
gas properties under the full cost accounting rules of the Commission. Under
these rules, capitalized costs of proved oil and natural gas properties may not
exceed the present value of estimated future net revenues from proved reserves,
discounted at 10%. Application of this "ceiling" test generally requires
pricing future revenue at the unescalated prices in effect as of the end of each
fiscal quarter and requires a write down for accounting purposes if the ceiling
is exceeded, even if prices declined for only a short period of time. The
Company may be required to write down the carrying value of its oil and natural
gas properties when oil and natural gas prices are depressed or unusually
volatile. If a write down is required, it would result in a charge to earnings
and would not impact cash flow from operating activities.
In order to reduce its exposure to short-term fluctuations in the price of
natural gas, the Company periodically enters into hedging arrangements. The
Company's hedging arrangements apply to only a portion of its production and
provide only partial price protection against declines in natural gas prices.
Such hedging arrangements may expose the Company to risk of financial loss in
certain circumstances, including instances where production is less than
expected, the Company's customers fail to purchase contracted quantities of oil
or natural gas or a sudden, unexpected event materially impacts oil or natural
gas prices. In addition, the Company's hedging arrangements limit the benefit to
the Company of increases in the price of natural gas. See ITEM 7.--
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--General" and ITEMS 1 AND 2.--"BUSINESS AND PROPERTIES--MARKETING."
RESERVE REPLACEMENT RISK
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 as reserves
are produced. The Company's future oil and natural gas production is,
therefore, highly dependent upon its level of success in finding or acquiring
additional reserves. The business of exploring for, developing or acquiring
reserves is capital-intensive. To the extent cash flow from operations is
reduced and external sources of capital become limited or unavailable, the
Company's ability to make the necessary capital investment to maintain or expand
its asset base of oil and natural gas reserves would be impaired. As of
December 31, 1997, the Company had participated in a substantial percentage of
its wells as non-operator pursuant to various agreements. The failure of an
operator of the Company's wells to adequately perform operations, or such
operator's breach of the applicable agreements, could adversely impact the
Company. In addition, there can be no assurance that the Company's future
exploration, development and acquisition activities will result in additional
proved reserves or that the Company will be able to drill productive wells at
acceptable costs. See ITEM 7.--"MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS."
OPERATING RISKS OF OIL AND NATURAL GAS OPERATIONS
The oil and natural gas business involves certain operating hazards such as
well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas
or well fluids, fires, formations with abnormal pressures, pollution, releases
of toxic gas and other environmental hazards and risks, any of which could
result in substantial losses to the Company. The availability of a ready market
for the Company's oil and natural gas production also depends on the proximity
of reserves to, and the capacity of, oil and natural gas gathering systems,
pipelines and trucking or terminal facilities. In addition, the Company may be
liable for environmental damages caused by previous owners of property purchased
and leased by the Company. As a result, substantial liabilities to third
parties or governmental entities may be incurred, the payment of which could
reduce or eliminate the funds available for exploration, development or
acquisitions or result in the loss of the Company's properties. In accordance
with customary industry practices, the Company maintains insurance against some,
but not all, of such risks and losses. The Company does not carry business
interruption insurance. The occurrence of an event not fully covered by
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insurance could have a material adverse effect on the financial condition and
results of operations of the Company. See ITEMS 1 AND 2.--"BUSINESS AND
PROPERTIES--OPERATING HAZARDS AND INSURANCE."
DEPENDENCE ON KEY PERSONNEL
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."
RELIANCE ON TECHNOLOGICAL DEVELOPMENT AND POSSIBLE TECHNOLOGICAL OBSOLESCENCE
The Company's business is dependent upon utilization of changing
technology. As a result, the Company's ability to adapt to evolving
technologies, obtain new products and maintain technological advantages will be
important to its future success. The Company believes that its ability to
utilize state of the art technologies currently gives it an advantage over many
of its competitors. This advantage, however, is based in part upon technologies
developed by others, and the Company may not be able to maintain this advantage.
As new technologies develop, the Company may be placed at a competitive
disadvantage, and competitive pressures may force the Company to implement such
new technologies at substantial cost. There can be no assurance that the
Company will be able to successfully utilize, or expend the financial resources
necessary to acquire, new technology, that others will not either achieve
technological expertise comparable to or exceeding that of the Company or that
others will not implement new technologies before the Company. One or more of
the technologies currently utilized by the Company or implemented in the future
may become obsolete. In such case, the Company's business, financial condition
and results of operations could be materially adversely affected. If the
Company is unable to utilize the most advanced commercially available
technology, the Company's business, financial condition and results of
operations could be materially and adversely affected. See ITEMS 1 AND 2.--
"BUSINESS AND PROPERTIES--Exploration Technology."
SIGNIFICANT CAPITAL REQUIREMENTS
Due to its active exploration and development and technology development
programs, the Company has experienced and expects to continue to experience
substantial working capital needs. Additional financing may be required in the
future to fund the Company's growth and developmental and exploratory drilling
and continued technological development. No assurances can be given as to the
availability or terms of any such additional financing that may be required or
that financing will continue to be available under the existing or new credit
facilities. In the event such capital resources are not available to the
Company, its drilling and other activities may be curtailed. See ITEM 7.--
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Liquidity and Capital Resources."
GOVERNMENT REGULATION AND ENVIRONMENTAL MATTERS
Oil and natural gas operations are subject to various federal, state and
local government regulations, which may be changed from time to time in response
to economic or political conditions. Matters subject to regulation include
discharge permits for drilling operations, drilling bonds, reports concerning
operations, the spacing of wells, unitization and pooling of properties and
taxation. From time to time, regulatory agencies have imposed price controls
and limitations on production by restricting the rate of flow of oil and natural
gas wells below actual production capacity in order to conserve supplies of oil
and natural gas. In addition, the development, production, handling, storage,
transportation and disposal of oil and natural gas, by-products thereof and
other substances and materials produced or used in connection with oil and
natural gas operations are subject to regulation under federal, state and local
laws and regulations primarily relating to protection of human health and the
environment. The Company is also subject to changing and extensive tax laws,
the effects of which cannot be predicted. The 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
REGULATION."
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ABILITY TO MANAGE GROWTH AND ACHIEVE BUSINESS STRATEGY
The Company has experienced significant growth in the recent past through
the expansion of its drilling program. The Company's rapid growth has placed,
and is expected to continue to place, a significant strain on the Company's
financial, technical, operational and administrative resources. As the Company
enlarges the number of projects it is evaluating or in which it is
participating, there will be additional demands on the Company's financial,
technical, operational and administrative resources. The Company's ability to
continue its growth will depend upon a number of factors, including its ability
to identify and acquire new exploratory sites, its ability to develop existing
sites, its ability to continue to retain and attract skilled personnel, the
results of its drilling program, hydrocarbon prices, access to capital and other
factors. There can be no assurance that the Company will be successful in
achieving growth or any other aspect of its business strategy.
COMPETITION
The Company encounters competition from other oil and natural gas companies
in all areas of its operations, including the acquisition of exploratory
prospects and proven properties. The Company's competitors include major
integrated oil and natural gas companies and numerous independent oil and
natural gas companies, individuals and drilling and income programs. Many of
its competitors are large, well-established companies with substantially larger
operating staffs and greater capital resources than the Company's and which, in
many instances, have been engaged in the oil and natural gas business for a much
longer time than the Company. Such companies may be able to pay more for
exploratory prospects and productive 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 prospects and to
acquire additional properties in the future will be dependent upon its ability
to conduct its operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. See ITEMS 1 AND
2.--"BUSINESS AND PROPERTIES--COMPETITION."
UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES
There are numerous uncertainties inherent in estimating oil and natural gas
reserves and their estimated values, including many factors beyond the control
of the producer. The reserve data set forth in this report represent only
estimates. Reservoir engineering is a subjective 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 and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions concerning future oil and
natural gas prices, future operating costs, severance and excise taxes,
development costs and workover and remedial costs, all of which may in fact vary
considerably from actual results. For these reasons, estimates of the
economically recoverable quantities of 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 and such reserve estimates may be subject to downward or
upward adjustment based upon such factors. Actual production, revenues and
expenditures with respect to the Company's reserves will likely vary from
estimates, and such variances may be material. In addition, the 10% discount
factor, which is required by the Commission to be used in calculating discounted
future net cash flows for reporting purposes, is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company or the oil and natural gas industry in
general. See ITEMS 1 AND 2.--"BUSINESS AND PROPERTIES--Oil and Natural Gas
Reserves."
ACQUISITION RISKS
The Company generally seeks to explore for oil and natural gas rather than
to purchase producing properties. As a result, the Company's experience in the
acquisition of such properties is limited. The successful acquisition of
producing properties requires an assessment of recoverable reserves, future oil
and natural gas prices,
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operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact and their accuracy inherently
uncertain. In connection with such an assessment, the Company performs a review
of the subject properties that it believes to be generally consistent with
industry practices, which generally includes on-site inspections and the review
of reports filed with various regulatory entities. Such a review, however, will
not reveal all existing or potential problems nor will it permit a buyer to
become sufficiently familiar with the properties to fully assess their
deficiencies and capabilities. Inspections may not always be performed on every
well, and structural and environmental problems are not necessarily observable
even when an inspection is undertaken. Even when problems are identified, the
seller may be unwilling or unable to provide effective contractual protection
against all or part of such problems. There can be no assurances that any
acquisition of property interests by the Company will be successful and, if
unsuccessful, that such failure will not have an adverse effect on the Company's
future results of operations and financial condition.
RISKS OF FOREIGN OPERATIONS
The Company's investment in Frontera Resources Corporation and other
foreign investments 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.
YEAR 2000
The Company has evaluated the impact of the year 2000 processing issues
considering current financial and accounting, production, land and geological
computer systems and software utilized by the Company. The Company is in the
process of replacing its existing financial and accounting, production and land
applications with software which is year 2000 compliant. Implementation is
expected to be completed on or before June 30, 1998 at a total cost of
approximately $200,000. The Company believes its geological systems and software
are year 2000 compliant. The Company currently anticipates that it will not
incur a material disruption of operations relating to year 2000 processing
issues but there can be no assurance that the Company will not incur unexpected
year 2000 costs or be adversely affected by year 2000 issues of its suppliers,
customers and other entities.
ABSENCE OF DIVIDENDS ON COMMON STOCK
The Company currently intends to retain any earnings for the future
operation and development of its business and does not currently anticipate
paying any dividends in the foreseeable future. Any future dividends also may
be restricted by the Company's then-existing loan agreements. See 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.
MARKETABILITY OF PRODUCTION
The marketability of the Company's production depends upon the availability
and capacity of natural gas gathering systems, pipelines and processing
facilities, and the unavailability or lack of capacity thereof could result in
the shut-in of producing wells or the delay or discontinuance of development
plans for properties. In addition, Federal and state regulation of oil and
natural gas production and transportation, general economic conditions and
changes in supply and demand could adversely affect the Company's ability to
produce and market its oil and natural gas on a profitable basis.
CERTAIN ANTI-TAKEOVER PROVISIONS
The Company's Certificate of Incorporation and Bylaws and the Delaware
General Corporation Law contain provisions that may have the effect of delaying,
deferring or preventing a change of control of the Company. These provisions,
among other things, provide for a classified Board of Directors with staggered
terms, restrict the
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ability of stockholders to take action by written consent and authorize the
Board of Directors to set the terms of Preferred Stock.
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.
Present value. When used with respect to oil and natural gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using prices
and costs in effect as of the date indicated, without giving effect to
nonproperty-related expenses such as general and administrative expenses, debt
service and future income tax expense or to depletion, depreciation, and
amortization, discounted using an annual discount rate of 10%.
Productive well. A well that is found to be capable of producing hydrocarbons
in sufficient quantities such that proceeds from the sale of such production
exceeds production expenses and taxes.
Proved developed nonproducing reserves. Proved developed reserves expected to
be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and able to produce to market.
Proved developed reserves. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
23
<PAGE>
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible oil and/or 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 E. CALAWAY has served as the Chief Executive Officer and Chairman of the
Board of Directors of the Company (the "Board") since December 1996. He was a
founder of the Company's predecessor corporations and served as the Chief
Executive Officer and Chairman of the Board of such companies from 1986 until
the Company's March 1997 initial public offering. Mr. John E. Calaway is also
the Chairman of the Nominating Committee of the Board. Mr. John E. Calaway has
more than 20 years of experience in the oil and natural gas exploration and
production business. Mr. John E. Calaway is 40 years old.
JAMES D. CALAWAY has served as the President and as a director of the Company
since December 1996 and prior thereto served as a director of the Company's
corporate predecessor since April 1991. Mr. James D. Calaway is also
24
<PAGE>
a member of the Audit and Nominating Committees of the Board. From January 1994
to March 1997, he served as Special Advisor to the Company's corporate
predecessor. From 1989 to January 1994, Mr. James D. Calaway was primarily
engaged in the organization and capitalization of several high technology
companies, including The Forefront Group, Inc. Prior thereto, he served as Vice
President of Business Development for Space Industries International, Inc., a
company he co-founded in 1982 that develops, fabricates, integrates and operates
spacecraft and space flight equipment. Mr. James D. Calaway received a B.A. in
Economics from the University of Texas and an M.A. in Politics, Philosophy and
Economics from Oxford University. Mr. James D. Calaway is 40 years old. Mr John
E. Calaway and Mr. James D. Calaway are twin brothers.
MICHAEL G. LONG has served as 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 45 years old.
BRIAN C. BAUMLER has served as Controller of the Company since June 1997 and
Treasurer since August 1997. From September 1988 to May 1997, Mr. Baumler was
employed by Deloitte and Touche LLP, most recently as a Senior Manager of Audit
Services. He is a Certified Public Accountant, a member of the American
Institute of Certified Public Accounts, Texas Society of Certified Public
Accountants and the Houston Chapter of Certified Public Accountants. He holds a
B.B.A in Accounting from the University of Northern Iowa. Mr. Baumler is 32
years old.
SIGNIFICANT EMPLOYEES
DAVID L. BLAKE has served as a Director of Exploration for the Company since
March 1997 and prior thereto served as a geophysicist/geologist with the
Company's predecessor corporation since July 1989. From 1984 to July 1989, he
held the position of geophysicist for Mobil Exploration and Production Company.
Mr. Blake holds a B.S. in Geophysics from Texas A&M University.
MARK J. GABRISCH has served as the Director 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 a Director 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 Director of Engineering 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.
25
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) As of March 20, 1998, the Company estimates there were
approximately 191 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 20, 1998, the Company had 7,760,867 shares
outstanding and its closing price on NASDAQ was $12.00 per share. The high and
low bid prices for the Company's Common Stock during each quarter in the year
ended December 31, 1997 were as follows:
COMMON STOCK
HIGH LOW
---- ---
QUARTER:
First(1)............... $19 3/8 $16
Second................. 16 1/2 11 3/4
Third.................. 20 12 1/2
Fourth................. 21 1/8 11
_______________
(1) The first date of trading of the Company's common stock was February 26,
1997.
The Company has never paid a dividend, cash or otherwise and does not
intend to in the foreseeable future. See ITEMS 1 AND 2.--BUSINESS AND
PROPERTIES--"FORWARD LOOKING INFORAMTION AND RISK FACTORS--Absence of Dividends
on Common Stock."
In August and September of 1997, the Company sold an aggregate of 48,922
shares of Common Stock to a former employee pursuant to a stock option that had
been previously granted by the Company's predecessor corporation and assumed by
the Company in the Combination Transactions (as defined herein). These shares
were sold for $2.04 per share in cash pursuant to the terms of such option.
Such exercise was exempt from registration pursuant to Rule 701 promulgated
under the Securities Act of 1933, as amended.
(b) Use of Proceeds.
The Company's Registration Statements on Form S-1 (Registration Nos.
333-17267 and 333-22363), as amended, with respect to the initial public
offering (the "Offering") of shares of Company's Common Stock was declared
effective by the Securities and Exchange Commission on February 25, 1997. In
the Offering, the Company sold 2,400,000 shares of Common Stock on March 3, 1997
and 360,000 shares of Common Stock on March 17, 1997 pursuant to the exercise of
the underwriters' over-allotment option.
The net proceeds to the Company from the Offering were $40 million.
As of December 31, 1997, the Company has used such net proceeds as follows: (i)
to repay $12.7 million of indebtedness, (ii) to make a $3.6 million investment
in Frontera and capital expenditures of $19.9 million in the Company's drilling
plans and its 3-D project portfolios and (iii) the remaining $3.8 million was
used to acquire temporary investments. None of such payments were direct or
indirect payments to directors or officers of the Company or their associates,
to persons owning ten percent or more of any class of equity securities of the
Company or to affiliates to the Company.
26
<PAGE>
ITEM 6. SELECTED FINACIAL 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,
-----------------------------------------------------------------
1997 1996 (3) 1995 (3) 1994 (3) 1993 (3)
---- ------- -------- -------- --------
(in thousands exccept per share amounts)
<S> <C> <C> <C> <C> <C>
Statement of Operational Data:
Oil and natural gas revenue $ 13,468 $ 7,719 $ 2,040 $ 1,994 $ 1,455
Costs and expenses:
Oil and natural gas operating expenses 2,331 1,600 686 305 167
Depletion, depreciation and amortization 2,876 1,613 813 593 441
General and administrative 4,641 2,753 2,484 2,026 1,734
Unearned compensation expense 513
-------- ------- ------- ------- -------
Total operating expenses 10,361 5,966 3,983 2,924 2,342
-------- ------- ------- ------- -------
Operating income (loss) 3,107 1,753 (1,943) (930) (887)
Interest expense (183) (859) (315) (385) (635)
Interest income 901
Gain on sale of oil and gas property 3,337 2,284 247
Other income 233
-------- ------- ------- ------- -------
Income (loss) before income taxes
and minority interest 3,825 1,127 1,079 969 (1,275)
Income tax expense (394) (397) (292)
Minority interest (433) (576) (543) 721
-------- ------- ------- ------- -------
Net income (loss) $ 3,825 $ 300 $ 106 $ 134 $ (554)
======== ======= ======= ======= =======
Pro forma basic income (loss) per share (1) $ 0.53 $ 0.06 $ 0.02 $ 0.03 $ (0.12)
Pro forma diluted income (loss) per share (1) $ 0.52 $ 0.06 $ 0.02 $ 0.03 $ (0.12)
Pro forma basic weighted average number of
shares outstanding (1) 7,275 4,701 4,701 4,701 4,701
Pro forma diluted weighted average number of
shares outstanding (1) 7,320 4,701 4,701 4,701 4,701
Statement of Cash Flow Data:
EBITDA (2) $ 6,884 $ 3,166 $ 1,631 $ 1,404 $ 522
Capital expenditures 29,874 10,467 8,512 6,809 3,660
Net cash (used in) provided by operating activities 4,145 2,278 (927) 1,404 522
Net cash used in investing activities (31,177) (5,651) (1,154) (722) (1,081)
Net cash provided by financing activities 29,266 4,716 1,932 6,809 3,660
</TABLE>
<TABLE>
<CAPTION>
As of December 31,
-----------------------------------------------------------------
1997 1996 (3) 1995 (3) 1994 (3) 1993 (3)
---- ------- -------- -------- --------
(in thousands)
<S> <C> <C> <C> <C> <C>
Balance Sheet Data:
Working capital $ 7,627 $ 690 $ (947) $ (973) $ (168)
Property and equipment, net 36,663 11,989 7,911 4,136 2,622
Total assets 53,766 19,556 9,858 6,128 5,190
Long-term debt including current maturities 11,862 6,214 4,177 4,240
Equity (deficit) 47,911 (373) (658) (749) (871)
</TABLE>
_______________
(1) Pro forma net income (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 Transactions were outstanding for
all periods prior to the Combination.
(2) EBITDA represents earnings before interest expense, income taxes, depletion,
depreciation and amortization. Management of the Company believes that
EBITDA may provide additional information about the Company's ability to
meet its future requirements for debt service, capital expenditures and
working capital. EBITDA is a financial measure commonly used 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 four 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 Old Edge and the
Joint Venture (as defined herein). The Joint Venture interests not owned by
Old Edge is recorded as minority interest.
27
<PAGE>
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 Offering and the related combination of certain entities
that held interests in Edge Joint Venture II (the "Joint Venture") and the
acquisition of direct interests in the Joint Venture and in certain oil and
natural gas properties also owned by the Joint Venture. In a series of
transactions (the "Combination or Combination Transactions"), the Company
acquired directly or indirectly 100% of the interests in the Joint Venture and
the Calaway Interests (as defined herein) (collectively the "Combined Assets")
by completing (i) a merger of Edge Petroleum Corporation, a Texas corporation
("Old Edge"), with and into a wholly owned subsidiary of the Company in which
shareholders of Old Edge received shares of common stock and Old Edge became a
wholly owned subsidiary of the Company; (ii) an exchange of shares of the
Company's common stock for the general and limited partner interests in Edge
Group II Limited Partnership and the limited partner interests in Gulfedge
Limited Partnership; (iii) an acquisition of interests in certain oil and
natural gas properties held by Mr. James C. Calaway (the "Calaway Interests") in
exchange for shares of the Company's common stock; and (iv) a purchase of Edge
Group Partnership's interest in the Joint Venture in exchange for shares of the
Company's common stock. The Company issued an aggregate of 4,701,361 shares of
common stock in the Combination.
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 began operations in 1983 and until 1992 generated exploratory
drilling prospects based on 2-D seismic data for sale to other exploration and
production companies. During 1992, as a result of the advent of economic
onshore 3-D seismic surveys and the improvement and increased affordability of
data interpretation technologies, the Company changed its strategy to emphasize
exploration based upon the use of 3-D seismic data. From 1992 to 1995, the
Company reduced its inventory of 2-D based prospects, began limited drilling for
its own account and began developing prospects based on 3-D seismic data. Since
early 1995, the Company has almost exclusively drilled prospects generated from
3-D seismic data, while accelerating its drilling activity and increasing its
working interests in new project areas primarily in South Texas and Louisiana.
The Company uses the full-cost method of accounting for its oil and natural
gas properties. Under this method, all acquisition, exploration and development
costs, including certain general and administrative costs that are directly
attributable to the Company's acquisition, exploration and development
activities, are capitalized in a "full-cost pool" as incurred. The Company
records depletion of its full-cost pool using the unit of production method.
Investments in unproved properties are not subject to amortization until the
proved reserves associated with the projects can be determined or until
impaired. To the extent that capitalized costs subject to amortization in the
full-cost pool (net of depletion, depreciation and amortization and related
deferred taxes) exceed the present value (using a 10% discount rate) of
estimated future net after-tax cash flows from proved oil and natural gas
reserves, such excess costs are charged to operations. Once incurred, an
impairment of oil and natural gas properties is not reversible at a later date.
Impairment of oil and natural gas properties is assessed on a quarterly basis in
conjunction with the Company's quarterly filings with the Commission. During
the three years ended December 31, 1997, no impairments of the Company's oil and
natural gas properties were deemed necessary.
Pursuant to the Combination Transactions, the owners of the Combined Assets
received all revenues attributable to production and are responsible for all
incurred expenses related to the Combined Assets for all periods prior to March
3, 1997. Effective with the Combination (which was contemporaneous with the
closing of the Offering), the Company is entitled to receive all revenues and is
responsible for all expenses related to the Combined Assets on and after March
3, 1997.
28
<PAGE>
The Joint Venture was not a tax paying entity, and the applicable taxes for
all periods prior to the Combination (March 3, 1997) are directly taxable to the
individual affiliate owners of the Joint Venture.
The Company's revenues, profitability, future growth and ability to borrow
funds or obtain additional capital, and the carrying value of its properties,
are substantially dependent on prevailing prices of oil and natural gas. It is
impossible to predict future oil and natural gas price movements with certainty.
Declines in prices received for oil and natural gas may have an adverse affect
on the Company's financial condition, liquidity, ability to finance capital
expenditures and results of operations. Lower prices may also impact the amount
of reserves that can be produced economically by the Company.
Due to the instability of oil and natural gas prices, the Company has
entered into, from time to time, price risk management transactions (e.g., swaps
and collars) for a portion of its 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 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 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. Effective October 1, 1997, and
continuing through January 31, 1998, the Company had in place a natural gas
commodity collar with a financial institution covering 5,000 MMbtus per day, or
approximately 30% of the Company's daily production. Prices received float
between a floor price of $2.50 per MMbtu and a cap price of $3.15 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. Total natural gas production marketed under this
arrangement was 460,000 MMbtu for the year ended December 31, 1997. Included
within natural gas revenues for the year ended December 31, 1997 was $33,150
representing a net gain from current collar activity. Subsequent to December
31, 1997, the Company has entered into two additional collar arrangements with a
financial institution that begin February 1, 1998 and April 1, 1998,
respectively, and expire on April 30, 1998 and June 30, 1998, respectively.
These collar arrangements cover 5,000 MMbtus per day with floating floor and
ceiling prices ranging between $2.15 and $2.75 per MMbtu. There was no material
hedging activity during the years ended December 31, 1996 and 1995.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1997 COMPARED TO THE YEAR ENDED DECEMBER 31, 1996
Revenue and Production
Oil and natural gas revenues increased 74% from $7.7 million in 1996 to
$13.5 million in 1997. Production volumes for oil increased 52% from 109,225
Bbls in 1996 to 165,640 Bbls in 1997. The increase in oil production increased
revenues by approximately $1.1 million, which was partially offset by an 11%
decrease in average oil prices that reduced revenues by approximately $348,000.
Production volumes for natural gas increased 86% from 2,316,105 Mcf in 1996 to
4,298,859 Mcf in 1997. The increase in natural gas production increased
revenues by approximately $4.8 million. A 2% increase in average natural gas
prices increased revenues by approximately $170,000. The overall net increase
in oil and natural gas production was due to 75 new gross, (29.89 net),
producing exploratory and development wells drilled and completed since December
31, 1996 partially offset by normal production declines from existing wells.
During the year ended December 31, 1997 the Company marketed its natural gas
produced from a certain gas field under the terms of fixed price natural gas
contracts. The terms of these contracts required no minimum volume commitment
and provided incremental pricing based on certain levels of production. Total
production during 1997 (net to the Company's interest), marketed under these
agreements was approximately 1.4 Bcf. Prices received for production marketed
under these agreements averaged $2.25 per Mcf for the year ended December 31,
1997. No such contracts existed during 1996. Included within natural gas
revenues for the year ended December 31, 1997 was $33,150 representing a net
gain from current collar activity. The collar settlements increased the
effective average natural gas prices by $0.01 per Mcf for the year ended
December 31, 1997.
29
<PAGE>
The following table summarizes production volumes, average sales
prices and operating revenues for the Company's oil and natural gas operations
for the years ended December 31, 1997 and 1996.
<TABLE>
<CAPTION>
1997 Period Compared
December 31, to 1996 Period
------------------------ ----------------------------
Increase % Increase
1997 1996 (Decrease) (Decrease)
---- ---- --------- ----------
<S> <C> <C> <C> <C>
Production volumes:
Oil and condensate (Bbls) 165,640 109,225 56,415 52 %
Natural gas (Mcf) 4,298,859 2,316,105 1,982,754 86 %
Average sales prices:
Oil and condensate ($ per Bbl) $ 17.21 $ 19.31 $ (2.10) (11)%
Natural gas ($ per Mcf) 2.47 2.42 0.05 2 %
Operating revenues:
Oil and condensate $ 2,850,600 $2,108,729 $ 741,871 35 %
Natural gas 10,617,442 5,610,749 5,006,693 89 %
----------- ---------- ----------
Total $13,468,042 $7,719,478 $5,748,564 74 %
=========== ========== ==========
</TABLE>
COSTS AND OPERATING EXPENSES
Oil and natural gas operating expenses increased 46% from $1.6 million in
1996 to $2.3 million in 1997 due to increased production generated from new oil
and natural gas wells drilled and completed in 1997. Oil and natural gas
operating expenses on a unit of production basis were $0.44 per Mcfe and $0.54
Mcfe for the years ended December 31, 1997 and 1996, respectively. The decrease
on a unit of production basis is primarily attributable to the disproportionate
increase in natural gas production during 1997, which has a lower average
production cost per Mcfe compared to oil.
Depletion, depreciation and amortization expense ("DD&A") increased 78%
from $1.6 million in 1996 to $2.9 million in 1997. Included within DD&A for the
years ended December 31, 1996 and 1997 was $1.35 million and $2.49 million,
respectively, representing depletion expense of oil and natural gas properties.
The increase in depletion expense was primarily due to increased oil and natural
gas production, which increased depletion expense by approximately $1.1 million.
A 4% increase in the overall depletion rate increased depletion expense by
approximately $70,000. The increase in depletion rate was primarily due to an
increase in future development cost for proved undeveloped oil and natural gas
properties of approximately $5 million and a 6.3 Bcfe downward revision to prior
year oil and natural gas reserve volume estimates. Depletion on a unit of
production basis for the years ended December 31, 1997 and 1996 was $0.47 per
Mcfe and $0.45 per Mcfe, respectively. The remaining increase in DD&A was due
primarily to depreciation of new computer hardware and software and office
furniture purchased since December 31, 1996, which was partially offset by
decreased amortization of deferred loan costs.
General and administrative expense ("G&A") increased 69% from $2.8 million
in 1996 to $4.6 million in 1997. This increase was attributable to additional
administrative staffing and the hiring of additional employees to support the
Company's increased level of exploration activities, 3-D project generation and
other activities. Included as a reduction in G&A for the years ended December
31, 1997 and 1996, was approximately $802,000 and $339,000, 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, 1997 and 1996 were $0.88
per Mcfe and $0.93 per Mcfe, respectively. The Company expects that G&A on a
unit of production basis to continue to decline as production increases and the
rate of increase in G&A slows.
Unearned compensation expense for the year ended December 31, 1997 was
$513,393 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.
Interest expense decreased 79% from $858,663 in 1996 to $183,028 in 1997.
The decrease resulted from the repayment of $12.7 million of indebtedness on
March 3, 1997 with proceeds of the Offering.
30
<PAGE>
Interest income for the year ended December 31, 1997 was $900,867 earned
from short-term investments purchased from excess proceeds from the Offering.
There was no material short-term investments purchased during 1996.
Other income in 1996 consisted of $232,500 of commissions earned to market
a property for a third party. There were no such commissions earned during the
year ended December 31, 1997.
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, 1997, the Company has
substantially utilized its available net operating loss carry forward and other
net deferred tax assets and should the Company have taxable income in future
periods a provision for tax expense will be provided. Income tax expense for
the year ended December 31, 1996 was $394,675.
Minority interest for the year ended December 31, 1997 was eliminated as
result of the completion of the Combination on March 3, 1997 in which the
Company acquired from the predecessor entities 100% of their ownership interests
in the Joint Venture.
For the year ended December 31, 1997, the Company had operating income of
$3.1 million as compared to operating income of $1.8 million in 1996. The
significant increase in operating income was primarily attributable to higher
levels of production from new well additions offset by increases in operating
costs and expenses related to the new well additions (75 gross, 29.89 net) and
lower average oil and condensate prices. Operating income was further reduced
by increased G&A attributable to additional administrative staffing and the
hiring of additional employees to support the Company's increased level of
drilling activities. Net income was $3.8 million, or basic and diluted earnings
per share of $0.53 and $0.52, respectively, for the year ended December 31,
1997, as compared to net income of $300,185, or basic and diluted earnings per
share of $0.06 for 1996.
YEAR ENDED DECEMBER 31, 1996 COMPARED TO THE YEAR ENDED DECEMBER 31, 1995
Revenue and Production
Oil and natural gas revenues increased 278% from $2.0 million in 1995 to
$7.7 million in 1996. Production volumes for oil increased 71% from 63,885 Bbls
in 1995 to 109,225 Bbls in 1996. The increase in oil production increased
revenues approximately $724,000 further increased by a 21% increase in average
oil prices which increased revenue by approximately $365,000. Production
volumes for natural gas increased 352% from 512,901 Mcf in 1995 to 2,316,105 Mcf
in 1996. The increase in natural gas production increased revenues by $3.6
million. A 22% increase in average natural gas prices increased revenues by $1.0
million. The increase in oil and natural gas production was due to 32 new
gross, (15.8 net), producing exploratory and development wells being
successfully drilled and completed during 1996, which was partially offset by
normal production declines from existing wells. The increases in average oil
and natural gas prices were directly attributable to improved overall market
conditions.
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 1996 and 1995.
<TABLE>
<CAPTION>
1996 Period Compared
December 31, to 1995 Period
--------------------------- --------------------------
1996 1995 Increase % Increase
---- ----
<S> <C> <C> <C> <C>
Production volumes:
Oil and condensate (Bbls) 109,225 63,885 45,340 71 %
Natural gas (Mcf) 2,316,105 512,901 1,803,204 352 %
Average sales prices:
Oil and condensate ($ per Bbl) $ 19.31 $ 15.96 $ 3.35 21 %
Natural gas ($ per Mcf) $ 2.42 $ 1.99 $ 0.43 22 %
Operating revenues:
Oil and condensate $ 2,108,729 $ 1,019,773 $ 1,088,956 107 %
Natural gas 5,610,749 1,020,673 4,590,076 450 %
----------- ----------- -----------
Total $ 7,719,478 $ 2,040,446 $ 5,679,032 278 %
=========== =========== ===========
</TABLE>
31
<PAGE>
COSTS AND OPERATING EXPENSES
Oil and natural gas operating expenses increased 133% from $686,438 in 1995
to $1.6 million in 1996 due to increased production generated from new oil and
natural gas wells drilled and completed during 1996. Oil and natural gas
operating expenses on a unit of production basis were $0.54 per Mcfe and $0.77
per Mcfe for the years ended December 31, 1996 and 1995, respectively. . The
decrease on a unit of production basis is primarily attributable to the
disproportionate increase in natural gas production during 1996, which has a
lower average production cost per Mcfe compared to oil.
DD&A expense increased 98% from $813,402 in 1995 to $1.6 million in 1996.
Included within DD&A for the years ended December 31, 1995 and 1996 was $557,657
and $1.35 million, respectively, representing depletion expense of oil and
natural gas property. The increase in depletion expense was primarily due to
improved oil and natural gas production, which increased depletion expense by
approximately $1.3 million. This was partially offset by a 27% decrease in the
overall depletion rate decreased depletion expense by $498,000. The decrease in
depletion rate was primarily due to a significant increase in oil and natural
gas reserve estimates as of December 31, 1996. Depletion on a unit of
production basis for the years ended December 31, 1996 and 1995 was $0.45 per
Mcfe and $0.62 per Mcfe, respectively. The remaining increase in DD&A was due
primarily to depreciation of new computer hardware and software and office
equipment purchased since December 31, 1995 offset by a decrease in the
amortization of organizational cost which became fully amortized during 1995.
G&A increased 11% from $2.5 million in 1995 to $2.8 million in 1996. This
increase was attributable to additional administrative staffing and the hiring
of additional employees to support the Company's increased level of drilling
activities, 3-D project generation and other activities. Included as a
reduction in G&A for the years ended December 31, 1996 and 1995, was
approximately $339,000 and $144,000, respectively, of overhead reimbursements
and management fees received from various management, operating and seismic
agreements. G&A on a unit of production basis for the years ended December 31,
1996 and 1995 was $0.93 per Mcfe and $2.77 per Mcfe, respectively.
Interest expense increased 172% from $315,342 in 1995 to $858,663 in 1996.
This increase was primarily due to the repayment of a promissory note in March
1995 which reduced the weighted average debt outstanding during 1995, offset by
increased borrowings during the second half of 1995 and throughout 1996 under
the Revolving Credit Facility which was partially offset during 1996 by a lower
average interest rate.
Other income in 1996 consists of $232,500 of commissions earned to market a
property for a third party. There were no such commissions earned in 1995.
There were no gains on the sale of oil and natural gas property in 1996 as
compared to a gain of $3.3 million in 1995. The majority of the gain recorded in
1995 was attributable to the sale of a proved producing property for $3.4
million resulting in a gain of $2.8 million. The remaining gain was
attributable to the sale of an unproved oil and natural gas prospect.
Minority interest decreased from $575,811 in 1995 to $432,786 in 1996. The
decrease was attributable to reduced earnings of the Joint Venture.
Income tax expense for the years ended December 31, 1996 and 1995 was
$394,675 and $397,088, respectively.
Net income was $300,185, or basic and diluted earnings per share of $0.06,
for the year ended December 31, 1996 as compared to $105,881, or basic and
diluted earnings per share of $0.02, for the year ended December 31, 1995.
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
32
<PAGE>
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.
The Company had cash and cash equivalents at December 31, 1997 of $3.8
million, consisting primarily of short-term money market investments, as
compared to $1.5 million at December 31, 1996. Working capital was $7.6 million
as of December 31, 1997 as compared to $690,393 at December 31, 1996.
Cash flows provided by (used in) operations were $4.1 million, $2.3 million
and ($926,771), for the years ended December 31, 1997, 1996 and 1995,
respectively. The significant increase in net cash provided by operations for
the year ended December 31, 1997 as compared to 1996 was primarily attributable
to higher levels of production from new well additions which was partially
offset by increases in operating costs and expenses related to the new
successful wells (75 gross, 29.89 net) and lower average oil and condensate
prices. Operating cash flows were further reduced by increased G&A attributable
to additional administrative staffing and the hiring of additional employees to
support the Company's increased level of exploration activities. The increase
in operating cash flows for the year ended December 31, 1996 as compared to 1995
was primarily attributable to an increase in operating income of $3.7 million,
partially offset by an increase in working capital of $1.6 million and increased
interest expense. The changes in working capital were primarily due to the
Company becoming an oil and natural gas well operator in late 1995 and a
significant increase in drilling activities during the year ended December 31,
1996. The increase in cash flows used in 1995 was due primarily to the increase
in operating loss, which was offset by various changes in balance sheet
accounts. Accounts receivable from working interest owners increased $213,300
in 1995 due to increased drilling activity in which the Company was the
operator. Accounts payable, trade and accounts payable to related parties
increased by $420,257 and $266,490, respectively. These increases were caused
by increased drilling activity for the Company's own account as well as an
increase in management fees due a related party which accumulated but had not
yet been paid.
During the year ended December 31, 1997, 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 $31.2 million in investing activities during 1997
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 $10.5 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 are convertible into approximately 10% of the common stock of
Frontera. The Company may seek overseas direct investment opportunities with
Frontera and, particularly in Latin America, with others. The Company expects
capital expenditures in 1998 will be at least $30 million. A substantial
portion of capital expenditures in 1998 will be invested in the Company's
portfolio of 3-D prospects to fund drilling activities 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.
During the year ended December 31, 1996, the Company reinvested a
substantial portion of its cash flows to increase its 3-D prospect portfolio,
improve its 3-D seismic interpretation technology and fund its drilling program.
As a result, the Company used $5.7 million in investing activities during 1996
including capital expenditures of $10.5 million offset by proceeds from the
sales of oil and natural gas property of $4.8 million. Investing activities
used $1.2 million in cash in 1995. This change was attributable to a substantial
increase in capital expenditures relating to the Company's increased exploration
activities. The Company's drilling efforts resulted in the successful
completion of 22 gross wells in 1995 and 32 gross wells in 1996. In 1995 the
Company sold one of its proved producing properties and received total cash
proceeds from such sale of $3.4 million. The Company sold another of its proved
producing properties for $2.6 million in 1996. These proceeds were used to pay
down debt and fund general working capital and corporate needs. The Company
also sold several undeveloped oil and natural gas prospects and received cash
proceeds of $2.2 million and $4.0 million in 1996 and 1995, respectively.
Cash flows from financing activities in 1997 were $29.3 million compared to
$4.7 million in 1996. The
33
<PAGE>
significant increase in cash flows from financing activities is attributable to
the completion of the Company's Offering in March 1997 offset by repayment of
the Company's debt. Cash flows from financing activities in 1996 were primarily
attributable to drawdowns on its Revolving Credit Facility, which were partially
offset by deferred offering costs. Cash flows from financing activities were
$1.9 million for the year ended December 31, 1995 primarily attributable to
drawdowns on its Revolving Credit Facility, offset by the repayment of other
long-term indebtedness.
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 1998 capital expenditures, commitments and working capital requirements
through cash flows from operations, borrowings and to the extent necessary other
financing activities. The Company believes it will have sufficient capital
resources and liquidity to fund its capital expenditures and meet such financial
obligations as they come due. In the event such capital resources are not
available to the Company, its drilling and other activities may be curtailed.
See ITEMS 1 AND 2.--BUSINESS AND PROPERTIES--"FORWARD LOOKING INFORMATION AND
RISK FACTORS--Significant Capital Requirements."
REVOLVING CREDIT FACILITY
In July 1995, the Company entered into a two-year secured Revolving Credit
Facility with Compass Bank-Houston ("Compass") which provides a maximum loan
amount of $20 million, subject to borrowing base limitations. The Credit
Facility allows Compass to make, in its sole discretion, the borrowing base
determination based upon the Company's proved oil and natural gas reserves.
During early 1997 the maturity of the Credit Facility was extended to July 1998.
The interest rate for borrowings is either the Base Rate plus 0.5% or LIBOR plus
2.5%. The Base Rate is the higher of (i) the Federal Funds Rate plus 0.5% or
(ii) the prime rate. The Credit Facility also provides for the payment of
certain commitment and other fees. The Company is subject to certain covenants
under the terms of the Credit Facility, including requirements to maintain
specified tangible capital and a ratio of cash flow to debt service coverage of
at least 1.25 to 1.00. The Credit Facility also places restriction on
dividends, additional indebtedness, liens, sales of properties and other
matters.
During March 1997, the outstanding balance under the Credit Facility of
$11.0 million was repaid with proceeds from the Offering. The Credit Facility
remains available for future borrowings under similar terms, but the borrowing
base has been reduced at the Company's request to $1 million so as to limit
expenses. However, the Company has the ability to restore availability subject
to the provisions of the Credit Facility. As of March 1998 the Company is
negotiating a new credit facility with a group of banks. The Company expects to
have the new facility available for use during the second quarter of 1998 and
believes that the availability under the facility in conjunction with cash flows
from operations will be sufficient to fund current working capital requirements,
general corporate needs and planned 1998 capital expenditures.
SUBORDINATED LOAN
In December 1994, the Joint Venture entered into an agreement providing for
a subordinated loan. Such agreement provided for a $1 million term loan and a
$1 million line of credit. The Company borrowed $1 million under the provisions
of the term loan and $300,000 under the line of credit. During March 1997, the
outstanding balance of $1.3 million was repaid with proceeds from the Offering
and the subordinated loan agreement was discharged.
EQUIPMENT LOANS
Prior to the Offering, the Company was a party to various equipment loans
with lenders to acquire computer and related office equipment. These loans had
various terms and maturities. During March 1997, all but $32,000 of the
outstanding balance of $412,000 was repaid with proceeds from the Offering with
the remaining loan balance repaid during 1997 with cash flows from operations.
34
<PAGE>
YEAR 2000
The Company has evaluated the impact of the year 2000 processing issues
considering all current financial and accounting, production, land and
geological computer systems and software utilized by the Company. The Company
is in the process of replacing its existing financial and accounting, production
and land applications with software which is year 2000 compliant. Implementation
is expected to be completed on or before June 30, 1998 at a total cost of
approximately $200,000. The Company believes its geological systems and software
are year 2000 compliant. The Company currently anticipates that it will not
incur a material disruption of operations relating to year 2000 processing
issues but there can be no assurance that the Company will not incur unexpected
year 2000 costs or may not be adversely affected by year 2000 issues of its
suppliers, customers and other entities.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
The requirements of ITEM 7A. under regulations of the Securities and
Exchange Commission are not required or are not applicable and therefore have
been omitted.
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 AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
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 1998 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, 1997. Pursuant
to Item 401 (b) of regulation S-K certain of the information required by this
item with respects to executive officers of the Company is set forth in Part I
of this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by ITEM 11. will be contained in the Proxy
Statement under the heading "Executive Compensation and Other Information" and
is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by ITEM 12. will be contained in the Proxy
Statement under the heading "Security Ownership of Management and Certain
Beneficial Owners" and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTION
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.
35
<PAGE>
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial Statements and Schedules:
1. Financial Statements: See Index to the Consolidated Financial Statements and
Supplementary Information immediately following the signature page of this
report.
2. Financial Statement Schedule: See Index to the Consolidated Financial
Statements and Supplementary Information immediately following the signature
page of this report.
3. Exhibits: The following documents are filed as exhibits to this report.
+2.1 -- Amended and Restated Combination Agreement by and among (i) Edge Group
II Limited Partnership, (ii) Gulfedge Limited Partnership, (iii) Edge
Group Partnership, (iv) Edge Petroleum Corporation, (v) Edge Mergeco,
Inc. and (vi) the Company, dated as of January 13, 1997 (Incorporated
by reference from exhibit 2.1 to the Company's Registration Statement
on Form S-4 (Registration No. 333-17269))
+3.1 -- Restated Certificate of Incorporated of the Company, as amended
(Incorporated by reference from exhibit 3.1 to the Company's
Registration Statement on Form S-4 (Registration No. 333-17269)).
+3.2 -- Bylaws of the Company (Incorporated by reference from exhibit 3.2 to
the Company's Registration Statement on Form S-4 (Registration No.
333-17269)).
+4.1 -- Credit Agreement, as amended, dated as of July 11, 1995, between Edge
Joint Venture II and Compass Bank--Houston, as lender (Incorporated by
reference from exhibit 4.3 to the Company's Registration Statement on
Form S-4 (Registration No. 333-17269)).
+4.2 -- Security Agreements, as amended, dated as of July 11, 1995 of Edge
Joint Venture II in favor of Compass Bank--Houston (Incorporated by
reference from exhibit 4.4 to the Company's Registration Statement on
Form S-4 (Registration No. 333-17269)).
-- 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.
+10.1 -- Joint Venture Agreement between Edge Joint Venture II and Essex
Royalty Limited Partnership II, dated as of May 10, 1994 (Incorporated
by reference from exhibit 10.2 to the Company's Registration Statement
on Form S-4 (Registration No. 333-17269)).
+10.2 -- Joint Venture Agreement between Edge Joint Venture II and Essex
Royalty Limited Partnership, dated as of April 11, 1992 Incorporated
by reference from exhibit 10.3 to the Company's Registration Statement
on Form S-4 (Registration No. 333-17269)).
+10.3 -- Registration Rights Agreement between Edge Holding Company Limited
Partnership and the Company (Incorporated by reference from exhibit
10.6 to the Company's Registration Statement on Form S-4 (Registration
No. 333-17269)).
+10.4 -- 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)).
+10.5 -- Incentive Plan of Edge Petroleum Corporation (Incorporated by
reference from exhibit 10.3 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 1997).
+10.6 -- Employment Agreement dated February 25, 1997 between Edge Petroleum
Corporation and John E. Calaway (Incorporated by reference from
exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the
quarter ended June 30, 1997).
+10.7 -- 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).
+10.8 -- Employment Agreement between the Company and Michael G. Long
Incorporated by reference from exhibit 10.10 to the Company's
Registration Statement on Form S-4 (Registration No. 333-17269)).
36
<PAGE>
+10.9 -- Purchase Agreement between the Company and James C. Calaway dated as
of December 2, 1996 (Incorporated by reference from exhibit 10.11 to
the Company's Registration Statement on Form S-4 (Registration No.
333-17269)).
+10.10 -- 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)).
+10.11 -- 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)).
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, 1997 (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, 1997.
37
<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 3/31/98 /S/ JOHN E. CALAWAY
----------------------------------------
John E. Calaway
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 3/31/98 /S/ JOHN E. CALAWAY
----------------------------------------
John E. Calaway
Chief Executive Officer and
Chairman of the Board
Date 3/31/98 /S/ JAMES D. CALAWAY
----------------------------------------
James D. Calaway
President and Director
Date 3/31/98 /S/ MICHAEL G. LONG
----------------------------------------
Michael G. Long
Chief Financial Officer
Date 3/31/98 /S/ BRIAN C. BAUMLER
----------------------------------------
Brian C. Baumler
Controller and Treasurer
Date 3/31/98 /S/ VINCENT ANDREWS
----------------------------------------
Vincent Andrews
Director
Date 3/31/98 /S/ DAVID B. BENEDICT
----------------------------------------
David B. Benedict
Director
Date 3/31/98 /S/ NILS P. PETERSON
----------------------------------------
Nils P. Perterson
Director
Date 3/31/98 /S/ STANLEY S. RAPHAEL
----------------------------------------
Stanley S. Raphael
Director
Date 3/31/98 /S/ JOHN SFONDRINI
----------------------------------------
John Sfondrini
Director
Date 3/31/98 /S/ ROBERT W. SHOWER
----------------------------------------
Robert W. Shower
Director
38
<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, 1997 and 1996......... F-3
Consolidated Statements of Operations for the Years Ended
December 31, 1997, 1996 and 1995.................................... F-4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995.................................... F-5
Consolidated Statements of Stockholders' Equity (Deficit) for the
Years Ended December 31, 1997, 1996 and 1995........................ F-6
Notes to Consolidated Financial Statements........................... F-7
Unaudited Information:
Supplementary Information to Consolidated Financial Statements....... F-17
CONSOLIDATED FINANCIAL STATEMENT SCHEDULE
NONE
All other schedules for which provision is made in the applicable
accounting regulations of the Securities and Exchange Commission are not
required under the related instructions or are inapplicable and therefore have
been omitted.
F-1
<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, 1997 and
1996, and the related consolidated statements of operations, stockholders'
equity (deficit) and cash flows for each of the three years in the period ended
December 31, 1997. 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, 1997 and 1996,
and the results of its operations and its cash flows for the years then ended in
conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Houston, Texas
March 6, 1998
F-2
<PAGE>
<TABLE>
<CAPTION>
EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
- ---------------------------------------------------------------------------------------------------------------------------------
DECEMBER 31, DECEMBER 31,
1997 1996
------------ ------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 3,777,950 $ 1,543,228
Accounts receivable, trade 2,394,497 2,038,889
Accounts receivable, joint interest owners, net 6,547,619 2,659,025
Receivables from related parties 385,192 186,562
Other current assets 352,571 114,456
----------- -----------
Total current assets 13,457,829 6,542,160
PROPERTY AND EQUIPMENT, Net - full cost method of accounting for oil and gas properties 36,662,521 11,989,241
DEFERRED OFFERING COSTS 1,006,379
INVESTMENT IN FRONTERA 3,628,264
OTHER ASSETS 17,232 18,320
----------- -----------
TOTAL ASSETS 53,765,846 19,556,100
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
CURRENT LIABILITIES:
Accounts payable, trade 4,794,037 2,502,024
Accounts payable to related parties 40,000 1,372,450
Accrued interest payable 74,354
Accrued liabilities 1,020,645 1,602,881
Current portion of notes payable 300,058
------------ -----------
Total current liabilities 5,854,682 5,851,767
------------ -----------
NOTES PAYABLE 11,561,844
DEFERRED INCOME TAXES 248,673
MINORITY INTEREST 2,267,185
------------ -----------
Total liabilities 5,854,682 19,929,469
------------ -----------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY (DEFICIT):
Preferred stock, $.01par value; 5,000,000 shares authorized; none outstanding
Common stock, $.01par value; 25,000,000 shares authorized; 7,760,869 shares
issued and outstanding 77,609
Additional paid-in capital 47,629,822
Retained earnings 3,825,009
Unearned compensation - restricted stock (3,621,276)
Deficit of predecessor entities (373,369)
------------ -----------
Total stockholders' equity (deficit) 47,911,164 (373,369)
------------ -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT) $ 53,765,846 $19,556,100
============ ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-3
<PAGE>
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------
1997 1996 1995
------------ ---------- ------------
<S> <C> <C> <C>
OIL AND NATURAL GAS REVENUES $ 13,468,042 $ 7,719,478 $ 2,040,446
OPERATING EXPENSES:
Oil and natural gas operating expenses 2,330,648 1,600,085 686,438
Depletion, depreciation, and amortization 2,875,457 1,613,022 813,402
General and administrative expenses 4,641,374 2,752,562 2,483,560
Unearned compensation expense 513,393
------------ ----------- -----------
Total operating expenses 10,360,872 5,965,669 3,983,400
------------ ----------- -----------
OPERATING INCOME (LOSS) 3,107,170 1,753,809 (1,942,954)
OTHER INCOME AND (EXPENSE):
Interest expense (183,028) (858,663) (315,342)
Interest income 900,867
Other Income 232,500
Gain on sale of oil and gas property 3,337,076
------------ ----------- -----------
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST 3,825,009 1,127,646 1,078,780
INCOME TAX EXPENSE (394,675) (397,088)
MINORITY INTEREST (432,786) (575,811)
------------ ----------- -----------
NET INCOME $ 3,825,009 $ 300,185 $ 105,881
============ =========== ===========
PRO FORMA BASIC EARNINGS PER SHARE $ 0.53 $ 0.06 $ 0.02
============ =========== ===========
PRO FORMA DILUTED EARNINGS PER SHARE $ 0.52 $ 0.06 $ 0.02
============ =========== ===========
PRO FORMA BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 7,274,617 4,701,361 4,701,361
============ =========== ===========
PRO FORMA DILUTED WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING 7,320,400 4,701,361 4,701,361
============ =========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE>
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------
1997 1996 1995
---------- ------------ -----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 3,825,009 $ 300,185 $ 105,881
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depletion, depreciation and amortization 2,875,457 1,613,022 813,402
Gain on sale of oil and natural gas property (3,337,076)
Deferred income taxes 394,675 397,088
Unearned compensation expense 513,393
Minority interest 432,786 575,811
Changes in assets and liabilities:
Accounts receivable, trade (355,608) (870,969) 60,098
Accounts receivable, joint interest owners, net (3,888,594) (2,325,473) (213,300)
Receivable from related parties (198,630) (60,618) (23,324)
Other current assets (238,115) (54,105) 16,778
Other assets 1,088 (41,133)
Accounts payable, trade 2,292,013 1,357,616 420,257
Accounts payable to related parties 66,623 266,490
Accrued interest payable (74,354) 27,936 12,996
Accrued liabilities (606,292) 1,442,388 50,818
Long-term liability (46,245) (31,557)
----------- ------------ -----------
Net cash provided by (used in) operating activities 4,145,367 2,277,821 (926,771)
----------- ------------ -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of prospects and property and equipment (29,874,155) (10,466,754) (8,511,991)
Proceeds from the sale of prospects and oil and natural gas properties 2,325,418 4,815,779 7,358,189
Investment in Frontera (3,628,264)
----------- ------------ -----------
Net cash used in investing activities (31,177,001) (5,650,975) (1,153,802)
----------- ------------ -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable 867,350 5,987,000 313,131
Payment on notes payable (11,017,348) (249,070) (83,691)
Proceeds from long-term notes payable 5,300,000
Payment on long-term notes payable (411,904) (3,582,955)
Payment on related party subordinated loans (1,300,000)
Net proceeds from issuance of common stock 41,028,258
Net proceeds from exercise of common stock options 100,000
Treasury stock transactions (16,000) (14,000)
Deferred offering cost (1,006,379)
----------- ------------ -----------
Net cash provided by financing activities 29,266,356 4,715,551 1,932,485
----------- ------------ -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 2,234,722 1,342,397 (148,088)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 1,543,228 200,831 348,919
----------- ------------ -----------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 3,777,950 $ 1,543,228 $ 200,831
=========== ============ ===========
SUPPLEMENTAL CASH FLOW DISCLOSURES - Cash paid for interest $ 257,382 $ 844,849 $ 307,510
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 $ - $ -
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE>
<TABLE>
<CAPTION>
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (DEFICIT)
- -----------------------------------------------------------------------------------------------------------------------------
Old Edge
Common Stock Common Stock Additional
----------------- ----------------- Paid-in Treasury Retained
Shares Amount Shares Amount Capital Stock Earnings
------- ------ --------- ------ ---------- -------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE,
JANUARY 1, 1995 105,263 $ 1,053 $ 634,695 $ (12,000) $(1,373,183)
Treasury stock purchase, 422 shares (28,000)
Issuance of treasury stock, 211 shares 14,000
Net income 105,881
------- ------ --------- -------- ---------- -------- ------------
BALANCE,
DECEMBER 31, 1995 105,263 1,053 634,695 (26,000) (1,267,302)
Treasury stock purchase, 422 shares (32,000)
Issuance of treasury stock, 211 shares 16,000
Net income 300,185
------- ------ --------- -------- ---------- -------- ------------
BALANCE,
DECEMBER 31, 1996 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 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
======= ====== ========= ======== ========== ======== ============
Unearned
Compensation- Total
Restricted Stockholders'
Stock Equity
-------------- -------------
<S> <C> <C>
BALANCE,
JANUARY 1, 1995 $ (749,435)
Treasury stock purchase, 422 shares (28,000)
Issuance of treasury stock, 211 shares 14,000
Net income 105,881
----------- -----------
BALANCE,
DECEMBER 31, 1995 (657,554)
Treasury stock purchase, 422 shares (32,000)
Issuance of treasury stock, 211 shares 16,000
Net income 300,185
----------- -----------
BALANCE,
DECEMBER 31, 1996 (373,369)
Combination 3,599,635
Public 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
=========== ===========
</TABLE>
See accompanying notes to the consolidated financial statements.
F-6
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
THE COMBINATION TRANSACTIONS - Edge Petroleum Corporation, a Delaware
corporation (the "Company") was incorporated in August 1996. Effective February
25, 1997, in a series of "Combination Transactions" or (the "Combination") the
Company completed (i) a merger of Edge Petroleum Corporation, a Texas
corporation ("Old Edge"), with Edge Mergeco, Inc, a wholly owned subsidiary of
the Company organized for this purpose, in which the shareholders of Old Edge
received Common Stock of the Company (the "Common Stock"), (ii) an exchange
offer to the general and limited partners of Edge Group II Limited Partnership
("Edge Group II") in which such partners exchanged their interests in Edge
Group II for Common Stock, (iii) an exchange offer to the limited partners of
Gulfedge Limited Partnership ("Gulfedge"), of which Old Edge was the general
partner, in which such limited partners exchanged their interests in Gulfedge
for Common Stock, (iv) a purchase from Edge Group Partnership ("Edge Group
Partnership") of its interest in the Edge Joint Venture II (the "Joint
Venture"), for consideration consisting of Common Stock and (v) an exchange of
interests in certain oil and natural gas properties held by Mr. James C. Calaway
(the "Calaway Interests") for Common Stock. Upon consummation of the
Combination Transactions, the Company acquired directly or indirectly all of the
interest in the Joint Venture and the Calaway Interests (the "Combined Assets").
The Company issued an aggregate of 4,701,363 shares of Common Stock in the
combination.
In March 1997, the Company completed its initial public offering (the
"Offering") issuing 2,760,000 shares of Common Stock at public offering price
$16.50 per share. The Offering provided the Company with proceeds of
approximately $40 million, net of expenses.
PRINCIPLES OF COMBINATION - The Combination was accounted for as a
reorganization pursuant to Staff Accounting Bulletin 47 due to the high degree
of common ownership among the combining entities and only equity ownership
interests in the entities being exchanged. Accordingly, the consolidated
accounts as of and for the year ended December 31, 1996 and for the year ended
December 31, 1995, are presented using the historical costs and results of
operations of the affiliated entities as if such entities had always been
combined. All intercompany balances were eliminated upon the combination and
all assets and liabilities were assumed by the Company. Accordingly, historical
transactions consummated by the Joint Venture, Old Edge, Edge Group II and
Gulfedge are individually and or collectively referred to herein as transactions
of the Company.
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements as of and
for the year ended December 31, 1997 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.
The consolidated financial statements as of and for the year ended December
31, 1996 and for the year ended December 31, 1995 include the accounts of Old
Edge and the Joint Venture, both of which share common ownership and management.
The Joint Venture, a general partnership, was formed by Old Edge, Edge Group II,
Edge Group Partnership and Gulfedge. The Joint Venture interests not owned by
Old Edge are recorded as minority interest.
NATURE OF OPERATIONS - The Company is an independent energy company engaged
in the exploration, development and production of oil and natural gas. The
Company conducts its operations primarily along the onshore United States Gulf
Coast, with its primary emphasis in South Texas and Louisiana where it currently
controls interest in excess of 219,000 gross acres. 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.
Subsequent to the combination, the Company in a series of transactions,
combined the Joint Venture, Old Edge, Edge Group II and Gulfedge into Edge
Petroleum Exploration Company, a wholly-owned subsidiary of the Company.
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.
F-7
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
OIL AND GAS PROPERTY - Investments in oil and natural gas properties are
accounted for using the full cost method of accounting. All costs associated
with the acquisition, exploration and development of oil and natural gas
properties are capitalized.
Oil and natural gas properties are amortized using the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the prospects
can be determined or until impairment occurs. If the results of an assessment
indicates that a 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, 1997,
1996 and 1995 were $0.47, $0.45 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 cost
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 cost 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. During the three years ended December 31, 1997, no
impairment of the Company's oil and natural gas properties was deemed necessary.
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.
The Company's earnings for the three years ended December 31, 1997, were
not subject to corporate income taxes as a result of the Company's ability to
utilize available net operating loss carryforwards ("NOL's"), and other net
deferred tax assets. Such NOL's and net deferred tax assets, which were
previously reserved for, have been substantially utilized as of December 31,
1997, and should the Company have taxable income in future periods a provision
for tax expense will be provided.
From inception through February 24, 1997, except for Old Edge, the owners
of interests in the Joint Venture were not required to pay federal income taxes
due to their status as "pass-through" entities that are not subject to federal
income taxation; instead, taxes relating to the taxable income of the Joint
Venture for such periods were required to be paid by the owners of such
entities. Although the effective date of the Combination is February 25, 1997,
each owner of interests in the Joint Venture (or holders of interests in such
owners that are "pass through" entities) was required to include in its taxable
income, for all periods ending on the date of or prior to the completion of the
Combination, its allocable portion of the taxable income attributable to the
Joint Venture and is entitled to all tax benefits attributable to the Joint
Venture through completion of the Combination.
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 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 natural gas it also limits
F-8
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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. Effective
October 1, 1997, and continuing through January 31, 1998, the Company had in
place a natural gas commodity collar with a financial institution covering 5,000
MMbtus per day, or approximately 30% of the Company's daily production. Prices
received float between a floor price of $2.50 per MMbtu and a cap price of $3.15
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. Total natural gas production marketed
under this arrangement was 460,000 MMbtu for the year ended December 31, 1997.
Included within natural gas revenues for the year ended December 31, 1997 was
$33,150 representing a net gain from current collar activity. Subsequent to
December 31, 1997, the Company has entered into two additional collar
arrangements with a financial institution that begin February 1, 1998 and April
1, 1998, respectively, and expire on April 30, 1998 and June 30, 1998,
respectively. These collar arrangements cover 5,000 MMbtus per day with floating
floor and ceiling prices ranging between $2.15 and $2.75 per MMbtu. There was no
material hedging activity during the years ended December 31, 1996 and 1995.
STATEMENTS OF CASH FLOWS - The consolidated statements of cash flows are
presented using the indirect method and consider all highly liquid investments
with original maturities of three months or less to be cash equivalents.
INVESTMENT IN FRONTERA - During 1997, the Company made an investment in
Frontera Resources Corporation ("Frontera") through the purchase of 15,171
shares of Series D Preferred Stock for $3.6 million. The Series D Preferred
stock is convertible into approximately 10% of the fully diluted outstanding
Common Stock (excluding employee stock options) as of December 31, 1997.
Frontera began operations in 1996 and is a privately held international energy
company that is seeking to develop upstream and downstream energy projects in
emerging international markets. Currently, Frontera is pursuing projects in the
Republic of Georgia, Azerbeaijan and Bolivia. The investment is recorded under
the cost method of accounting, which allows for an investment to be carried at
cost unless there are underlying circumstances that would cause the asset to be
impaired. As of December 31, 1997, the cost of the investment in Frontera
approximates fair value, and accordingly no write-down of the asset has been
recorded.
STOCK-BASED COMPENSATION - In fiscal year 1997, the Company adopted 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 7).
PRO FORMA NET INCOME PER SHARE - Pro forma net income per share is based on
the weighted average number of shares of Common Stock outstanding during the
period. The computation assumes that the Company was incorporated during the
periods presented and that the shares issued in connection with the Combination
were outstanding for all periods. Pro forma net income per share has been
computed based on net income as disclosed in the Consolidated Statements of
Operations and assuming the 4,701,361 shares of Common Stock issued in
connection with the Combination were outstanding since January 1, 1993.
EARNINGS PER SHARE - During 1997, the Company implemented 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 having
exercise prices less than the average market price of the common stock using the
treasury stock method. The earnings per share data for prior years has been
restated following the standards in SFAS No. 128.
FINANCIAL INSTRUMENTS - The Company's financial instruments consist of cash,
receivables, payables, long-term debt and natural gas commodity hedges. The
carrying amount of cash, receivables and payables approximates fair
F-9
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
value because of the short-term nature of these items. The carrying amount of
long-term debt as of December 31, 1996 approximates fair value as all such
amounts were repaid during 1997. The carrying amount of the Company's natural
gas commodity hedges approximates fair value based on the expected settlement
amount of these transactions as of December 31, 1997.
USE OF ESTIMATES - The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities as of the date of the financial
statements and the reported amounts of revenue and expenses during the reporting
periods. Actual results could differ from these estimates.
CONCENTRATION OF CREDIT RISK - Substantially all of the Company's accounts
receivable result from oil and natural gas sales or joint interest billings to
third parties in the oil and natural gas industry. This concentration of
customers and joint interest owners may impact the Company's overall credit risk
in that these entities may be similarly affected by changes in economic and
other conditions. Historically, the Company has not experienced credit losses
on such receivables.
RECLASSIFICATIONS - Certain prior year balances have been reclassified to
conform to the current year presentation.
2. PROPERTY AND EQUIPMENT
At December 31, 1997 and 1996, property and equipment consisted of the
following:
<TABLE>
<CAPTION>
1997 1996
------------ -----------
<S> <C> <C>
Oil and natural gas properties $ 16,100,052 $ 9,975,074
Unproved oil and natural gas properties 22,937,927 3,884,966
Computer equipment and software 3,238,182 1,819,080
Other office property and equipment 1,225,183 194,933
------------ -----------
Total property and equipment 43,501,344 15,874,053
Accumulated depletion, depreciation and amortization (6,838,823) (3,884,812)
------------ -----------
Property and equipment, net $ 36,662,521 $11,989,241
============ ===========
</TABLE>
Oil and natural gas properties not subject to amortization consist of the
cost of unproved 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:
<TABLE>
<CAPTION>
December 31,
-----------------------------------
1997 1996
------------- -----------
<S> <C> <C>
Year cost incurred:
Remainder $ 213,022 $ 513,679
1994 133,088 564,789
1995 454,716 551,205
1996 1,675,038 2,255,293
1997 20,462,063
----------- ----------
Total $22,937,927 $3,884,966
=========== ==========
</TABLE>
F-10
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 provides up to $20,000,000 in
borrowings limited by a borrowing base (as defined by the Revolving Credit
Facility) which was $11,175,000 at December 31, 1996. At December 31, 1996,
borrowings outstanding under the Revolving Credit Facility totaled $10,150,000.
The Revolving Credit Facility provides for interest at the lender's prime rate
plus 0.75% (9.0% at December 31, 1996). The borrowing base is subject to review
by the bank on a quarterly basis and may be adjusted subject to the provisions
of the Revolving Credit Facility. On March 3, 1997 the Company repaid the
outstanding balance of $11,091,449 and accrued interest on such debt with
proceeds from the Offering. The Revolving Credit Facility remains available for
future borrowings with similar terms, but the borrowing base has been reduced to
$1 million so as to limit expenses. However, the Company has the ability to
restore availability subject to the provisions of the Revolving Credit Facility.
In January 1995 the Company entered into a Subordinated Loan Agreement with a
shareholder of Old Edge. The agreement provided for a $1 million term loan and
a $1 million line of credit. Interest at 10% per annum was due monthly. On
March 3, 1997 the Company repaid the outstanding balance of $ 1,300,000 and
accrued interest on such debt with proceeds from the Offering.
During March 1997, the Company repaid all but $32,000 of the $412,000 of
outstanding equipment loan balances with proceeds from the Offering, with the
remaining loan balance being repaid during 1997 with cash flows from operations.
At December 31, 1996, notes payable and long-term debt consisted of the
following:
<TABLE>
<S> <C>
Revolving credit facility, lenders' prime rate plus 0.75%, interest
payable monthly, maturing June 1, 1998 $10,150,000
Note payable to bank, lenders' prime rate plus 0.75%, payable in
monthly principal installments of $ 7,500 plus accrued
interest, matures March 1, 1997 90,000
Note payable to bank, lenders' prime rate plus 1.5%, payable in
monthly principal installments of $5,547 plus accrued
interest, matures March 1, 1997 16,642
Note payable, 10.996% interest, payable in monthly installments
of principal and interest of $2,326, matures June 22, 1998 38,470
Note payable, lenders' prime rate plus 0.75%, payable in monthly
principal installments of $14,042 plus accrued interest,
matures July 1, 1998 266,790
Subordinate note payable to a shareholder of the Company, 10%
interest, interest payable monthly, matures April 8, 1998 1,300,000
-----------
Total 11,861,902
Current portion (300,058)
-----------
Long-term portion $ 11,561,844
============
</TABLE>
There were no outstanding notes payable or long-term debt at December 31,
1997.
4. 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
F-11
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 the 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, 1997, the Company was obligated under a noncancelable
operating lease for office space. Following is a schedule of the remaining
future minimum lease payments under this lease:
1998 $ 263,256
1999 267,957
2000 267,957
2001 267,957
2002-2003 312,616
------------
Total $ 1,379,743
============
Rent expense for the years ended December 31, 1997, 1996 and 1995 was
$214,143, $204,376 and $165,317, respectively.
5. INCOME TAXES
Deferred income taxes reflect the tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts calculated for income tax purposes in accordance with
SFAS No. 109.
Significant components of the Company's deferred tax liabilities and assets
as of December 31, 1997 and 1996 are as follows:
<TABLE>
<CAPTION>
1997 1996
---------------- ---------------
<S> <C> <C>
Deferred tax liability:
Book basis of oil and gas properties in excess of tax basis $2,246,201
Loss allowed for tax purposes in excess of book
loss from Old Edge's partnership interest in
the Joint Venture $ 920,119
Other 538
----------- ---------------
Total 2,246,201 920,657
Deferred tax asset:
Tax basis of oil and gas properties in excess of book basis 2,046,680
Net operating laoss carryforwards 620,033
Statutory depletion carry forward 140,390
Other 59,131 51,951
----------- ---------------
Total 2,246,201 671,984
----------- ---------------
Net deferred tax liability $ - $ 248,673
=========== ===============
</TABLE>
F-12
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The differences between the federal income taxes calculated at the
statutory rate and the Company's income tax expense is summarized as follows:
<TABLE>
<CAPTION>
1997 1996 1995
------------ ----------- ----------
<S> <C> <C> <C>
Statutory federal income taxes $ 1,338,753 $ 394,675 $ 377,575
Non-statutory stock options (224,617)
Income not taxable to the Company (66,961)
Expense not deductible for tax purposes 10,483 7,546 19,513
Net tax assets of acquired entities (1,057,658)
Change in valuation allowance (7,546)
----------- --------- ---------
Income tax expense $ - $ 394,675 $ 397,088
=========== ========= ==========
</TABLE>
The Company's unrecognized net deferred tax assets have been substantially
utilized as of December 31, 1997, and should the Company have taxable income in
future periods, a provision for tax expense will be provided.
Pro forma provision for income taxes for the years ended December 31, 1997,
1996 and 1995 has been presented to reflect the Company's income taxes that
would have been reported had the Company owned all of the interests in the Joint
Venture since inception (April 8, 1991).
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Income before income taxes $ 3,825,009 $ 1,127,646 $ 1,078,780
Income tax at statutory rate $ 1,338,753 $ 394,675 $ 377,575
Non-deductible items 10,483 7,546 19,513
Income not taxable to the Company (66,961)
Non-statutory stock options (224,617)
Net tax assets of acquired entities (1,057,658)
Change in valuation allowance (402,221) (397,088)
----------- ----------- -----------
Pro forma net income $ 3,825,009 $ 1,127,646 $ 1,078,780
=========== =========== ===========
Pro forma basic earnings per share $ 0.53 $ 0.24 $ 0.23
Pro forma diluted earnings per share $ 0.52 $ 0.24 $ 0.23
Pro forma weighted average number
of common shares outstanding 7,274,617 4,701,361 4,701,361
Pro forma weighted average number
of common shares outstanding 7,320,400 4,701,361 4,701,361
</TABLE>
6. 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 year ended December 31, 1997 the Company
contributed $40,954 to the Plan.
7. EQUITY AND STOCK PLANS
On March 3, 1997 the Combination Transactions were consummated resulting in
the issuance of 4,701,363 shares to the predecessor owners of the Combined
Assets (See Note 1). In addition, during March 1997, the Company completed its
Offering issuing 2,760,000 shares at $16.50 per share. Net proceeds totaled $40
million, net of offering cost of approximately $5.4 million.
F-13
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 3-10 years. An aggregate of 1,000,000 shares of Common
Stock have been reserved for grants under the Incentive Plan, of which 101,971
shares were available for future grants at December 31, 1997 (these shares
include only those as issued under the Incentive Plan). Shares of Common Stock
awarded as restricted stock are subject to restrictions on transfer and subject
to risk forfeiture until earned by continued employment or service or
achievement of certain performance milestones. During 1997, 250,586 shares of
restricted stock were awarded having a market value of $16.50 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
shareholders' equity. The unearned compensation-restricted stock is amortized to
operations over the related vesting period. Such unearned compensation expense
amounted to $ 513,393 in 1997.
In addition, as of the date of the Combination Transactions, 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 Transactions, 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 such 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.
A summary of the status of the Company's stock options and changes as of
and for the year ended December 31, 1997 are presented below:
1997
---------------------------------------
Weighted Avg.
Shares Exercise Price
----------------- ---------------------
Outstanding, January 1 -
Granted 773,040 $ 14.80
Forfeited (27,753) 16.50
Exercised (48,922) 2.04
---------
Outstanding, December 31 696,365 $ 15.63
=========
Exercisable, December 31 48,922 $ 4.09
======
<TABLE>
<CAPTION>
Options Outstanding as of December 31, 1997 Options Exercisable
------------------------------------------------------- ------------------------------
Weighted
Average Weighted Weighted
Range of Shares Remaining Average Shares Average
Exercise Price Outstanding Contractual Life Exercise Price Exercisable Exercise Price
-------------- ----------- ---------------- -------------- ----------- --------------
<S> <C> <C> <C> <C> <C>
$4.09 48,922 - $ 4.09 48,922 $ 4.09
$16.50 696,365 4.9 $ 16.50 - -
</TABLE>
F-14
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 year ended December 31, 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") adapted for the use in valuing stock
options. The estimated values under the Model are based on the following
assumptions: expected volatility based on historical volatility of daily Common
Stock Prices (41%), 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 (with the exercise
occurring at the end of such period) and a forfeiture rate of 10% over the
vesting period of such options.
1997
----------
Net Income:
As reported $ 3,825,009
Pro forma 3,454,671
Earnings Per Share:
Basic as reported $ 0.53
Diluted as reported 0.52
Pro forma basic $ 0.22
Pro forma diluted 0.22
The following is presented as a reconciliation of the numerators and
denominators of basic and diluted earnings per share computations, in accordance
with SFAS No. 128.
Year Ended December 31, 1997
-------------------------------------
Income Shares Per-Share
(Numerator) (Denominator) Amount
----------- ------------- ----------
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
=========== ============= ==========
For the two years ended December 31, 1996 and 1995 there were no dilutive
stock options outstanding.
8. RELATED PARTY TRANSACTIONS
The Company incurred management fees from the general partners of Edge
Group II of $66,623 and $266,480 for the year ended December 31, 1996 and 1995,
respectively. Included in accounts payable to related party at December 31,
1996 was $1,332,450, representing accrued management fees due the general
partners. These fees were settled with the general partners of Edge Group II as
a component of the Edge Group II exchange offer executed February 25, 1997.
F-15
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 1997 and 1996, included in receivables from related
parties, was $85,681 and $26,889, representing amounts due from directors and
employees of the Company.
At December 31, 1996 the Company was liable to a shareholder of Old Edge
for $1,300,000 of notes payable. The respective liability was repaid during
March 1997 with proceeds from the Offering (See Note 3).
The Company receives revenue from various related parties for maintaining
certain oil and natural gas properties. Representation fees amounted to
$25,500, $30,000 and $24,000 for the three years ended December 31, 1997, 1996
and 1995, respectively. At December 31, 1997 and 1996, $20,624 and $10,188,
respectively, of representation fees due the Company were included in
receivables from related parties.
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 each of the three years ended December
31, 1997, the Company recorded management fees totaling $120,000, 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, 1997, 1996 and 1995 amounted to
$61,746, $67,000 and $40,250, respectively. At December 31, 1997 and 1996, the
Company had a receivable from the Essex Joint Ventures of $258,887 and $172,000,
respectively, relating to these management fees, direct expenses, and costs.
9. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED):
<TABLE>
<CAPTION>
4th 3rd 2nd 1st
Quarter Quarter Quarter Quarter
----------- --------- -------- --------
(in thousands except per share amounts)
<S> <C> <C> <C> <C>
1997
Revenues $ 3,810 $ 3,201 $ 3,016 $ 3,441
Operating expenses 3,172 2,451 2,525 2,213
Gross profit 638 750 491 1,228
Other income and expenses 134 266 615 (297)
Net income 772 1,016 1,106 931
Pro forma basic earnings per share $ 0.10 $ 0.13 $ 0.14 $ 0.16
Pro forma diluted earnings per share 0.10 0.13 0.14 0.16
1996
Revenues $ 2,614 $ 2,031 $ 1,797 $ 1,277
Operating expenses 1,848 1,460 1,121 1,537
Gross profit 766 571 676 (260)
Other income and (expenses) (313) (350) (317) (41)
Minority interest (344) (98) (199) 209
Net income (loss) 109 123 160 (92)
Pro forma basic earnings per share $ 0.02 $ 0.03 $ 0.03 $ (0.02)
Pro forma diluted earnings per share 0.02 0.03 0.03 (0.02)
</TABLE>
The sum of the individual quarterly pro forma net income per share amounts
may not agree with year-to-date pro forma net income 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.
F-16
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. 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 - 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:
<TABLE>
<CAPTION>
December 31,
------------------------------------------------
1997 1996 1995
----------- --------- ----------
<S> <C> <C> <C>
Oil and natural gas properties $ 16,100,052 $ 9,975,074 $ 7,085,245
Unproved oil and natural gas properties 22,937,927 3,884,966 1,944,552
Accumulated depletion, depreciation and
amortization (5,698,270) (3,210,838) (1,746,663)
------------ ------------ -----------
Net capitalized cost $ 33,339,709 $ 10,649,202 $ 7,283,134
------------ ------------ -----------
</TABLE>
COSTS INCURRED - Costs incurred in oil and natural gas property acquisition,
exploration and development activities are summarized below:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------
1997 1996 1995
---------- --------- ---------
<S> <C> <C> <C>
Acquisition Cost:
Unproved $17,659,706 $ 4,489,740 $ 3,658,573
Proved 91,025
Exploration costs 8,640,530 2,669,082 2,642,025
Development costs 1,207,771 2,342,831 1,149,548
----------- ----------- -----------
Gross costs incurred 27,508,007 9,501,653 7,541,171
Less proceeds from the sales of prospects 2,325,418 2,229,835 4,008,189
----------- ----------- -----------
Net cost incurred $25,182,589 $ 7,271,818 $ 3,532,982
----------- ----------- -----------
</TABLE>
Gross costs incurred excludes sales of proved and unproved oil and natural
gas properties which were 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:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------
1997 1996 1995
---------------------------------------------
<S> <C> <C> <C>
Oil and natural gas revenues $ 13,468,042 $ 7,719,478 $ 2,040,446
Oil and natural gas operating expenses 1,459,291 1,063,552 570,637
Production taxes 871,357 536,533 115,801
Depletion, depreciation and amortization 2,483,539 1,351,113 557,657
---------------------------------------------
Results of operations $ 8,653,855 $ 4,768,280 $ 796,351
---------------------------------------------
</TABLE>
RESERVES - Proved reserves are estimated quantities of oil and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods. Proved oil and natural gas reserve quantities
for the periods presented are based on estimates prepared by Ryder Scott
Company ("Ryder Scott"), independent petroleum engineers. Such estimates have
been prepared in accordance with guidelines established by the Securities and
Exchange Commission.
F-17
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. These
quantities include the minority interest in the Joint Venture as the Joint
Venture is consolidated with Old Edge for the years ended December 31, 1996 and
1995 (see Note 1).
<TABLE>
<CAPTION>
Natural Gas
(Mcf)
Year Ended December 31,
---------------------------------------------
1997 1996 1995
------------ ---------- ----------
<S> <C> <C> <C>
Proved developed and undeveloped reserves
Beginning of year 13,417,000 8,821,000 3,673,000
Revisions of previous estimates (5,397,141) (1,178,453) 277,863
Purchases of natural gas properties 1,047,000
Extensions and discoveries 25,402,000 8,154,000 6,247,000
Sales of natural gas properties (63,442) (1,910,962)
Production (4,298,859) (2,316,105) (512,901)
------------ ---------- ----------
End of Year 29,123,000 13,417,000 8,821,000
============ ========== ==========
Proved developed reserves at year end 17,866,000 11,301,000 6,692,000
============ ========== ==========
Minority interest:
Proved developed and undeveloped, end of year 9,517,483 6,257,265
========== ==========
Proved developed, end of year 8,016,477 4,747,037
========== ==========
</TABLE>
<TABLE>
<CAPTION>
Oil, Condensate and Natural Gas Liquids
(Bbls)
Year Ended December 31,
-----------------------------------------------
1997 1996 1995
---------- --------- ----------
<S> <C> <C> <C>
Proved developed and undeveloped reserves
Beginning of year 642,714 708,933 368,160
Revisions of previous estimates (147,917) (36,746) 156,687
Purchases of oil properties 6,275
Extensions and discoveries 537,029 245,703 278,268
Sales of oil properties (165,951) (36,572)
Production (165,640) (109,225) (63,885)
---------- --------- ----------
End of Year 866,186 642,714 708,933
========== ========= ==========
Proved developed reserves at year end 646,009 569,856 652,843
========== ========= ==========
Minority interest:
Proved developed and undeveloped, end of year 455,916 502,889
========= ==========
Proved developed, end of year 404,233 463,101
========= ==========
</TABLE>
F-18
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
STANDARDIZED MEASURE - The Standardized Measure of Discounted Future Net Cash
Flows ("Standardized Measure") relating to the Company's ownership interests in
proved oil and natural gas reserves for each of the three years ended December
31, 1997 is shown below:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1997 1996 1995
----------- ----------- ----------
<S> <C> <C> <C>
Future cash inflows $ 83,454,087 $ 63,446,170 $ 31,011,202
Future oil and natural gas operating expenses (16,228,391) (9,590,565) (5,906,519)
Future development costs (5,957,039) (982,603) (641,475)
Future income tax expenses (16,575,185) (13,797,568) (5,883,983)
------------ ------------ ------------
Future net cash flows 44,693,472 39,075,434 18,579,225
10% discount factor (13,450,819) (8,875,265) (4,633,593)
Standardized measure of discounted future ------------ ------------ ------------
net cash flows $ 31,242,653 $ 30,200,169 $ 13,945,632
------------ ------------ ------------
</TABLE>
The Standardized Measure reflects the consolidation of the Joint Venture
for the years ended December 31, 1996 and 1995. The minority interest's share of
Standardized Measure is $21,422,792 and $9,892,474, at December 31, 1996 and
1995, respectively.
The Standardized Measure and changes therein have been computed by Ryder
Scott as follows. Future cash in flows are based on the application of 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 based primarily on estimates prepared by the Company's petroleum
engineers and provided to Ryder Scott, of expenditures to be incurred in
developing and producing the Company's proved oil and natural gas reserves at
the end of the year, using year end costs and assuming the continuation of
existing economic conditions.
Future income taxes are based on year-end statutory rates. A discount
factor of 10% was used to reflect the timing of future net cash flows. The
Standardized Measure is not intended to represent the replacement cost or fair
market value of the Company's oil and natural gas properties.
The Standardized Measure 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 - Changes in Standardized Measure relating to
proved oil and gas reserves are summarized below:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1997 1996 1995
----------- ----------- ----------
<S> <C> <C> <C>
Changes due to current year operations:
Sales of oil and natural gas, net of oil and natural
gas operating expenses $(11,137,394) $ (6,358,807) $(1,354,008)
Sales of oil and natural gas properties (1,884,221) (3,113,415)
Extensions and discoveries 34,003,639 22,901,796 10,194,038
Purchases of oil and natural gas properties 540,345
Changes due to revisions in standardized variables:
Prices and operating expenses (15,703,096) 8,668,053 408,398
Revisions of previous quantity estimates (8,897,696) (2,970,834) 1,935,454
Estimated future development costs (4,974,436) (341,128) 62,740
Income taxes 3,116,093 (5,728,481) (2,330,338)
Accretion of discount 3,942,563 1,744,261 794,640
Production rates (timing) and other 692,811 223,898 27,926
----------- ----------- ----------
Net change 1,042,484 16,254,537 7,165,780
Beginning of year 30,200,169 13,945,632 6,779,852
----------- ----------- ----------
End of year $ 31,242,653 $ 30,200,169 $13,945,632
----------- ----------- ----------
</TABLE>
F-19
<PAGE>
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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-20
<PAGE>
EXHIBIT 21.1
SUBSIDIARIES OF THE COMPANY
Edge Petroleum Exploration Company (a Delaware corporation)
Edge Petroleum Operating Company, Inc. (a Texas corporation)
<PAGE>
EXHIBIT 23.1
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference in the Registration Statement of
Edge Petroleum Corporation, a Delaware corporation, (the "Company") on Form S-8
Registration No. 333-22571 of our report dated March 6, 1998, appearing in the
Annual Report on Form 10-K of the Company for the year ended December 31,
1997and to the reference to us under the heading "Experts" in such Registration
Statement.
/S/ DELOITTE & TOUCHE LLP
Houston, Texas
March 27, 1997
<PAGE>
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. 333-22571
of our summary report dated March 27, 1998 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 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 27, 1998
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 3,777,950
<SECURITIES> 0
<RECEIVABLES> 9,327,308
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 13,457,829
<PP&E> 43,501,344
<DEPRECIATION> (6,838,823)
<TOTAL-ASSETS> 53,765,846
<CURRENT-LIABILITIES> 5,830,626
<BONDS> 0
0
0
<COMMON> 77,609
<OTHER-SE> 47,833,555
<TOTAL-LIABILITY-AND-EQUITY> 53,765,846
<SALES> 0
<TOTAL-REVENUES> 13,468,042
<CGS> 0
<TOTAL-COSTS> 10,360,872
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 183,028
<INCOME-PRETAX> 3,825,009
<INCOME-TAX> 0
<INCOME-CONTINUING> 3,825,009
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 3,825,009
<EPS-PRIMARY> 0.53
<EPS-DILUTED> 0.52
</TABLE>
<PAGE>
EXHIBIT 99.1
March 27, 1998
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, 1997. 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 1997 hydrocarbon prices were
used in the preparation of this report as required by SEC guidelines; however,
actual future prices may vary significantly from December 1997 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, 1997
-------------------------------------------------
<TABLE>
<CAPTION>
Proved
-------------------------------------------------------------------------------
Developed
-------------------------------------- Total
Producing Non-Producing Undeveloped Proved
---------------- ------------------ ----------------- ----------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
- ----------------------
Oil/Condensate - Barrels 331,374 185,577 220,177 737,128
Plant Products - Barrels 70,797 58,261 0 129,058
Gas - MMCF 8,377 9,489 11,257 29,123
INCOME DATA
- -----------
Future Gross Revenue $24,541,573 $24,124,209 $28,955,851 $77,621,633
Deductions 4,877,720 3,841,482 7,633,774 16,352,976
---------- ---------- ---------- ----------
Future Net Income (FNI) $19,663,853 $20,282,727 $21,322,077 $61,268,657
Discounted FNI @ 10% $16,756,263 $11,089,209 $13,043,156 $40,888,628
</TABLE>
<PAGE>
Edge Petroleum Corporation
March 27, 1998
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 84 percent and liquid hydrocarbon reserves account for the
remaining 16 percent of total future gross revenue from proved reserves.
RESERVES INCLUDED IN THIS REPORT
- --------------------------------
The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission Staff Accounting Bulletins. The definition
of proved reserves is included in the section entitled "Definitions of Reserves"
which is attached with this report.
The proved developed non-producing reserves included herein are comprised
of shut-in and behind pipe categories. The various reserve status categories
are defined in the section entitled "Reserve Status Categories (SEC)" which is
attached with this report.
ESTIMATES OF RESERVES
In general, the reserves included herein were predominantly estimated
by the volumetric method due to the limited production history of the wells
considered in this study. However, performance methods were used in certain
cases where characteristics of the data indicated 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.
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.
<PAGE>
Edge Petroleum Corporation
March 27, 1998
HYDROCARBON PRICES
Edge furnished us with prices in effect at December 31, 1997 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, 1997 were not taken into account in
this report. Future prices used in this report are discussed in more detail in
the section entitled "Hydrocarbon Pricing Parameters" which is attached with
this report.
COSTS
Operating costs for the leases and wells in this report are based on the
operating expense reports of Edge and include only those costs directly
applicable to the leases or wells. When applicable, the operating costs include
a portion of general and administrative costs allocated directly to the leases
and wells under terms of operating agreements. 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.
GENERAL
While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may 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 November 1997.
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
PETROLEUM ENGINEERS
Michael F. Stell, P.E.
Vice President
<PAGE>
DEFINITIONS OF RESERVES
PROVED RESERVES (SEC DEFINITION)
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalation based on
future conditions.
Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. In certain
instances, proved reserves are assigned on the basis of a combination of core
analysis and electrical and other type logs which indicate the reservoirs are
analogous to reservoirs in the same field which are producing or have
demonstrated the ability to produce on a formation test. The area of a
reservoir considered proved includes (1) that portion delineated by drilling and
defined by fluid contacts, if any, and (2) the adjoining portions not yet
drilled that can be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of data on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls the
lower proved limit of the reservoir.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) successful testing by a pilot project or the
operation of an installed program in the reservoir provides support for the
engineering analysis on which the project or program was based, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Proved natural gas reserves are comprised of non-associated,
associated and dissolved gas. An appropriate reduction in gas reserves has been
made for the expected removal of natural gas liquids, for lease and plant fuel,
and for the exclusion of non-hydrocarbon gases if they occur in significant
quantities and are removed prior to sale. Estimates of proved reserves do not
include crude oil, natural gas, or natural gas liquids being held in underground
or surface storage.
Proved reserves are estimates of hydrocarbons to be recovered from a
given date forward. They may be revised as hydrocarbons are produced and
additional data become available.
<PAGE>
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,
1997 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, 1997 were not considered in this report.
PLANT PRODUCTS
Edge furnished us with plant product prices in effect at December 31, 1997
and these prices were held constant to depletion of the properties.
GAS
Edge furnished us with gas prices in effect at December 31, 1997 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, 1997 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.
