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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, 1998
Commission file number: 0-22149
EDGE PETROLEUM CORPORATION
(Exact name of Registrant as specified in its charter)
Delaware 76-0511037
(State or other jurisdiction of (I.R.S. Employer Identification
incorporation or organization) No.)
Texaco Heritage Plaza
1111 Bagby, Suite 2100
Houston, Texas 77002
(Address of principal executive offices) (Zip code)
713-654-8960
(Registrant's telephone number including area code)
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Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to section 12(g) of the Act:
Common Stock, Par Value $.01 Per Share
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. / /
The aggregate market value of the voting stock held by non-affiliates of the
Registrant at March 19, 1999, was $41,774,672 (based on a value of $5.375 per
share, the closing price of the Common Stock as quoted by NASDAQ National Market
on such date). 7,772,032 shares of Common Stock, par value $.01 per share, were
outstanding on March 19, 1999.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the registrant's 1999 Annual
Meeting of Shareholders, to be filed pursuant to Regulation 14A under the
Securities Exchange Act of 1934, are incorporated by reference into Part III of
this report.
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TABLE OF CONTENTS
PAGE
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PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES 2
ITEM 3. LEGAL PROCEEDINGS 26
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 26
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 28
ITEM 6. SELECTED FINANCIAL DATA 29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS 30
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK 41
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 41
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURES 41
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 41
ITEM 11. EXECUTIVE COMPENSATION 41
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 41
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 41
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K 42
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
222,000 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, high-
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 19.5
MMcfe in 1998. While experiencing this rapid growth, the Company has maintained
a low cost structure. At December 31, 1998, the Company's estimate of proved oil
and natural gas reserves consisted of 24.2 Bcf of natural gas and 445 MBbls of
oil. During 1998, the Company drilled 83 gross wells, (36.03 net wells) and
added proved reserves of 8.95 Bcfe, before oil and natural gas revisions and
production, representing a 125% replacement ratio of 1998 production of 7.1
Bcfe. At December 31, 1998, Edge's estimated proved reserves before income taxes
and discounted to present value at 10% per annum were $22.7 million, based on
SEC pricing at December 31, 1998 of $11.04 per Bbl of oil and $1.84 per Mcf of
natural gas.
2
EXPLORATION TECHNOLOGY
Since 1992, as a result of the advent of economic onshore 3-D seismic
surveys and the improvement and increased affordability of data interpretation
technologies, the Company has relied almost exclusively on the interpretation of
3-D seismic data in its exploration strategy. The principal advantage of 3-D
seismic data over 2-D seismic data is that it affords a geoscientist the ability
to investigate the entire prospective area using a 3-D seismic data volume, as
compared to the limited number of two dimensional profiles covering a small
percentage of the prospective area that are available using 2-D seismic data. As
a consequence, a geoscientist using 3-D seismic data is able to more fully
evaluate prospective areas and produce more accurate interpretations. The use of
structural maps based upon 3-D seismic data can significantly improve the
probability of drilling commercially successful wells, since this data allows
structurally advantageous positions to be more accurately located in highly
drilled exploration plays where only 2-D seismic data was used in the past.
The Company's methodology for interpreting 3-D seismic data has advanced
beyond traditional 3-D interpretation techniques, which consist of interpreting
multiple closely spaced 2-D profiles extracted from 3-D seismic volumes to
generate 3-D structural maps. The Company's advanced visualization and data
analysis techniques and resources enable its geoscientists to view 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 nine 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
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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.
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
4
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, 1998. 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, 1998. 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 received and
estimated development and production costs that were in effect during December
1998 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, 1998, see the reserve report included as
an exhibit to this Annual Report on Form 10-K (the "Ryder Scott Report"). The
present value of estimated future net revenues before income taxes was prepared
using constant prices as of the calculation date, discounted at 10% per annum on
a pretax basis, and is not intended to represent the current market value of the
estimated oil and natural gas reserves owned by the Company. For further
information concerning the present value of future net revenue from these proved
reserves, see Note 10 of Notes to the 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."
PROVED RESERVES
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DEVELOPED (1) UNDEVELOPED (2) TOTAL
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(DOLLARS IN THOUSANDS)
Oil and condensate (MBbls) (3)..................... 308 137 445
Natural gas (MMcf)................................. 15,844 8,391 24,235
Natural gas equivalents (MMcfe).................... 17,692 9,213 26,905
Estimated future net revenues before income
taxes............................................ $ 23,083 $ 11,346 $ 34,429
Present value of estimated future net revenues
before income taxes (discounted 10% annum) (4)... $ 16,647 $ 6,083 $ 22,730
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(1) Proved developed reserves are proved reserves which are expected to be
recovered from existing wells with existing equipment and operating methods.
(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, 1998, which were $1.84 per Mcf of natural gas and $11.04 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
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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, 1998. 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, 1998. There can be no assurance that all of the
proved reserves will be produced and sold within the periods indicated, that the
assumed prices will actually be realized for such production or that existing
contracts will be honored or judicially enforced.
VOLUMES, PRICES AND OIL AND NATURAL GAS OPERATING EXPENSE
The following table sets forth certain information regarding production
volumes, average sales prices and average oil and natural gas operating expense
associated with, the Company's sales of oil and natural gas for the periods
indicated.
YEAR ENDED DECEMBER 31,
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1998 1997 1996
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PRODUCTION:
Oil and Condensate (MBbls) (1)................................. 142 166 109
Natural gas (MMcf)............................................. 6,284 4,299 2,316
Natural gas equivalent (MMcfe)................................. 7,135 5,293 2,970
AVERAGE SALES PRICE:
Oil and Condensate ($ per Bbl) (1)............................. $ 12.29 $ 17.21 $ 19.31
Natural gas ($ per Mcf) (2).................................... 2.18 2.47 2.42
Natural gas equivalent ($ per Mcfe) (2)........................ 2.17 2.54 2.60
AVERAGE OIL AND NATURAL GAS OPERATING EXPENSE ($ PER MCFE) (3)... 0.47 0.44 0.54
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(1) Includes plant products.
(2) Includes the effect of hedging activity for the year ended December 31, 1998
and 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, 1996 to December 31, 1998, the Company incurred total net
acquisition, exploration and development costs of approximately $71.3 million
and generated proceeds of approximately $11.5 million from the sale of
undeveloped prospects. Total acquisition, exploration, and development
activities from January 1, 1996 to December 31, 1998, resulted in the addition
of approximately 47 Bcfe (before downward reserve revisions of approximately
16.9 Bcfe), net to the Company's interest, of proved reserves
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at an average reserve replacement cost of $1.99 per Mcfe (net cost incurred
divided by net reserve additions). Reserve replacement costs reflect the
proceeds from the sales of undeveloped prospects recorded as a reduction to the
full-cost pool.
The Company's reserve replacement costs have historically fluctuated on a
year to year basis. Reserve replacement costs, as measured annually, may not be
indicative of the Company's ability to economically replace oil and natural gas
reserves because the recognition of costs may not necessarily coincide with the
addition of proved reserves.
ACQUISITION, EXPLORATION AND DEVELOPMENT CAPITAL EXPENDITURES
The following table sets forth certain information regarding the total costs
incurred in the acquisition, exploration and development of proved and unproved
properties.
YEAR ENDED DECEMBER 31,
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1998 1997 1996
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(IN THOUSANDS)
Acquisition Cost:
Unproved prospects.......................................... $ 20,853 $ 17,660 $ 4,490
Exploration costs............................................. 10,236 8,640 2,669
Development costs............................................. 3,250 1,208 2,343
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Total costs incurred........................................ 34,339 27,508 9,502
Less proceeds from sales of prospects......................... 6,952 2,325 2,230
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Net costs incurred.......................................... $ 27,387 $ 25,183 $ 7,272
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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.
DRILLING ACTIVITY
The following table sets forth the drilling activity of the Company for the
three years ended December 31, 1998. 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.
YEAR ENDED DECEMBER 31,
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1998 1997 1996
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GROSS NET GROSS NET GROSS NET
----------- --------- ----------- --------- ----------- ---------
EXPLORATORY:
Productive......................................... 43 19.34 60 27.07 32 15.82
Non-productive..................................... 23 10.27 22 9.68 12 3.76
-- -- --
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Total............................................ 66 29.61 82 36.75 44 19.58
DEVELOPMENT:.........................................
Productive......................................... 12 3.53 15 2.82
Non-productive..................................... 5 2.89 4 1.87 1 0.20
-- -- --
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Total............................................ 17 6.42 19 4.69 1 0.20
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At December 31, 1998, the Company is evaluating one test well (.05 net).
Final completion is pending the results of that test.
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, 1998.
COMPANY OPERATED NON- OPERATED
TOTAL
---------------------- ---------------------- --------------------------
GROSS NET GROSS NET GROSS (1) NET (1)
----------- --------- ----------- --------- ------------- -----------
Oil.............................................. 18 9.35 23 5.96 41 15.31
Natural gas...................................... 91 56.17 58 11.55 149 67.72
--
--- --------- --------- --- -----
Total.......................................... 109 65.52 81 17.51 190 83.03
--
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(1) Includes 42 gross wells shut in, (19.84 net).
ACREAGE DATA
The following table sets forth certain information regarding the Company's
developed and undeveloped lease acreage as of December 31, 1998. Developed acres
refers to acreage within producing units and undeveloped acres refers to acreage
that has not been placed in producing units.
UNDEVELOPED ACRES
DEVELOPED ACRES TOTAL
-------------------- -------------------- --------------------
GROSS NET GROSS NET GROSS NET
--------- --------- --------- --------- --------- ---------
Texas...................................... 62,068 23,133 56,386 17,266 118,454 40,399
Louisiana.................................. 1,911 300 15,546 5,749 17,457 6,049
Mississippi................................ 2,660 87 10,269 9,093 12,929 9,180
Alabama.................................... 1,511 168 569 279 2,080 447
--------- --------- --------- --------- --------- ---------
Total.................................... 68,150 23,688 82,770 32,387 150,920 56,075
--------- --------- --------- --------- --------- ---------
Leases covering approximately 26,903.78 gross (10,047.80 net), 21,790.12
gross (9,257.74 net), 28,782.18 gross (12,858.21 net) and 235.73 gross (59.39
net) undeveloped acres are scheduled to expire in 1999, 2000, 2001 and 2002,
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 67,872.85 gross (30,663.97 net) acres that the
Company has a right to acquire pursuant to various seismic option agreements at
December 31, 1998. 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 Company has operations
in 25 3-D project areas. The description below groups those project areas into
major play areas and provides detail on the key areas the Company expects to
exploit in 1999. 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, typically, has participated in these project
areas with industry partners under agreements that typically provide for the
industry partners to bear a greater share
8
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
SOUTH TEXAS FRIO-VICKSBURG TREND
This trend encompasses the Amazon, Aubrey, Encinitas, Everest, and
Santellana 3-D project areas, covering about 550 square miles, and spans parts
of Brooks, Starr, and Hidalgo Counties in South Texas. The Company's average
working interests range from 100% in the Santellana area to 22.5% in the
Encinitas area.--There were nine wells drilled in this trend in 1998. At
year-end 1998, Edge's net production from this area was approximately 8.5 MMcfe
per day. The focus for this area will be deeper drilling the Vicksburg
formation. Nine wells are planned for this area in 1999.
SOUTH TEXAS FRIO-WILCOX TREND
This trend encompasses the Belco Target Area 2, Leroy, Nita Austin, Spartan
and Spartan Extension, Tyler, Brandon, Buckeye, Clayton, Bee County, Cameron 3-D
project areas, covering approximately 805 square miles in Duval, Webb, Live Oak,
Bee and Goliad Counties. The Company's average working interests range from 100%
to 0%. In some areas in this trend the Company has historically sold prospects
retaining only a back-in working interest after payout. There were 63 wells
drilled in this trend during 1998. At year-end 1998, Edge's net production from
this area was approximately 10.3 MMcfe per day. Edge plans to drill
approximately 15 wells in this area during 1999, consisting of a combination of
typical shallower Frio, Hockley, Pettus and Yegua wells plus select deeper
Wilcox wells.
The Company is developing a new, large project area within this trend on the
42,000 acre M.E. O'Conner Heirs Ranch. During 1998 Edge and a partner, Texaco,
negotiated a single lease covering the O'Conner Ranch and will acquire
approximately 100 square miles of new, proprietary 3-D seismic covering the
Ranch during 1999. Edge will have a 50% working interest in all wells above
8,000 feet and 22.5% in deeper wells. Seismic data is expected to be delivered
in the third quarter with drilling beginning in the fourth quarter of 1999.
LOUISIANA
During 1997, Edge began to reestablish activity in Louisiana where the
Company had been historically active and has had prior exploratory successes.
Early in its history, the Company developed and sold a number of South Louisiana
exploration prospects including a prospect that became the Maurice Field, a
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field that has produced in excess of 150 Bcfe since its discovery in 1987. Edge
currently has a 2.68% working interest in two wells in this field. During 1998
Edge participated in the drilling of four wells in South Louisiana, three of
which were dry holes.
SOUTH LOUISIANA MARGTEX, BOLMEX TREND
This trend is the focus of the Company's Genesis Project area in Acadia,
Vermilion, Lafayette and St. Landry Parishes. The Company has approximately 500
square miles of 3-D seismic data covering this prolific natural gas trend. Edge
began drilling one large prospect in this area in early 1999. It is an 18,000
foot MargTex exploratory well. Edge has an 11% direct working interest plus a
22.5% carry to casing point by its partners which results in a 26% working
interest at casing point and a 19% NRI. The Company has leased and expects to
drill three additional exploratory wells in this area during 1999, retaining an
average 30% working interest.
SOUTH LOUISIANA NODOSARIA EMBAYMENT TREND
During 1998 the Company initiated the optioning, permitting and leasing of a
150 square mile area in St. Landry, Acadia and Lafayette Parishes. In late 1998,
the Company brought two partners into the project and contracted for the
acquisition of 3-D seismic data over the area, which is to be completed in
mid-1999. The Company and its partners will have exclusive rights to this data
for a nine to twelve month period after which the seismic contractor has the
right to sell the data to other interested parties. The seismic contractor is
paying for 30% of the permitting and acquisition costs for that marketing right.
The Company will retain a 45% working interest in the Nodosaria Embayment
Project, while paying for only 20% of optioning and data acquisition costs, and
its two partners will each have a 27.5% working interest.
The Nodosaria Embayment Project area has never been shot with 3-D seismic
but is A prolific producer from older fields drilled based upon 2-D seismic
data. The exploration focus of the project is balance between intermediate,
normally pressured 10,000 foot targets and deeper, geopressured 15,000 foot
targets. The survey area has produced 2.5 Tcf of gas and 145 MMBbl of oil to
date. Only five wells have been drilled below 15,000 feet on the northern half
of the survey and only 28 wells have been drilled below 15,000 feet in the
southern half.
INVESTMENT IN FRONTERA RESOURCES CORPORATION
In August 1997, the Company acquired 15,171 shares of Series D Preferred
Stock of Frontera Resources Corporation ("Frontera") that were initially
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.
Pursuant to a rights offering conducted in November 1998, the Company agreed
to purchase 44,027 shares of Frontera Common Stock plus such additional shares,
if necessary, to maintain its current 8.73% interest of partially diluted
outstanding Frontera Stock (assuming conversion of all preferred stock). The
rights offering consisted of two tranches. The Company paid $116,671 in
December, 1998 in connection
10
with the first tranche and exercised an option to acquire an additional 2,123
shares in January 1999. Should the Company exercise the second tranche of the
rights offering (which the Company believes will happen during the first half of
1999) the Company will be obligated to purchase another 44,027 shares to
maintain is approximate 8.73% interest.
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. During 1997 and 1998 the Company had in place several natural gas
commodity collars with a financial institution covering 5,000 - 20,000 MMbtus
per day, or approximately 30%--60% of the Company's daily production. Prices
received float between a floor and cap price per MMbtu, (delivered price basis,
Houston Ship Channel), with settlement for each calendar month occurring five
business days following the publishing of the Inside F.E.R.C. Gas Marketing
Report. Included within natural gas revenues for the years ended December 31,
1997 and 1998 was approximately $33,000 and $482,000, respectively, representing
net settlement gains from collar activities. There were no active collar
agreements in place at December 31, 1998. During December 1998, the Company
entered into a fixed price swap for $1.96 per MMbtu. This fixed price swap
covers 13,000 MMbtu per day, or approxiamtely 65% of daily production, and is
effective beginning March 1, 1999 and expires on October 31, 1999. There was no
material hedging activity during the year ended December 31, 1996.
11
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 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
12
laws and regulations. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells that may be drilled in
and the unitization or pooling of oil and natural gas properties. In this
regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely primarily or exclusively on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units, and therefore more difficult to develop a
project if the operator owns less than 100% of the leasehold. In addition, state
conservation laws establish maximum rates of production from oil and natural gas
wells, generally prohibit the venting or flaring of natural gas and impose
certain requirements regarding the ratability of production. The effect of these
regulations may limit the amount of oil and natural gas the Company can produce
from its wells and may limit the number of wells or the locations at which the
Company can drill. The regulatory burden on the oil and natural gas industry
increases the Company's costs of doing business and, consequently, affects its
profitability. Inasmuch as such laws and regulations are frequently expanded,
amended and reinterpreted, the Company is unable to predict the future cost or
impact of complying with such regulations.
REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS. 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.
13
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
14
treatment and disposal or release of hydrocarbons or other wastes was not under
the Company's control. These properties and the wastes disposed thereon may be
subject to the Comprehensive Environmental Response, Compensation and Liability
Act ("CERCLA"), RCRA and analogous state laws as well as state laws governing
the management of oil and natural gas wastes. Under such laws, the Company could
be required to remove or remediate previously disposed wastes (including wastes
disposed of or released by prior owners or operators) or property contamination
(including groundwater contamination) or to perform remedial plugging operations
to prevent future contamination.
The Company's operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted in
1990 and contain provisions that may result in the gradual imposition of certain
pollution control requirements with respect to air emissions from the operations
of the Company. The EPA and states have been developing regulations to implement
these requirements. The Company may be required to incur certain capital
expenditures in the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals
addressing other air emission-related issues. However, the Company does not
believe its operations will be materially adversely affected by any such
requirements.
Federal regulations require certain owners or operators of facilities that
store or otherwise handle oil, such as the Company, to prepare and implement
spill prevention, control, countermeasure ("SPCC") and response plans relating
to the possible discharge of oil into surface waters. The Company has
acknowledged the need for SPCC plans at certain of its properties and believes
that it will be able to develop and implement these plans in the near future.
The Oil Pollution Act of 1990, ("OPA") contains numerous requirements relating
to the prevention of and response to oil spills into waters of the United
States. The OPA subjects owners of facilities to strict joint and several
liability for all containment and cleanup costs and certain other damages
arising from a spill, including, but not limited to, the costs of responding to
a release of oil to surface waters. The OPA also requires owners and operators
of offshore facilities that could be the source of an oil spill into federal or
state waters, including wetlands, to post a bond, letter of credit or other form
of financial assurance in amounts ranging from $10 million in specified state
waters to $35 million in federal outer continental shelf waters to cover costs
that could be incurred by governmental authorities in responding to an oil
spill. Such financial assurances may be increased by as much as $150 million if
a formal risk assessment indicates that the increase is warranted. Noncompliance
with OPA may result in varying civil and criminal penalties and liabilities.
Operations of the Company are also subject to the federal Clean Water Act
("CWA") and analogous state laws. In accordance with the CWA, the state of
Louisiana has issued regulations prohibiting discharges of produced water in
state coastal waters effective July 1, 1997. Pursuant to other requirements of
the CWA, the EPA has adopted regulations concerning discharges of storm water
runoff. This program requires covered facilities to obtain individual permits,
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
15
for neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances released
into the environment.
The Company also is subject to a variety of federal, state and local
permitting and registration requirements relating to protection of the
environment. Management believes that the Company is in substantial compliance
with current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse effect on
the Company.
OPERATING HAZARDS AND INSURANCE
The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosion, blow-out, pipe failure, casing collapse,
abnormally pressured formations and environmental hazards such as oil spills,
natural gas leaks, ruptures and discharges of toxic gases, the occurrence of any
of which could result in substantial losses to the Company due to injury or loss
of life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, cleanup responsibilities,
regulatory investigation and penalties and suspension of operations.
In accordance with customary industry practice, the Company maintains
insurance against some, but not all, of the risks described above. The Company's
insurance does not cover business interruption or protect against loss of
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, 1998, the Company had 48 full-time employees, primarily
professionals, including nine geologists/geophysicists, four geo-technicians,
four landmen and three engineers. The Company believes that its relationships
with its employees are good. None of the Company's employees are covered by a
collective bargaining agreement. From time to time, the Company utilizes the
services of independent consultants and contractors to perform various
professional services, particularly in the areas of construction, design, well
site surveillance, permitting and environmental assessment. Field and on-site
production operation services, such as pumping, maintenance, dispatching,
inspection and testing, are generally provided by independent contractors.
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.
16
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 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
17
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 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
18
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, 1998, 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 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
19
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 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."
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 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.
20
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, 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
21
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 completed its assessment of the year 2000 processing issues
of its internal technology systems, considering current financial and
accounting, production, land and geological computer systems and software
utilized by the Company. Due to the need for improved management reporting, the
Company is in the process of replacing its existing financial and accounting,
production and land applications with new software which is year 2000 compliant.
Implementation is expected to be completed on or before June 30, 1999 at a total
cost of approximately $235,000. As of December 31, 1998, the Company has
incurred approximately $180,000 converting to its new financial and accounting
system and software with a majority of the remaining cost to be incurred prior
to March 31, 1999. Production and land applications will be operational on or
before June 30, 1999. These costs have been funded from cash flows from
operations and the cost of the new software and necessary hardware upgrades have
been capitalized. Based on assertions made by vendors, the Company believes its
geological systems and software are year 2000 compliant. In addition the Company
is performing other forms of due diligence to ensure that its geological systems
are compliant.
The Company is also in the process of evaluating the risk presented by
potential Year 2000 non-compliance by third parties. Because such risks vary
substantially, companies are being contacted based on the estimated magnitude of
risk posed to the Company by their year 2000 non-compliance. The Company
anticipates that these efforts will continue through 1999 and will not result in
significant costs to the Company.
The Company's assessment of its Year 2000 issues involves many assumptions.
There can be no assurance that the Company's assumptions will prove accurate,
and actual results could differ significantly from the assumptions. In
conducting its Year 2000 compliance efforts, the Company has relied primarily on
vendor representations with respect to internal computerized systems and
representations from third parties with which the Company has business
relationships and has not independently verified representations. There can be
no assurance that these representations will prove accurate. A Year 2000 failure
could result in a business interruption that adversely effects the Company's
business, financial condition or results of operations. Although it is not
currently aware of any likely business disruptions, the Company has developed a
contingency plan to address and assess the readiness of its material suppliers,
customers
22
and other entities as it relates to year 2000 processing issues and expects this
work to be completed before December 31, 1999. The Company is not insured for
this type of loss should a loss occur.
The foregoing statements are intended to be and are hereby designated "Year
2000 Readiness Disclosures" within the meaning of the Year 2000 Information and
Readiness Disclosure Act.
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 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.
23
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.
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.
24
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.
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.
25
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. ELIAS has served as the Chief Executive Officer and Chairman of the
Board of Directors (the "Board") of the Company since November 1998. Mr. Elias
is a member (chairman) of the Nominating Committee of the Board. From April 1993
to September 30, 1998, he served in various senior management positions,
including Executive Vice President, of Seagull Energy Corporation, a company
engaged in oil and natural gas exploration, development and production and
pipeline marketing. Prior to April, 1993 Mr. Elias served in various positions
including senior management position with Amoco Corporation, a major integrated
oil and gas company. Mr. Elias has more than 35 years of experience in the oil
and natural gas exploration and production business. He is 58 years old. Mr.
Elias' current term as director of the Company expires in 2000.
JOHN E. CALAWAY formerly served as the Chief Executive Officer and Chairman
of the Board of the Company from December 1996 through November 1998. Effective
November 16, 1998, John E. Calaway resigned as Chairman of the Board, Chief
Executive Officer and a director of the Company. He was the 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 was also the Chairman of the
Nominating Committee of the Board.
JAMES D. CALAWAY has served as the President and Chief Operating Officer 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 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 41 years old. Mr. John E. Calaway and Mr. James D. Calaway are twin brothers.
MICHAEL G. LONG has served as Senior Vice President and Chief Financial
Officer of the Company since December 1996. Mr. Long served as Vice
President-Finance of W&T Offshore, Inc., an oil and natural gas exploration and
production company, from July 1995 to December 1996. From May 1994 to July 1995,
he served as Vice President of the Southwest Petroleum Division for Chase
Manhattan Bank, N.A. Prior
26
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 46 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 33
years old.
SIGNIFICANT EMPLOYEES
MARK J. GABRISCH has served as the Vice President of Land for the Company
since March 1997. From November 1994 to March 1997, he served in a similar
capacity with the Company's predecessor corporation. From 1985 to October 1994,
he was a landman, most recently a Senior Landman, for Shell Oil Company. Mr.
Gabrisch holds a B.S. in Petroleum Land Management from the University of
Houston.
JOHN O. HASTINGS, JR. has served as the Vice President of Exploration for
the Company since March 1997 and prior thereto served in a similar capacity with
the Company's predecessor corporation since February 1994. From 1984 to February
1994, he was an exploration geologist with Shell Oil Company, serving as Senior
Geologist before his departure. Mr. Hastings holds a B.A. from Dartmouth in
Earth Sciences and a M.S. in Geology from Texas A&M University.
JOHN O. TUGWELL has served as the Vice President of Production for the
Company since March 1997 and prior thereto served as Senior Petroleum Engineer
of the Company's predecessor corporation since May 1995. From 1986 to May 1995,
he held various reservoir/production engineering positions with Shell Oil
Company, most recently that of Senior Reservoir Engineer. Mr. Tugwell holds a
B.S. in Petroleum Engineering from Louisiana State University. Mr. Tugwell is a
registered Professional Engineer in the State of Texas.
27
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
(a) As of March 19, 1999, the Company estimates there were approximately 231
beneficial holders of its Common Stock. The Company's Common Stock is
listed on the NASDAQ National Market ("NASDAQ") and traded under the
symbol "EPEX". As of March 19, 1999, the Company had 7,772,032 shares
outstanding and its closing price on NASDAQ was $5.375 per share. The
following table sets forth, for the periods indicated, the high and low
closing sales prices for Common Stock of the Company as listed on Nasdaq.
COMMON STOCK
----------------
HIGH LOW
----- -----
CALENDAR 1998
QUARTER:
First.................. $14 $ 9 1/4
Second................. 13 3/4 10 5/8
Third.................. 11 7/8 7 7/8
Fourth................. 10 1/8 4 1/8
CALENDAR 1997
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. The payment of future dividends will be determined
by the Company's Board of Directors in light of conditions then existing,
including the Company's earnings, financial condition, capital requirements,
restrictions in financing agreements, business conditions and other factors. See
ITEMS 1 AND 2.-- BUSINESS AND PROPERTIES--FORWARD LOOKING INFORMATION AND RISK
FACTORS-- Absence of Dividends on Common Stock."
28
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth selected financial data regarding the Company
as of and for each of the periods indicated. The following data should be read
in conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Company's financial statements and notes
thereto, which follow:
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1998 1997 1996 (3) 1995 (3) 1994 (3)
---------- ---------- --------- --------- -----------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
STATEMENT OF OPERATIONAL DATA:
Oil and natural gas revenue............................. $ 15,463 $ 13,468 $ 7,719 $ 2,040 $ 1,994
Costs and expenses:
Oil and natural gas operating expenses................ 3,376 2,331 1,600 686 305
Depletion, depreciation and amortization.............. 10,002 2,876 1,613 813 593
Impairment of oil and natural gas properties.......... 10,013
General and administative............................. 4,583 4,641 2,753 2,484 2,026
Other charge.......................................... 2,898
Unearned compensation expense......................... 621 513
---------- ---------- --------- --------- -----------
Total operating expenses............................ 31,493 10,361 5,966 3,983 2,924
---------- ---------- --------- --------- -----------
Operating income (loss)................................. (16,030) 3,107 1,753 (1,943) (930)
Interest expense........................................ (90) (183) (859) (315) (385)
Interest income......................................... 133 901
Gain on sale of oil and gas property.................... 3,337 2,284
Other income............................................ 233
---------- ---------- --------- --------- -----------
Income (loss) before income taxes, minority interest and
cumulative effect of accounting change................ (15,987) 3,825 1,127 1,079 969
Income tax (expense) benefit............................ 983 (394) (397) (292)
Minority interest....................................... (433) (576) (543)
---------- ---------- --------- --------- -----------
Income (loss) before cumulative effect of accounting
change................................................ (15,004) 3,825 300 106 134
Cumulative effect of accounting change.................. 1,781
---------- ---------- --------- --------- -----------
Net income (loss)....................................... $ (13,223) $ 3,825 $ 300 $ 106 $ 134
---------- ---------- --------- --------- -----------
---------- ---------- --------- --------- -----------
Basic income (loss) per share: (1)
Income (loss) before cumulative effect of accounting
change.............................................. $ (1.93) $ 0.53 $ 0.06 $ 0.02 $ 0.03
Cumulative effect of accounting change................ 0.23
---------- ---------- --------- --------- -----------
Basic earnings (loss) per share......................... $ (1.70) $ 0.53 $ 0.06 $ 0.02 $ 0.03
---------- ---------- --------- --------- -----------
---------- ---------- --------- --------- -----------
Diluted income (loss) per share: (1)
Income (loss) before cumulative effect of accounting
change.............................................. $ (1.93) $ 0.52 $ 0.06 $ 0.02 $ 0.03
Cumulative effect of accounting change................ 0.23
---------- ---------- --------- --------- -----------
Diluted earnings (loss) per share....................... $ (1.70) $ 0.52 $ 0.06 $ 0.02 $ 0.03
Basic weighted average number of shares outstanding
(1)................................................... 7,772 7,275 4,701 4,701 4,701
Diluted weighted average number of shares outstanding
(1)................................................... 7,772 7,320 4,701 4,701 4,701
STATEMENT OF CASH FLOW DATA:
EBITDA (2).............................................. $ 4,118 $ 6,884 $ 3,166 $ 1,631 $ 1,404
Capital expenditures.................................... 34,824 29,874 10,467 8,512 6,809
Net cash provided by (used in) operating activities..... 11,983 4,145 2,278 (927) (604)
Net cash used in investing activities................... (27,989) (31,177) (5,651) (1,154) 291
Net cash provided by (used in) financing activities..... 12,500 29,266 4,716 1,932 (425)
29
AS OF DECEMBER 31,
---------------------------------------------------------
1998 1997 1996 (3) 1995 (3) 1994 (3)
--------- --------- --------- ----------- -----------
(IN THOUSANDS)
BALANCE SHEET DATA:
Working capital............................................ $ (8,255) $ 7,603 $ 690 $ (947) $ (973)
Property and equipment, net................................ 47,259 36,663 11,989 7,911 4,136
Total assets............................................... 56,279 53,766 19,556 9,858 6,128
Long-term debt including current maturities................ 12,500 11,862 6,214 4,177
Equity (deficit)........................................... 36,956 47,911 (373) (658) (749)
- ------------------------
(1) Basic and diluted 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, effective March 3, 1997.
(2) EBITDA represents income (loss) before cumulative effect of accounting
change, interest expense, income taxes, depletion, depreciation and
amortization and impairment. Management of the Company believes that EBITDA
may provide additional information about the Company's ability to meet its
future requirements for debt service, capital expenditures and working
capital. EBITDA is a financial measure commonly used in the oil and natural
gas industry and should not be considered in isolation or as a substitute
for net income, operating income, cash flows from operating activities or
any other measure of financial performance presented in accordance with
generally accepted accounting principles or as a measure of a company's
profitability or liquidity. Because EBITDA excludes some, but not all, items
that affect net income this measure may vary among companies. The EBITDA
data presented above may not be comparable to a similarly titled measure of
other companies.
(3) The Combination (as defined herein) was accounted for as a reorganization of
entities under common control. Accordingly, as of and for the three years in
the period ended December 31, 1996, the consolidated accounts are presented
using the historical costs and results of operations of the affiliated
entities as if such entities had always been combined. Accordingly the
consolidated financial statements include the accounts of Edge Petroleum
Corporation, a Texas corporations,("Old Edge"), and Edge Joint Venture II
(the "Joint Venture). The Joint Venture interests not owned by Old Edge is
recorded as minority interest.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is a review of the Company's financial position and results of
operations for the periods indicated. The Company's Consolidated Financial
Statements and Supplementary Data and the related notes thereto contain detailed
information that should be referred to in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations.
GENERAL OVERVIEW
The Company was organized as a Delaware corporation in August 1996 in
connection with the initial public offering (the "Offering") and related
combination of certain entities that held interests in the Joint Venture and
certain other oil and natural gas properties; herein referred to as the
"Combination". In a series of combination transactions the Company issued an
aggregate of 4,701,361 shares of common stock and received in exchange 100% of
the ownership interests in the Joint Venture and certain other oil and natural
gas properties. In March 1997, and contemporaneously with the Combination, the
Company completed the Offering of 2,760,000 shares of its common stock
generating proceeds of approximately $40 million, net of expenses.
30
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. At
December 31, 1998 the Company recorded a full cost ceiling test write down of
its oil and natural gas properties of approximately $10 million.
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. During 1997 and 1998 the
Company had in place several natural gas commodity collars with a financial
institution covering 5,000-20,000 MMbtus per day, or approximately 30%-60% of
the Company's daily production. Prices received float between a floor and cap
price per MMbtu, (delivered price basis, Houston Ship Channel), with settlement
for each calendar month occurring five business days following the publishing of
the Inside F.E.R.C. Gas Marketing Report. Included within natural gas revenues
for the years ended December 31, 1998 and 1997 was approximately $482,000 and
$33,000, respectively, representing net settlement gains from collar activities.
There were no active collar agreements in place at December 31, 1998. During
December 1998, the Company entered into a fixed price swap for $1.96 per MMbtu.
This fixed price swap covers 13,000 MMbtu per day, or approximately 65% of daily
production, and is effective beginning March 1, 1999 and expires on October 31,
1999. There was no material hedging activity during the year ended December 31,
1996.
31
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1998 COMPARED TO THE YEAR ENDED DECEMBER 31, 1997
REVENUE AND PRODUCTION
Oil and natural gas revenues increased 15% from $13.5 million in 1997 to
$15.5 million in 1998. Production volumes for oil decreased 14% from 165,640
Bbls in 1997 to 141,774 Bbls in 1998. The decrease in oil production decreased
revenues by approximately $411,000, further decreased by a 29% decrease in
average oil prices that reduced revenues by approximately $698,000. Production
volumes for natural gas increased 46% from 4,298,859 Mcf in 1997 to 6,284,495
Mcf in 1998. The increase in natural gas production increased revenues by
approximately $4.9 million. A 12% decrease in average natural gas prices
decreased revenues by approximately $1.8 million. The overall net increase in
oil and natural gas production was due to 55 new gross, (22.87 net), producing
exploratory and development wells drilled and completed since December 31, 1997
partially offset by production declines from existing wells. Included within
natural gas revenues for the two years ended December 31, 1998 and 1997 was
approximately $482,000 and $33,000, respectively, representing net gains from
collar activity. The collar settlements increased the effective average natural
gas prices by $0.07 per Mcf and $0.01 per Mcf, respectively, for the two years
ended December 31, 1998 and 1997.
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 1998 and 1997.
1998 PERIOD COMPARED TO 1997
DECEMBER 31, PERIOD
---------------------------- ------------------------------
INCREASE % INCREASE
1998 1997 (DECREASE) (DECREASE)
------------- ------------- ------------- ---------------
Production volumes:
Oil and condensate (Bbls)............................. 141,774 165,640 (23,866) (14)%
Natural gas (Mcf)..................................... 6,284,495 4,298,859 1,985,636 46%
Natural gas equivalents(Mcfe)......................... 7,135,139 5,292,699 1,842,440 35%
Average sales prices:
Oil and condensate ($per Bbl)......................... $ 12.29 $ 17.21 $ (4.92) (29)%
Natural gas ($per Mcf)................................ 2.18 2.47 (0.29) (12)%
Operating revenues:
Oil and condensate.................................... $ 1,742,311 $ 2,850,600 $ (1,108,289) (39)%
Natural gas........................................... 13,721,121 10,617,442 3,103,679 29%
------------- ------------- -------------
Total................................................... $ 15,463,432 $ 13,468,042 $ 1,995,390 15%
------------- ------------- -------------
------------- ------------- -------------
COSTS AND OPERATING EXPENSES
Oil and natural gas operating expenses increased 45% from $2.3 million in
1997 to $3.4 million in 1998 due to increased production generated from new oil
and natural gas wells drilled and completed in 1998. Oil and natural gas
operating expenses on a unit of production basis were $0.47 per Mcfe and $0.44
per Mcfe for the years ended December 31, 1998 and 1997, respectively.
Depletion, depreciation and amortization expense ("DD&A") increased 248%
from $2.9 million in 1997 to $10 million in 1998. Included within DD&A for the
years ended December 31, 1997 and 1998 was $2.48 million and $9.3 million,
respectively, representing depletion expense of oil and natural gas properties.
A 177% increase in the overall depletion rate increased depletion expense by
approximately $5.9 million. The increase in the depletion rate was primarily due
to revisions of oil and natural gas reserve estimates as of December 31, 1998
and the abandonment during the fourth quarter of 1998 of certain projects,
portions of projects and prospects located in non-core areas. Additionally, the
depletion rate was further increased due to the change in accounting method (see
Note 1 to the Consolidation Financial
32
Statements) which increased depletion expense by approximately $608,000 during
the year ended December 31, 1998. Increased oil and natural gas production
further increased depletion expense by approximately $865,000. Depletion on a
unit of production basis for the years ended December 31, 1998 and 1997 was
$1.30 per Mcfe and $0.47 per Mcfe, respectively. The remaining increase in DD&A
was due primarily to depreciation of new computer hardware and software and
office furniture purchased during the fourth quarter of 1997 and the
amortization of deferred loan cost incurred as a result of a new credit facility
executed during April 1998.
The Securities and Exchange Commission requires that the carrying cost of
proved reserves be assessed periodically for ceiling test impairment. At
December 31,1998 the discounted future net revenues of the Company's proved
reserves were $22.7 million. As a result of the Company's carrying cost of
proved reserves being in excess of the present value using a discount rate of
10% the Company recorded a full cost ceiling test write down of its oil and
natural gas properties of approximately $10 million. There have been no write
downs of its oil and natural gas properties in prior years.
General and administrative expense ("G&A") was $4.6 million for each of the
years ended December 31, 1998 and 1997. Excluding the effects of the change in
accounting method (referred to in Note 1 to the Consolidated Financial
Statements), G&A increased by $2.3 million which was primarily attributable to
the hiring of additional employees to support the Company's increased level of
exploration activities and 3-D project generation and costs associated with
being a public company and general office overhead. Included as a reduction in
G&A for the years ended December 31, 1998 and 1997, was approximately $743,000
and $802,000, respectively, of overhead reimbursements and management fees
received from various management, operating and seismic agreements. General and
administrative expenses on a unit of production basis for the years ended
December 31, 1998 and 1997 were $0.64 per Mcfe and $0.88 per Mcfe, respectively.
Unearned compensation expense for the year ended December 31, 1998 and 1997
was $621,191 and $513,393, respectively due to the amortization of unearned
compensation expense recognized from restricted stock granted to executives at
the completion of the Offering. Unearned compensation expense will continue to
be recognized in the future, amortized over a vesting period of five to ten
years.
The other charge of approximately $2.9 million is expense incurred as a
result of John E. Calaway's resignation as Chairman of the Board and Chief
Executive Officer and Director of the Company. The Company incurred the one-time
charge to satisfy corporate obligations under his employment contract. Included
in the $2.9 million is a $1.6 million non-cash amount relating to vesting of the
remaining balance of Mr. Calaway's restricted common stock award granted
concurrent with the Company's Offering. The balance of the special charge
primarily represents cash payments to be paid to Mr. Calaway from the date of
his resignation to January, 2000, of which $623,000 has been paid as of December
31, 1998.
Interest expense for the year ended December 31, 1998 was $90,075, net of
interest capitalized to oil and natural gas properties of approximately
$411,000, as compared to interest expense of $183,028 for the year ended
December 31, 1997. The weighted average debt was $7 million for the year ended
December 31, 1998 compared to $2 million for the same period in 1997.
Interest income for the year ended December 31, 1998 was $132,993 compared
to $900,867 for the same period in 1997. A majority of the interest earned
during 1997 was earned from short-term investments purchased with unused
proceeds from the Offering. The Offering proceeds were fully deployed in
operations by the end of the first quarter of 1998.
For the year ended December 31, 1998, the Company had a tax benefit of
$982,966. As a result of the cumulative effect of the accounting change, the
Company recorded a provision for taxes during the second quarter of 1998. As a
result of losses generated during the second half of 1998 a tax benefit was
recognized to the extent of the provision for tax recorded. Due to the
availability of net operating loss carry forwards and other net deferred tax
assets there is no provision for current or deferred taxes for the year ended
December 31, 1997. As of December 31, 1998, the Company has available a
substantial net operating loss
33
carryforward and other net deferred tax assets and should the Company have
taxable income in future periods a provision for tax expense will be provided.
For the year ended December 31, 1998, the Company had an operating loss of
$16 million as compared to operating income of $3.1 million in 1997. The
significant decrease in operating income was primarily attributable to increased
depletion expense, a full cost ceiling test write down and the other charge,
referred to above, which was further reduced by increased operating costs and
expenses related to the new well additions (55 gross, 22.87 net) and lower
average commodity prices for both oil and natural gas. These decreases in
operating income were partially offset by higher levels of production from new
well additions. Net loss for the year ended December 31, 1998 was approximately
$13.2 million, ($15 million before cumulative effect of accounting change), or
basic and diluted loss per share of $1.70, as compared to net income of $3.8
million, or basic and diluted earnings per share of $0.53 and $0.52,
respectively for 1997.
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. Included
within natural gas revenues for the year ended December 31, 1997 was
approximately $33,000 representing a net gain from current collar activity. The
collar settlements increased the effective average natural gas prices by $0.01
per Mcf for the year ended December 31, 1997
The following table summarizes production volumes, average sales prices and
operating revenues for the Company's oil and natural gas operations for the
years ended December 31, 1997 and 1996.
1997 PERIOD
COMPARED
DECEMBER 31, TO 1996 PERIOD
--------------------------- -----------------------------
INCREASE % INCREASE
1997 1996 (DECREASE) (DECREASE)
------------- ------------ ------------ ---------------
Production volumes:
Oil and condensate (Bbls)............................... 165,640 109,225 56,415 52%
Natural gas (Mcf)....................................... 4,298,859 2,316,105 1,982,754 86%
Natural gas equivalent (Mcfe)........................... 5,292,699 2,971,455 2,321,244 78%
Average sales prices:
Oil and condensate ($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%
------------- ------------ ------------
------------- ------------ ------------
34
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 $2.48 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.
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.
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.
35
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.
LIQUIDITY AND CAPITAL RESOURCES
In March 1997, the Company completed the Offering of 2,760,000 shares of its
common stock at a public offering price of $16.50 per share. The Offering
provided the Company with proceeds of approximately $40 million, net of
expenses. The Company used approximately $12.7 million to repay its long-term
outstanding indebtedness incurred under its revolving credit facility (the
"Revolving Credit Facility"), subordinated loans and equipment loans. The
remaining proceeds from the Offering, together with cash flows from operations,
were used to fund capital expenditures, commitments, and other working capital
requirements and for general corporate purposes.
The Company had cash and cash equivalents at December 31, 1998 of $272,428,
consisting primarily of short-term money market investments, as compared to $3.8
million at December 31, 1997. Working capital was $(8.3) million as of December
31, 1998 as compared to $7.6 million at December 31, 1997.
Cash flows provided by operations were $12 million, $4.1 million and $2.3
million, for the years ended December 31, 1998, 1997 and 1996, respectively. The
significant increase in net cash provided by operations for the year ended
December 31, 1998 as compared to 1997 was primarily due to a significant amount
of collections of accounts receivable from joint interest owners and increased
accrued liabilities. Operating cash flows, before changes in working capital,
for the year ended December 31, 1998 decreased $917,000 primarily due to lower
interest income realized during 1998 and lower average commodity prices for both
oil and condensate and natural gas. 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 and lower average commodity prices
for oil and condensate. 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.
During the year ended December 31, 1998, the Company continued to reinvest a
substantial portion of its cash flows to increase its 3-D project portfolio,
improve its 3-D seismic interpretation technology and fund its drilling program.
As a result, the Company used $28 million in investing activities during 1998
including capital expenditures of approximately $34.8 million for oil and
natural gas property development offset by proceeds from the sale of oil and
natural gas prospects of $7 million. Capital expenditures of $13.5 million were
attributed to the drilling of 83 gross wells, 55 of which were successful, with
the majority of the remaining capital expenditures representing additions to
undeveloped oil and natural gas properties which has expanded and diversified
our portfolio of future drilling opportunities.
Pursuant to a rights offering by Frontera conducted in November 1998, the
Company agreed to purchase 44,027 shares of Frontera Common Stock plus such
additional shares, if necessary, to maintain its current 8.73% interest of
diluted outstanding Frontera stock. The Company paid $116,671 in December, 1998
in connection with this offering.
During the year ended December 31, 1997, the Company used $31.2 million in
investing activities including capital expenditures of approximately $29.9
million for oil and natural gas property development offset by proceeds from the
sale of oil and natural gas prospects of $2.3 million. Capital expenditures of
$9.8 million were attributed to the drilling of 101 gross wells, 75 of which
were successful, with the majority
36
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 expects capital expenditures in 1999 to be approximately $18
million. A substantial portion of capital expenditures in 1999 will be invested
in the Company's portfolio of 3-D prospects and to fund drilling activities
(approximately 50 gross wells) in an effort to expand its reserve base. In
addition, the Company will seek to continue to expand and improve its
technological and 3-D seismic interpretation capabilities.
Cash flows from financing activities in 1998 were $12.5 million compared to
$29.3 million in 1997. Financing activities during 1998 were comprised of
borrowings under its amended and restated Revolving Credit Facility. The
significant amount of cash flows from financing activities in 1997 was due to
the completion of the Company's Offering in March 1997 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.
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 1999 capital expenditures, commitments and working capital requirements
through cash flows from operations, possible available borrowings under its
existing Revolving Credit Facility, and to the extent necessary other financing
activities. The projected 1999 cash flows from operations are projected not to
be sufficient to fund its budgeted exploration and development program. To
provide additional working capital the Company continues to market a portion of
its interest in various Company generated drill ready prospects. Additionally,
the Company is currently evaluating various financing and refinancing options as
well as divestiture of certain non-core and under performing assets. The Company
believes it will be able to generate capital resources and liquidity sufficient
to fund its capital expenditures and meet such financial obligations as they
come due. In the event such capital resources are not available to the Company,
its drilling and other activities may be curtailed. See ITEMS 1 AND 2.--BUSINESS
AND PROPERTIES--"FORWARD LOOKING INFORMATION AND RISK FACTORS--Significant
Capital Requirements."
REVOLVING CREDIT FACILITY
During July 1995, the Company entered into a revolving credit facility (the
"Revolving Credit Facility") with a bank to finance temporary working capital
requirements. The Revolving Credit Facility provided up to $20 million in
borrowings limited by a borrowing base, as defined by the Revolving Credit
Facility. The Revolving Credit Facility provided for interest at the lender's
prime rate plus 0.75%. The borrowing base was subject to review by the bank on a
quarterly basis and could 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 with proceeds from its initial public offering.
Effective April 1, 1998, the Company amended and restated its Revolving Credit
Facility to provide a revolving line of credit of up to $100 million bearing
interest at a rate equal to prime or LIBOR plus 1.5%-2% depending on the level
of borrowing base utilization. The Company's initial borrowing base authorized
by the banks was approximately $15 million.
Effective September 29, 1998, the Company had its borrowing base
redetermined and amended its Revolving Credit Facility. The initial borrowing
base authorized by the bank was approximately $15 million. Beginning October 1,
1998 and on the first day of each month thereafter, the borrowing base was
required to be reduced by $550,000.
At December 31, 1998, borrowings under this facility totaled $12.5 million
with approximately $850,000 available for future borrowings. The weighted
average debt and interest rate during the year ended December 31, 1998 was
approximately $7 million and 7.3%, respectively.
37
The Revolving Credit Facility provides for certain restrictions, including
but not limited to, limitations on additional borrowings and issues of capital
stock, sales of its oil and natural gas properties or other collateral, engaging
in merger or consolidation transactions and prohibitions of dividends and
certain distributions of cash or properties and certain liens. The Revolving
Credit Facility also contains the following financial covenants: (i) tangible
net worth (total assets exclusive of certain intangibles minus liabilities) must
be at least $43 million plus 50% of positive net income and 100% of equity
raised for all quarterly periods subsequent to December 31, 1997; (ii) the ratio
at the end of any quarter of cash flow (net income plus proceeds of certain
project sales, depletion, depreciation, amortization and other non-cash expenses
less non-cash net income for such quarter) to debt service must be at least 1.25
to 1.00; and (iii) the ratio at the end of any quarter of EBIT (net income plus
interest expense and taxes, excluding non-cash, extraordinary expenses and
income) to interest expense for the proceeding 12-month period must be at least
4.5 to 1.00. At December 31, 1998 the Company was not in compliance with two of
its financial covenants, (i) and (iii) above, and accordingly has received
waivers from its bank for its noncompliance. There can be no assurance that the
Company will not require waivers in the future or, if required, that the bank
will grant them. The Revolving Credit Facility is secured by substantially all
the assets of the Company.
Subsequent to December 31, 1998, the Company undertook discussions with the
bank to restructure the Revolving Credit Facility. On March 18, 1999 the Company
and the Bank agreed on new terms which are as follows; 1) the proposed initial
borrowing base is $12 million comprised of a two tranche financing of a $9
million Revolving Credit Facility and a $3 million term facility, 2) Beginning
May 1, 1999, and on the first day of each month thereafter, the Revolving Credit
Facility borrowing base is required to be reduced by $400,000, 3) 75% of
prospect sales will be used to pay down the term facility with the remaining
unpaid term facility balance maturing on August 31, 1999. The Bank has also
agreed to amend the financial covenants on a go forward basis as follows;
tangible net worth will be at least 90% of actual tangible net worth as reported
at December 31, 1998 (or $33,260,720); the EBIT to Interest Expense and Cash
Flow Coverage covenants will be eliminated and replaced with a quarterly fixed
charge coverage test calculated as annualized EBITDA divided by the total of
interest plus 50% of quarter end loan outstanding and the covenant level would
be 1.25 to 1.00. The fixed charge coverage covenant does not apply until June
30, 1999.
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.
ACCOUNTING CHANGE
The Company uses the full-cost method of accounting for its oil and natural
gas properties. Under this method, all acquisition, exploration and development
costs that are directly attributable to the Company's acquisition, exploration
and development activities are capitalized in a "full-cost pool" as incurred. In
the second quarter of 1998 and effective January 1, 1998, the Company changed
its method of accounting for direct internal geological and geophysical ("G&G")
costs to one of capitalization of such costs, which are directly attributable to
acquisition, exploration and development activities, to oil and natural gas
property.
38
Prior to the change the Company expensed these costs as incurred. The Company
believes the accounting change provides for a better matching of revenues and
expenses and enhances the comparability of its results of operations with those
of other oil and natural gas companies that follow the full cost method of
accounting (see Note 1 to the Consolidated Financial Statements).
YEAR 2000
The Company has completed its assessment of the year 2000 processing issues
of its internal technology systems, considering current financial and
accounting, production, land and geological computer systems and software
utilized by the Company. Due to the need for improved management reporting, the
Company is in the process of replacing its existing financial and accounting,
production and land applications with new software which is year 2000 compliant.
Implementation is expected to be completed on or before June 30, 1999 at a total
cost of approximately $235,000. As of December 31, 1998, the Company has
incurred approximately $180,000 converting to its new financial and accounting
system and software with a majority of the remaining cost to be incurred prior
to March 31, 1999. Production and land applications will be operational on or
before June 30, 1999. These costs have been funded from cash flows from
operations and the cost of the new software and necessary hardware upgrades have
been capitalized. Based on assertions made by vendors, the Company believes its
geological systems and software are year 2000 compliant. In addition the Company
is performing other forms of due diligence to ensure that its geological systems
are compliant.
The Company is also in the process of evaluating the risk presented by
potential Year 2000 non-compliance by third parties. Because such risks vary
substantially, companies are being contacted based on the estimated magnitude of
risk posed to the Company by their year 2000 non-compliance. The Company
anticipates that these efforts will continue through 1999 and will not result in
significant costs to the Company.
The Company's assessment of its Year 2000 issues involves many assumptions.
There can be no assurance that the Company's assumptions will prove accurate,
and actual results could differ significantly from the assumptions. In
conducting its Year 2000 compliance efforts, the Company has relied primarily on
vendor representations with respect to internal computerized systems and
representations from third parties with which the Company has business
relationships and has not independently verified representations. There can be
no assurance that these representations will prove accurate. A Year 2000 failure
could result in a business interruption that adversely effects the Company's
business, financial condition or results of operations. Although it is not
currently aware of any likely business disruptions, the Company is developing a
contingency plan to address and assess the readiness of its material suppliers,
customers and other entities as it relates to year 2000 processing issues and
expects this work to be completed on or before December 31, 1998. The Company is
not insured for this type of loss should a loss occur.
The foregoing statements are intended to be and are hereby designated "Year
2000 Readiness Disclosures" within the meaning of the Year 2000 Information and
Readiness Disclosure Act.
ACCOUNTING PRONOUNCEMENTS
DERIVATIVES--In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 133, "Accounting for Derivative
Instruments and Hedging Activity" ("SFAS 133"). SFAS 133 establishes accounting
and reporting standards for derivative instruments and hedging activities that
require an entity to recognize all derivatives as an asset or liability measured
at fair value. Depending on the intended use of the derivatives, changes in its
fair value will be reported in the period of change as either a component of
earnings or a component of other comprehensive income.
SFAS 133 is effective for all fiscal quarters beginning after June 15, 1999.
Earlier application of SFAS 133 is encouraged, but not prior to the beginning of
any fiscal quarter that begins after issuance of the statement. Retroactive
application to periods prior to adoption is not allowed. The Company has not
quantified the impact of adoption on its financial statements or the date it
intends to adopt.
39
COMPREHENSIVE INCOME--In June 1997, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 130, "Reporting of
Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting
and displaying comprehensive income and its components. SFAS 130 is effective
for periods beginning after December 15, 1997. The purpose of reporting
comprehensive income is to report a measure of all changes in equity of an
enterprise that results from recognized transactions and other economic events
of the period other than transactions with owners in their capacity as owners.
As of December 31, 1998, there are no adjustments ("Other Comprehensive Income")
to net income (loss) in deriving comprehensive income.
40
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to market risk from changes in interest rates and
commodity prices. The Company uses a Revolving Credit Facility, which has a
floating interest rate, to finance a portion of its operations. The Company is
not subject to fair value risk resulting from changes in its floating interest
rates. The use of floating rate debt instruments provide benefit due to downward
interest rate movements but does not limit the Company to exposure from future
increases in interest rates. Based on December 31, 1998 floating interest rate
of 7.3%, a 10% change in interest rate would result in an increase or decrease
of approximately $91,000 on an annual basis. In the normal course of business
the Company enters into hedging transactions, including commodity price collars
and swaps, to mitigate its exposure to commodity price movements, but not for
trading or speculative purposes. 1n 1998, 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. During December 1998, the Company
entered into a fixed price swap for $1.96 per MMbtu. This fixed price swap
covers 13,000 MMbtu per day, or approximately 65% of daily production, and is
effective beginning March 1, 1999 and expires on October 31, 1999. At December
31, 1998, the fair value of this swap was approximately $(292,000). A 10% change
in the natural gas swap price per MMbtu would cause the total fair value of the
swap to increase or decrease by approximately $79,000 per month.
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
DISCLOSURES
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information regarding directors and executive officers required under
ITEM 10. will be contained within the definitive Proxy Statement of the
Company's 1999 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, 1998. 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 TRANSACTIONS
The information required by ITEM 13. will be contained in the Proxy
Statement under the heading "Transactions with Management and Certain
Shareholders" and "Executive Compensation and Other Information" and is
incorporated herein by reference.
41
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial Statements and Schedules:
1. Financial Statements: See Index to the Consolidated Financial Statements
and Supplementary Information immediately following the signature page
of this report.
2. Financial Statement Schedule: See Index to the Consolidated Financial
Statements and Supplementary Information immediately following the
signature page of this report.
3. Exhibits: The following documents are filed as exhibits to this report.
+2.1 -- Amended and Restated Combination Agreement by and among (i) Edge Group II Limited Partnership, (ii)
Gulfedge Limited Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum Corporation, (v)
Edge Mergeco, Inc. and (vi) the Company, dated as of January 13, 1997 (Incorporated by reference
from exhibit 2.1 to the Company's Registration Statement on Form S-4 (Registration No.
333-17269))
+3.1 -- Restated Certificate of Incorporated of the Company, as amended (Incorporated by reference from
exhibit 3.1 to the Company's Registration Statement on Form S-4 (Registration No. 333-17269)).
+3.2 -- Bylaws of the Company (Incorporated by reference from exhibit 3.2 to the Company's Registration
Statement on Form S-4 (Registration No. 333-17269)).
+4.1 -- Amended and Restated Credit Agreement, dated April 1, 1998, by and between Edge Petroleum
Corporation and Edge Petroleum Exploration Company (collectively the "Borrower") and Compass
Bank, a Texas state chartered banking institution, as Agent for itself and First National Bank of
Chicago and other lenders party thereto. (Incorporated by Reference to 4.1 to the Company's
Quarterly Report on Form 10-Q for, the quarterly period ended March 31, 1998).
+4.2 -- First Amendment dated September 29, 1998 to the Amended and Restated Credit Agreement, dated as of
April 1, 1998, by and between the Borrower and the First National Bank of Chicago as agent and a
Lender thereto (Incorporated by Reference to 4.1 to the Company's Quarterly Report on Form 10-Q
for, the quarterly period ended March 31, 1998).
+4.3 -- Security Agreement, dated as of April 1, 1998, by and between the Borrower and Compass Bank, a
Texas state chartered banking institution, as Agent for itself and The First National Bank of
Chicago and other lenders party thereto the Credit Agreement (Incorporated by Reference to 4.1 to
the Company's Quarterly Report on Form 10-Q for, the quarterly period ended March 31, 1998).
+4.4 -- Security Agreement (Stock Pledge), dated as of April 1, 1998, by and between Edge Petroleum
Corporation and Compass Bank, a Texas state chartered banking institution, as Agent for itself
and The First National Bank of Chicago and other lenders party thereto the Credit Agreement
(Incorporated by Reference to 4.1 to the Company's Quarterly Report on Form 10-Q for, the
quarterly period ended March 31, 1998).
-- The Company is a party to several debt instruments under which the total amount of securities
authorized does not exceed 10% of the total assets of the Company and its subsidiaries on a
consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, the Company
agrees to furnish a copy of such instruments to the Commission upon request.
+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)).
42
+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 dated as of December 19, 1996, by and between the Company and Michael G. Long
(Incorporated by reference from exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for
the quarterly period ended September 30, 1998).
+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)).
10.12 -- Employment Agreement dated as of November 16, 1998, by and between the Company and John W. Elias.
10.13 -- Agreement dated as of November 16, 1998 by and between the Company and John E. Calaway.
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, 1998
(included as an appendix to this Form 10-K).
- ------------------------
+ Incorporated by reference as indicated.
(b) Reports on Form 8-K:-- On December 1, 1998 The Company filed a Form 8-K
announcing as of November 16, 1998 the election of John W. Elias as Chairman
of the Board and Chief Executive Officer following the resignation of John
E. Calaway, as Chairman of the Board and Chief Executive Officer and
Director of the Company.
43
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
EDGE PETROLEUM CORPORATION
Date 3/26/99 /s/ JOHN W. ELIAS
- ------------------ ------------------------------------
John W. Elias
CHIEF EXECUTIVE OFFICER AND
CHAIRMAN OF THE BOARD
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Date 3/26/99 /s/ JOHN W. ELIAS
- ------------------ ------------------------------------
John W. Elias
CHIEF EXECUTIVE OFFICER AND
CHAIRMAN OF THE BOARD
Date 3/26/99 /s/ JAMES D. CALAWAY
- ------------------ ------------------------------------
James D. Calaway
PRESIDENT AND CHIEF OPERATING
OFFICER
Date 3/26/99 /s/ MICHAEL G. LONG
- ------------------ ------------------------------------
Michael G. Long
SENIOR VICE PRESIDENT AND CHIEF
FINANCIAL OFFICER
Date 3/26/99 /s/ BRIAN C. BAUMLER
- ------------------ ------------------------------------
Brian C. Baumler
CONTROLLER AND TREASURER
Date 3/26/99 /s/ VINCENT ANDREWS
- ------------------ ------------------------------------
Vincent Andrews
DIRECTOR
Date 3/26/99 /s/ DAVID B. BENEDICT
- ------------------ ------------------------------------
David B. Benedict
DIRECTOR
44
Date 3/26/99 /s/ NILS P. PETERSON
- ------------------ ------------------------------------
Nils P. Perterson
DIRECTOR
Date 3/26/99 /s/ STANLEY S. RAPHAEL
- ------------------ ------------------------------------
Stanley S. Raphael
DIRECTOR
Date 3/26/99 /s/ JOHN SFONDRINI
- ------------------ ------------------------------------
John Sfondrini
DIRECTOR
Date 3/26/99 /s/ ROBERT W. SHOWER
- ------------------ ------------------------------------
Robert W. Shower
DIRECTOR
Date 3/26/99 /s/ WILLIAM H. WHITE
- ------------------ ------------------------------------
William H. White
DIRECTOR
45
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, 1998 and 1997............................................. F-3
Consolidated Statements of Operations for the Years Ended December 31, 1998, 1997 and 1996............... F-4
Consolidated Statements of Cash Flows for the Years Ended December 31, 1998, 1997 and 1996............... F-5
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 1998, 1997 and 1996..... F-6
Notes to Consolidated Financial Statements............................................................... F-7
Unaudited Information:
Supplementary Information to Consolidated Financial Statements........................................... F-20
CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
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
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, 1998 and 1997, and the related consolidated statements of operations,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1998. 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, 1998 and 1997,
and the results of its operations and its cash flows for each of the three years
in the period ended December 31, 1998, in conformity with generally accepted
accounting principles.
As discussed in Note 1 to the consolidated financial statements, effective
January 1, 1998 the Company changed its method of accounting for direct internal
geological and geophysical costs to one of capitalization of such costs, which
are directly attributable to acquisition, exploration and development
activities, to oil and natural gas properties.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 26, 1999
F-2
EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31,
----------------------
1998 1997
---------- ----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents........................................ $ 272,428 $3,777,950
Accounts receivable, trade....................................... 2,237,113 2,394,497
Accounts receivable, joint interest owners, net.................. 2,215,096 6,547,619
Receivables from related parties................................. 228,922 385,192
Other current assets............................................. 313,631 352,571
---------- ----------
Total current assets........................................... 5,267,190 13,457,829
PROPERTY AND EQUIPMENT, Net--full cost method of accounting for oil
and natural gas properties....................................... 47,258,993 36,662,521
INVESTMENT IN FRONTERA............................................. 3,744,935 3,628,264
OTHER ASSETS....................................................... 7,789 17,232
---------- ----------
TOTAL ASSETS....................................................... $56,278,907 $53,765,846
---------- ----------
---------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade.......................................... $4,390,824 $4,794,037
Accrued liabilities.............................................. 2,337,848 1,060,645
Accrued interest payable......................................... 93,880
Current portion of long-term debt................................ 6,700,000
---------- ----------
Total current liabilities...................................... 13,522,552 5,854,682
LONG-TERM DEBT..................................................... 5,800,000
---------- ----------
Total liabilities.............................................. 19,322,552 5,854,682
---------- ----------
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY
Preferred stock, $.01par value; 5,000,000 shares authorized; none
outstanding
Common stock, $.01par value; 25,000,000 shares authorized;
7,772,032 and 7,760,869 shares issued and outstanding at
December 31, 1998 and 1997, respectively....................... 77,720 77,609
Additional paid-in capital....................................... 47,769,159 47,629,822
Retained earnings (deficit)...................................... (9,398,410) 3,825,009
Unearned compensation--restricted stock.......................... (1,492,114) (3,621,276)
---------- ----------
Total stockholders' equity..................................... 36,956,355 47,911,164
---------- ----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY......................... $56,278,907 $53,765,846
---------- ----------
---------- ----------
See accompanying notes to the consolidated financial statements.
F-3
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
----------- ---------- ---------
OIL AND NATURAL GAS REVENUES........................... $15,463,432 $13,468,042 $7,719,478
OPERATING EXPENSES:
Oil and natural gas operating expenses............... 3,375,759 2,330,648 1,600,085
Depletion, depreciation, and amortization............ 10,002,533 2,875,457 1,613,022
Impairment of oil and natural gas properties......... 10,012,989
General and administrative expenses.................. 4,582,973 4,641,374 2,752,562
Unearned compensation expense........................ 621,191 513,393
Other charge......................................... 2,898,125
----------- ---------- ---------
Total operating expenses........................... 31,493,570 10,360,872 5,965,669
----------- ---------- ---------
OPERATING INCOME (LOSS)................................ (16,030,138) 3,107,170 1,753,809
OTHER INCOME AND (EXPENSE):
Interest expense..................................... (90,075) (183,028) (858,663)
Interest income...................................... 132,993 900,867
Other Income......................................... 232,500
----------- ---------- ---------
NET INCOME (LOSS) BEFORE INCOME TAXES, MINORITY
INTEREST AND CUMULATIVE EFFECT OF ACCOUNTING
CHANGE............................................... (15,987,220) 3,825,009 1,127,646
INCOME TAX BENEFIT (EXPENSE)........................... 982,966 (394,675)
MINORITY INTEREST...................................... (432,786)
----------- ---------- ---------
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF
ACCOUNTING CHANGE.................................... (15,004,254) 3,825,009 300,185
CUMULATIVE EFFECT OF ACCOUNTING CHANGE................. 1,780,835
----------- ---------- ---------
NET INCOME (LOSS)...................................... $(13,223,419) $3,825,009 $ 300,185
----------- ---------- ---------
----------- ---------- ---------
BASIC EARNINGS (LOSS) PER SHARE:
Net income (loss) before cumulative effect of
accounting change.................................. $ (1.93) $ 0.53 $ 0.06
Cumulative effect of accounting change............... 0.23
----------- ---------- ---------
Basic earnings (loss) per share...................... $ (1.70) $ 0.53 $ 0.06
----------- ---------- ---------
----------- ---------- ---------
DILUTED EARNINGS (LOSS) PER SHARE:
Net income (loss) before cumulative effect of
accounting change.................................. $ (1.93) $ 0.52 $ 0.06
Cumulative effect of accounting change............... 0.23
----------- ---------- ---------
Diluted earnings (loss) per share.................... $ (1.70) $ 0.52 $ 0.06
----------- ---------- ---------
----------- ---------- ---------
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING.......................................... 7,772,027 7,274,617 4,701,361
----------- ---------- ---------
----------- ---------- ---------
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING.......................................... 7,772,027 7,320,400 4,701,361
----------- ---------- ---------
----------- ---------- ---------
See accompanying notes to the consolidated financial statements.
F-4
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31,
-------------------------------------
1998 1997 1996
----------- ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)...................................................... $(13,223,419) $ 3,825,009 $ 300,185
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Cumulative effect of accounting change............................... (1,780,835)
Depletion, depreciation and amortization............................. 10,002,533 2,875,457 1,613,022
Impairment of oil and natural gas properties......................... 10,012,989
Deferred income taxes................................................ (982,966) 394,675
Unearned compensation expense........................................ 2,268,610 513,393
Minority interest.................................................... 432,786
Changes in assets and liabilities:
Accounts receivable, trade........................................... 157,384 (355,608) (870,969)
Accounts receivable, joint interest owners, net...................... 4,332,523 (3,888,594) (2,325,473)
Receivable from related parties...................................... 156,270 (198,630) (60,618)
Other current assets................................................. 38,940 (238,115) (54,105)
Other assets......................................................... 9,443 1,088
Accounts payable, trade.............................................. (403,213) 2,292,013 1,357,616
Accounts payable to related parties.................................. 66,623
Accrued interest payable............................................. 93,880 (74,354) 27,936
Accrued liabilities.................................................. 1,301,259 (606,292) 1,442,388
Long-term liability.................................................. (46,245)
----------- ----------- -----------
Net cash provided by operating activities.......................... 11,983,398 4,145,367 2,277,821
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchases of prospects and property and equipment...................... (34,823,922) (29,874,155) (10,466,754)
Proceeds from the sale of prospects and oil and natural gas
properties........................................................... 6,951,673 2,325,418 4,815,779
Investment in Frontera................................................. (116,671) (3,628,264)
----------- ----------- -----------
Net cash used in investing activities.............................. (27,988,920) (31,177,001) (5,650,975)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from notes payable............................................ 12,500,000 867,350 5,987,000
Payment on notes payable............................................... (11,017,348) (249,070)
Payment on long-term notes payable..................................... (411,904)
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)
Deferred offering cost................................................. (1,006,379)
----------- ----------- -----------
Net cash provided by financing activities.......................... 12,500,000 29,266,356 4,715,551
----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS..................... (3,505,522) 2,234,722 1,342,397
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD........................... 3,777,950 1,543,228 200,831
----------- ----------- -----------
CASH AND CASH EQUIVALENTS, END OF PERIOD................................. $ 272,428 $ 3,777,950 $ 1,543,228
----------- ----------- -----------
----------- ----------- -----------
SUPPLEMENTAL CASH FLOW DISCLOSURES--Cash paid for interest............... $ 415,820 $ 257,382 $ 844,849
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
See accompanying notes to consolidated financial statements.
F-5
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
OLD EDGE
COMMON STOCK COMMON STOCK ADDITIONAL
---------------------- -------------------- PAID-IN TREASURY
SHARES AMOUNT SHARES AMOUNT CAPITAL STOCK
--------- ----------- --------- --------- ----------- ---------
BALANCE, JANUARY 1, 1996........................... 105,263 $ 1,053 $ 634,695 $ (26,000)
Tresuary stock purchase, 422 shares................ (32,000)
Issuance of treasury stock, 211 shares............. 16,000
Net income.........................................
--------- ----------- --------- --------- ----------- ---------
BALANCE, DECEMBER 31, 1996......................... 105,263 1,053 634,695 (42,000)
Combination...................................... (105,263) (1,053) 4,701,361 $ 47,014 2,544,557 42,000
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.......................................
--------- ----------- --------- --------- ----------- ---------
BALANCE, DECEMBER 31, 1997......................... 7,760,869 77,609 47,629,822
Issuance of restricted common stock.............. 12,025 120 148,762
Forfeiture of restricted common stock............ (862) (9) (9,425)
Unearned compensation expense....................
Net loss.........................................
--------- ----------- --------- --------- ----------- ---------
BALANCE, DECEMBER 31, 1998......................... -- $ -- 7,772,032 $ 77,720 $47,769,159 $ --
--------- ----------- --------- --------- ----------- ---------
--------- ----------- --------- --------- ----------- ---------
UNEARNED TOTAL
RETAINED COMPENSATION - STOCKHOLDERS'
EARNINGS RESTRICTED EQUITY
(DEFICIT) STOCK (DEFECIT)
---------------- -------------- --------------
BALANCE, JANUARY 1, 1996........................... $ (1,267,302) $ (657,554)
Tresuary stock purchase, 422 shares................ (32,000)
Issuance of treasury stock, 211 shares............. 16,000
Net income......................................... 300,185 300,185
---------------- -------------- --------------
BALANCE, DECEMBER 31, 1996......................... (967,117) (373,369)
Combination...................................... 967,117 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 3,825,009
---------------- -------------- --------------
BALANCE, DECEMBER 31, 1997......................... 3,825,009 (3,621,276) 47,911,164
Issuance of restricted common stock.............. (148,882)
Forfeiture of restricted common stock............ 9,434
Unearned compensation expense.................... 2,268,610 2,268,610
Net loss......................................... (13,223,419) (13,223,419)
---------------- -------------- --------------
BALANCE, DECEMBER 31, 1998......................... $ (9,398,410) $ (1,492,114) $ 36,956,355
---------------- -------------- --------------
---------------- -------------- --------------
See accompanying notes to the consolidated financial statements.
F-6
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
GENERAL--The Company was organized as a Delaware corporation in August 1996
in connection with the Offering and related combination of certain entities that
held interests in Edge Joint Venture II (the "Joint Venture") and certain other
oil and natural gas properties; herein referred to as the "Combination". In a
series of combination transactions the Company issued an aggregate of 4,701,361
shares of common stock and received in exchange 100% of the ownership interests
in the Joint Venture and certain other oil and natural gas properties. In March
1997, and contemporaneously with the Combination, the Company completed the
Offering of 2,760,000 shares of its common stock generating proceeds of
approximately $40 million, net of expenses.
NATURE OF OPERATIONS--The Company is an independent energy company engaged
in the exploration, development and production of oil and natural gas. The
Company conducts its operations primarily along the onshore United States Gulf
Coast, with its primary emphasis in South Texas and Louisiana where it currently
controls interests in excess of 222,000 gross acres held under lease or option.
In its exploration efforts the Company emphasizes an integrated geologic
interpretation method incorporating 3-D seismic technology and advanced
visualization and data analysis techniques utilizing state-of-the-art computer
hardware and software.
PRINCIPLES OF CONSOLIDATION--The consolidated financial statements as of and
for the years ended December 31, 1998 and 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.
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 are presented using the
historical costs and results of operations of the affiliated entities as if such
entities had always been combined. The consolidated financial statements include
the accounts of Edge Petroleum Corporation, a Texas corporation, ("Old Edge")
and the Joint Venture, both of which share common ownership and management. For
the periods prior to the Combination, the Joint Venture interests not owned by
Old Edge are recorded as minority interest. All intercompany balances were
eliminated upon the Combination and all assets and liabilities were assumed by
the Company.
ACCOUNTING CHANGE--The Company uses the full-cost method of accounting for
its oil and natural gas properties. Under this method, all acquisition,
exploration and development costs that are directly attributable to the
Company's acquisition, exploration and development activities are capitalized in
a "full-cost pool" as incurred. In the second quarter of 1998 and effective
January 1, 1998, the Company changed its method of accounting for direct
internal geological and geophysical ("G&G") costs to one of capitalization of
such costs, which are directly attributable to acquisition, exploration and
development activities, to oil and natural gas properties. Prior to the change
the Company expensed these costs as incurred. The Company believes the
accounting change provides for a better matching of revenues and expenses and
enhances the comparability of it's financial statements with those of other
companies that follow the full-cost method of accounting. The $1,780,835
cumulative effect of the change in prior years (after reduction for income taxes
of $958,910) is included in the net loss for the year ended December 31, 1998.
The effect of the accounting change (reduced G&A offset by increased DD&A) on
the year ended December 31, 1998 was to decrease the net loss by $1,646,187
($0.21 basic and diluted loss per share).
F-7
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
The following pro forma amounts reflect the effect of retroactive
application of the accounting change on general and administrative expenses,
depletion and related income taxes.
YEAR ENDED
DECEMBER 31,
---------------------------------
1998 1997 1996
----------- --------- ---------
Net income (loss):
As reported........................... $(13,223,419) $3,825,009 $ 300,185
----------- --------- ---------
Pro forma............................. $(15,004,254) $4,005,275 $1,113,145
----------- --------- ---------
Basic earnings (loss) per share:
As reported........................... $ (1.70) $ 0.53 $ 0.06
----------- --------- ---------
Pro forma............................. $ 1.93 $ 0.55 $ 0.24
----------- --------- ---------
Diluted earnings (loss) per share:
As reported........................... $ (1.70) $ 0.52 $ 0.06
----------- --------- ---------
Pro forma............................. $ 1.93 $ 0.55 $ 0.24
----------- --------- ---------
Basic weighted average number of common
shares outstanding.................... 7,772,027 7,274,617 4,701,361
----------- --------- ---------
Diluted weighted average number of
common shares outstanding............. 7,772,027 7,320,400 4,701,361
----------- --------- ---------
OTHER CHARGE--Effective November 16, 1998, John E. Calaway resigned as
Chairman of the Board, and Chief Executive Officer ("CEO") and Director of the
Company. As a result of his resignation the Company recorded a one-time charge
of approximately $2.9 million to satisfy corporate obligations under his
employment contract. Included in the $2.9 million is a $1.6 million non-cash
amount relating to vesting of the remaining balance of Mr. Calaway's restricted
common stock award granted concurrent with the Company's Offering (see Note 7).
The balance of the special charge primarily represents cash payments to be paid
to Mr. Calaway from the date of his resignation date to January, 2000, of which
$623,000 has been paid as of December 31, 1998.
REVENUE RECOGNITION--The Company recognizes oil and natural gas revenue from
its interests in producing wells as oil and natural gas is produced and sold
from those wells. Oil and natural gas sold by the Company is not significantly
different from the Company's share of production.
OIL AND NATURAL GAS PROPERTY--Investments in oil and natural gas properties
are accounted for using the full cost method of accounting. All costs associated
with the acquisition, exploration and development of oil and natural gas
properties are capitalized.
Oil and natural gas properties are amortized using the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the prospects
can be determined or until impairment occurs. If the results of an assessment
indicates that an unproved property is impaired, the amount of impairment is
added to the proved oil and natural gas property costs to be amortized. The
amortizable base includes estimated future development costs and, where
significant, dismantlement, restoration and abandonment costs, net of estimated
salvage values. The depletion rates per Mcfe for the years ended December 31,
1998, 1997 and 1996 were $1.30, $0.47 and $0.45, respectively.
F-8
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Sales of proved and unproved properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves. Abandonments of oil and natural gas properties are accounted for as
adjustments of capitalized costs with no loss recognized.
In addition, the capitalized costs of oil and natural gas properties are
subject to a "ceiling test," whereby to the extent that such capitalized costs
subject to amortization in the full cost pool (net of depletion, depreciation
and amortization and related deferred taxes) exceed the present value (using 10%
discount rate) of estimated future net after-tax cash flows from proved oil and
natural gas reserves, such excess costs are charged to operations. Once incurred
an impairment of oil and natural gas properties is not reversible at a later
date. Impairment of oil and natural gas properties is assessed on a quarterly
basis in conjunction with the Company's quarterly filings with the Securities
and Exchange Commission. At December 31, 1998 the Company recorded a full cost
ceiling test write down of its oil and natural gas properties of approximately
$10 million.
Depreciation of other office furniture and equipment and computer hardware
and software is provided using the straight-line method based on estimated
useful lives ranging from five to ten years.
INCOME TAXES--The Company accounts for income taxes under the provisions of
Statement of Financial Accounting Standards No. 109--"Accounting for Income
Taxes," ("SFAS No. 109") which provides for an asset and liability approach for
accounting for income taxes. Under this approach, deferred tax assets and
liabilities are recognized based on anticipated future tax consequences, using
currently enacted tax laws, attributable to differences between financial
statement carrying amounts of assets and liabilities and their respective tax
bases.
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
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. During
1997 and 1998 the Company had in place several natural gas commodity collars
with a financial institution covering 5,000-20,000 MMbtus per day, or
approximately 30%-60% of the Company's daily production. Prices received float
between a floor and cap price per MMbtu, (delivered price basis, Houston Ship
Channel), with settlement for each calendar month occurring five business days
following the publishing of the Inside
F-9
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
F.E.R.C. Gas Marketing Report. Included within natural gas revenues for the
years ended December 31, 1997 and 1998 was approximately $33,000 and $482,000,
respectively, representing net settlement gains from collar activities. There
were no active collar agreements in place at December 31, 1998. During December
1998, the Company entered into a fixed price swap for $1.96 per MMbtu. This
fixed price swap covers 13,000 MMbtu per day, or approximately 65% of daily
production, and is effective beginning March 1, 1999 and expires on October 31,
1999. There was no material hedging activity during the year ended December 31,
1996.
STATEMENTS OF CASH FLOWS--The consolidated statements of cash flows are
presented using the indirect method and consider all highly liquid investments
with original maturities of three months or less to be cash equivalents.
INVESTMENT IN FRONTERA--In August 1997, the Company acquired 15,171 shares
of Series D Preferred Stock of Frontera Resources Corporation ("Frontera") were
initially 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 Jura 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.
Pursuant to a rights offering conducted in November 1998, the Company agreed
to purchase 44,027 shares of Frontera Common Stock plus such additional shares,
if necessary, to maintain its current 8.73% interest of diluted outstanding
Frontera Stock (assuming conversion of all preferred stock). The rights offering
consisted of two tranches. The Company paid $116,671 in December, 1998 in
connection with the first tranche and exercised an option to acquire an
additional 2,123 shares in January 1999. Should the Company exercise the second
tranche of the rights offering (the Company believes this will happen during the
first quarter of 1999) the Company will be obligated to purchase another 44,027
shares to maintain is approximate 8.73% interest.
The Company believes that the fair market value of its investment in
Frontera approximates its carrying value.
STOCK-BASED COMPENSATION--The Company accounts for Stock Based Compensation
in accordance with Financial Accounting Standards Board Statement No.
123--"Accounting for Stock Based Compensation," ("SFAS No. 123"). Under SFAS No.
123, the Company is permitted to either record expenses for stock options and
other employee compensation plans based on their fair value at the date of grant
or to continue to apply its current accounting policy under Accounting
Principles Board Opinion No. 25 ("APB No.25") and recognize compensation
expense, if any, based on the intrinsic value of the equity instrument at the
measurement date. The Company elected to continue following APB No. 25. The
adoption of SFAS No. 123 in 1997 had no effect on the Company's results of
operations (see Note 7).
F-10
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
EARNINGS PER SHARE--The Company accounts for its Earnings per share in
accordance with Statement of Financial Accounting Standards No. 128--"Earnings
per Share," ("SFAS No. 128") which establishes the requirements for presenting
earnings per share ("EPS"). SFAS No. 128 requires the presentation of "basic"
and "diluted" EPS on the face of the income statement. Basic earnings per common
share amounts are calculated using the average number of common shares
outstanding during each period. Diluted earnings per share assumes the exercise
of all stock options having exercise prices less than the average market price
of the common stock using the treasury stock method.
As a result of the Combination the earnings per share 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. Net income (loss) 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, 1994.
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 value
because of the short-term nature of these items. The carrying amount of
long-term debt as of December 31, 1998 approximates fair value and the fair
value of the natural gas commodity hedge was approximately $(292,000) at
December 31, 1998.
DERIVATIVES--In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standard No. 133, "Accounting for Derivative
Instruments and Hedging Activity" ("SFAS 133"). SFAS 133 establishes accounting
and reporting standards for derivative instruments and hedging activities that
require an entity to recognize all derivatives as an asset or liability measured
at fair value. Depending on the intended use of the derivatives, changes in its
fair value will be reported in the period of change as either a component of
earnings or a component of other comprehensive income.
SFAS 133 is effective for all fiscal quarters beginning after June 15, 1999.
Earlier application of SFAS 133 is encouraged, but not prior to the beginning of
any fiscal quarter that begins after issuance of the statement. Retroactive
application to periods prior to adoption is not allowed. The Company has not
quantified the impact of adoption on its financial statements or the date it
intends to adopt.
COMPREHENSIVE INCOME--In June 1997, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 130, "Reporting of
Comprehensive Income" ("SFAS 130"). SFAS 130 establishes standards for reporting
and displaying comprehensive income and its components. SFAS 130 is effective
for periods beginning after December 15, 1997. The purpose of reporting
comprehensive income is to report a measure of all changes in equity of an
enterprise that results from recognized transactions and other economic events
of the period other than transactions with owners in their capacity as owners.
As of December 31, 1998, there are no adjustments ("Other Comprehensive Income")
to net income (loss) in deriving comprehensive income.
USE OF ESTIMATES--The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make estimates
and assumptions that affect the reported 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
F-11
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
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 but due to deteriorating market conditions the
Company can not ensure that such losses may not be realized in the future.
RECLASSIFICATIONS--Certain prior year balances have been reclassified to
conform to the current year presentation.
2. PROPERTY AND EQUIPMENT
At December 31, 1998 and 1997, property and equipment consisted of the
following:
DECEMBER 31,
-----------------------
1998 1997
----------- ----------
Developed oil and natural gas properties.......................... $48,441,741 $16,100,052
Undeveloped oil and natural gas properties........................ 21,388,831 22,937,927
Computer equipment and software................................... 3,663,335 3,238,182
Other office property and equipment............................... 1,282,273 1,225,183
----------- ----------
Total property and equipment...................................... 74,776,180 43,501,344
Accumulated depletion, depreciation and amortization.............. (27,517,187) (6,838,823)
----------- ----------
Property and equipment, net....................................... $47,258,993 $36,662,521
----------- ----------
----------- ----------
Undeveloped oil and natural gas properties are not subject to amortization
and consist of the cost of undeveloped leaseholds, exploratory and developmental
wells in progress, and secondary recovery projects before the assignment of
proved reserves. These costs are reviewed periodically by management for
impairment, with the impairment provision included in the cost of oil and
natural gas properties subject to amortization. Factors considered by management
in its impairment assessment include drilling results by the Company and other
operators, the terms of oil and natural gas leases not held by production,
production response to secondary recovery activities and available funds for
exploration and development.
The following table summarizes the cost of the properties not subject to
amortization for the year the cost was incurred:
DECEMBER 31,
----------------------
1998 1997
---------- ----------
Year cost incurred:
Remainder........................................ $ 172,991 $ 346,110
1995............................................. 182,210 454,716
1996............................................. 943,055 1,675,038
1997............................................. 4,489,822 20,462,063
1998............................................. 15,600,753
---------- ----------
Total............................................ $21,388,831 $22,937,927
---------- ----------
---------- ----------
F-12
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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 provided up to $20 million in
borrowings limited by a borrowing base, as defined by the Revolving Credit
Facility. The Revolving Credit Facility provided for interest at the lender's
prime rate plus 0.75%. The borrowing base was subject to review by the bank on a
quarterly basis and could 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 with proceeds from its initial public offering.
Effective April 1, 1998, the Company amended and restated its Revolving Credit
Facility to provide a revolving line of credit of up to $100 million bearing
interest at a rate equal to prime or LIBOR plus 1.5%-2% depending on the level
of borrowing base utilization. The Company's initial borrowing base authorized
by the banks was approximately $15 million.
Effective September 29, 1998, the Company had its borrowing base
redetermined and amended its Revolving Credit Facility. The initial borrowing
base authorized by the bank was $15 million. Beginning October 1, 1998, and on
the first day of each month thereafter, the borrowing base was required to be
reduced by $550,000.
At December 31, 1998, borrowings under this facility totaled $12.5 million
with approximately $850,000 available for future borrowings. The weighted
average debt and interest rate during the year ended December 31, 1998 was
approximately $7 million and 7.3%, respectively.
The Revolving Credit Facility provides for certain restrictions, including
but not limited to, limitations on additional borrowings and issues of capital
stock, sales of its oil and natural gas properties or other collateral, engaging
in merger or consolidation transactions and prohibitions of dividends and
certain distributions of cash or properties and certain liens. The Revolving
Credit Facility also contains the following financial covenants: (i) tangible
net worth (total assets exclusive of certain intangibles minus liabilities) must
be at least $43 million plus 50% of positive net income and 100% of equity
raised for all quarterly periods subsequent to December 31, 1997; (ii) the ratio
at the end of any quarter of cash flow (net income plus proceeds of certain
project sales, depletion, depreciation, amortization and other non-cash expenses
less non-cash net income for such quarter) to debt service must be at least 1.25
to 1.00; and (iii) the ratio at the end of any quarter of EBIT (net income plus
interest expense and taxes, excluding non-cash, extraordinary expenses and
income) to interest expense for the proceeding 12-month period must be at least
4.5 to 1.00. At December 31, 1998 the Company was not in compliance with two of
its financial covenants, (i) and (iii) above, and accordingly has received
waivers from its bank for its noncompliance. There can be no assurance that the
Company will not require waivers in the future or, if required, that the bank
will grant them. The Revolving Credit Facility is secured by substantially all
the assets of the Company.
At December 31, 1998, based on amounts paid and to be paid in 1999 under the
Revolving Credit Facility, as restructured, current maturities of long-term debt
and long-term debt consisted of the following:
Revolving credit facility, interests rates at 7%-7.75%......... $12,500,000
Current portion................................................ (6,700,000)
----------
Long-term portion.............................................. $5,800,000
----------
----------
There was no outstanding notes payable or long-term debt at December 31,
1997.
F-13
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. LONG-TERM DEBT (CONTINUED)
Subsequent to December 31, 1998, the Company undertook discussions with the
bank to restructure the Revolving Credit Facility. On March 18, 1999 the Company
and the Bank agreed on new terms which are as follows; 1) the proposed initial
borrowing base is $12 million comprised of a two tranche financing of a $9
million Revolving Credit Facility and $3 million of subordinated debt, 2)
Beginning May 1, 1999, and on the first day of each month thereafter, the
Revolving Credit Facility borrowing base is required to be reduced by $400,000,
3) 75% of prospect sales will be used to pay down the subordinated debt with the
remaining unpaid subordinated balance maturing on August 31, 1999. The Bank has
also agreed to amend the financial covenants on a go forward basis are as
follows; tangible net worth will be 90% of actual tangible net worth as reported
at December 31, 1998 (or $33,260,720); the EBIT to interest expense and cash
flow coverage covenants will be eliminated and replaced with a quarterly fixed
charge coverage test calculated as annualized EBITDA divided by the total of
interest expense plus 50% of quarter end loan outstanding and the covenant level
would be 1.25 to 1.00. The fixed charge coverage covenant does not apply until
June 30, 1999.
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 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, 1998, 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:
1999............................................................ $ 267,957
2000............................................................ 267,957
2001............................................................ 267,957
2002............................................................ 267,957
2003............................................................ 44,659
---------
Total........................................................... $1,116,487
---------
---------
Rent expense for the years ended December 31, 1998, 1997 and 1996 was
$478,652, $214,143 and $204,376, 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.
F-14
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. INCOME TAXES (CONTINUED)
Significant components of the Company's deferred tax liabilities and assets
as of December 31, 1998 and 1997 are as follows:
1998 1997
--------- ---------
Deferred tax liability:
Book basis of oil and natural gas properties in excess of tax
basis............................................................ $2,633,825 $2,246,201
Deferred tax asset:
Other charge not currently deductable for tax purposes............. 792,708
Net operating loss carryforwards................................... 7,142,358 2,046,680
Statutory depletion carryforward................................... 140,390 140,390
Other miscellaneous................................................ 146,630 59,131
Valuation allowance................................................ (5,588,261)
--------- ---------
Total................................................................ 2,633,825 2,246,201
--------- ---------
Net deferred tax liability........................................... $ -- $ --
--------- ---------
--------- ---------
The differences between the statutory federal income taxes and the Company's
effective taxes is summarized as follows:
1998 1997 1996
---------- --------- ---------
Statutory federal income taxes............................ $(5,595,527) $1,338,753 $ 394,675
Permanent differences:
Expense not deductible for tax purposes................. 7,266 10,483 7,546
Income not taxable to the company....................... (66,961)
Temporary differences:
Non-Statutory stock options............................. (224,617)
Cumulative effect of accounting change.................. (958,910)
Other................................................... (24,056)
Change in valuation allowance........................... 5,588,261 (1,057,658) (7,546)
---------- --------- ---------
Income tax expense (benefit).............................. $ (982,966) $ -- $ 394,675
---------- --------- ---------
---------- --------- ---------
The differences between the statutory federal income taxes and the Company's
effective taxes is summarized as follows:
At December 31. 1998, the Company had cumulative net operating loss
carryforwards ("NOL") for federal income tax purposes of approximately $20.4
million which will begin to expire in 2007. The net operating loss carryforwards
assume that certain items, primarily intangible drilling costs have been written
off in the current year. However, the Company has not made a final determination
if an election will be made to capitalize all or part of these items for tax
purposes. Due to the 1997 ownership change of Old Edge and the Joint venture,
future utilization of the NOLs may be limited by the Internal Revenue Code
Section 382.
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
F-15
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. INCOME TAXES (CONTINUED)
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. On a pro forma basis, had the
Company been a tax paying entity from inception (April 1, 1991), the Company
would not have recorded a tax provision in any period prior to the Combination.
Thus the tax provision, as reported by the Company, for the year ended December
31, 1996 approximates what would have been reported on a pro forma basis had the
combining entities always been combined.
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, 1998 and 1997 the
Company contributed $68,869 and $40,954, respectively, to the Plan.
7. EQUITY AND STOCK PLANS
On March 3, 1997 the Combination Transactions were consummated resulting in
the issuance of 4,701,361 shares to the predecessor owners of the combining
entities involved in the Combination (see Note 1). In addition, during March
1997, the Company completed its Offering issuing 2,760,000 shares at $16.50 per
share. Net proceeds totaled $40 million, net of offering cost of approximately
$5.4 million.
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 1,200,000 shares of Common
Stock have been reserved for grants under the Incentive Plan, of which 271,483
shares were available for future grants at December 31, 1998 (these shares
include only those issued under the Incentive Plan). Shares of Common Stock
awarded as restricted stock are subject to restrictions on transfer and subject
to risk of forfeiture until earned by continued employment or service or
achievement of certain performance milestones. During 1998 and 1997, 2,412 and
250,586 shares, respectively, of restricted stock were awarded having a market
value of $12.38 and $16.50, respectively, per share as of the award date. The
total market value of such awards has been recorded as unearned
compensation-restricted stock and is shown as a separate component of
stockholders' equity. The unearned compensation-restricted stock is amortized to
operations over the related vesting period. Amortization of unearned
compensation expense amounted to $621,191 and $513,393 in 1998 and 1997,
respectively.
Effective November 16, 1998, Mr. John E. Calaway resigned as Chairman of the
Board, Chief Executive Officer and a director of the Company. In connection with
his resignation his remaining restricted stock, 106,916 shares, became fully
vested. Included in "Other charge" is the amortization of approximately $1.6
million of unearned compensation expense resulting from the vesting of those
restricted shares.
F-16
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. EQUITY AND STOCK PLANS (CONTINUED)
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. Of these shares
48,922 were exercised during 1997 and 48,922 remain outstanding at December 31,
1997 and 1998.
A summary of the status of the Company's stock options and changes as of and
for each of the two years ended December 31, 1998 and 1997 are presented below:
1998 1997
------------------------ ------------------------
WEIGHTED AVG. WEIGHTED AVG.
EXERCISE EXERCISE
SHARES PRICE SHARES PRICE
--------- ------------- --------- -------------
Outstanding, January 1........... 696,365 $ 15.63 --
Granted.......................... 107,600 12.76 773,040 $ 14.80
Forfeited........................ (74,910) 16.01 (27,753) 16.50
Exercised........................ (48,922) 2.04
--------- ---------
Outstanding, December 31......... 729,055 $ 15.17 696,365 $ 15.63
--------- ---------
--------- ---------
Exercisable, December 31......... 272,785 $ 14.27 48,922 $ 4.09
--------- ---------
--------- ---------
OPTIONS OUTSTANDING AS OF DECEMBER 31, 1998 OPTIONS EXERCISABLE
----------------------------------------------- --------------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
RANGE OF SHARES REMAINING EXERCISE SHARES EXERCISE
EXERCISE PRICE OUTSTANDING CONTRACTUAL LIFE PRICE EXERCISABLE PRICE
- --------------- ----------- ------------------- ------------- ----------- -------------
$4.09 48,922 8.17 $ 4.09 48,922 $ 4.09
$8.88-$10.00 5,000 9.75 $ 8.88
$10.00-$13.50 90,400 9.50 $ 12.87
$13.50-$16.50 584,733 8.17 $ 16.50 223,863 $ 16.50
The Company applies the intrinsic value based method of APB No.25 in
accounting for its stock options. Accordingly, no compensation expense has been
recognized for any stock options granted. Had compensation expense for the
Company's stock options granted during the years ended December 31, 1998 and
1997 been determined based on the fair value at the grant dates, consistent with
the methodology prescribed by SFAS No.123, the Company's net income and earnings
per share would have been reduced to the amounts indicated below based on the
Black-Scholes option pricing model (the "Model") adopted for the use in valuing
stock options. The estimated values under the Model are based on the following
assumptions for the year ended December 31, 1998 and 1997: expected volatility
based on historical volatility of daily Common Stock Prices (53% and 41%,
respectively), a risk free rate of return based on a discount rate which
approximates the U.S. Treasury rate at the time of the grant, no dividend
yields, an
F-17
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
7. EQUITY AND STOCK PLANS (CONTINUED)
expected option exercise period of 8 years (with the exercise occurring at the
end of such period) and a forfeiture rate of 0%-10% over the vesting period of
such options.
1998 1997
-------------- ------------
Net Income (Loss):
As reported................................................... $ (13,223,419) $ 3,825,009
Pro forma..................................................... $ (13,743,611) $ 3,454,671
As Reported
Basic earnings (loss) per share:
Net income (loss) before cumulative effect of accounting
change.................................................... $ (1.93) $ 0.53
Cumulative effect of accounting change...................... 0.23 --
-------------- ------------
Basic earnings (loss) per share............................. $ (1.70) $ 0.53
-------------- ------------
-------------- ------------
Diluted earnings (loss) per share:
Net income (loss) before cumulative effect of accounting
change.................................................... $ (1.93) $ 0.52
Cumulative effect of accounting change...................... 0.23 --
-------------- ------------
Diluted earnings (loss) per share........................... $ (1.70) $ 0.52
-------------- ------------
-------------- ------------
Pro forma
Basic earnings (loss) per share:
Net income (loss) before cumulative effect of accounting
change.................................................... $ (2.00) $ 0.47
Cumulative effect of accounting change...................... 0.23 --
-------------- ------------
Basic earnings (loss) per share............................. $ (1.77) $ 0.47
-------------- ------------
-------------- ------------
Diluted earnings (loss) per share:
Net income (loss) before cumulative effect of accounting
change.................................................... $ (2.00) $ 0.47
Cumulative effect of accounting change...................... 0.23 --
-------------- ------------
Diluted earnings (loss) per share........................... $ (1.77) $ 0.47
-------------- ------------
-------------- ------------
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
------------ ------------- -----------
F-18
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
7. EQUITY AND STOCK PLANS (CONTINUED)
For the year ended December 31, 1998, the Company reported a net loss thus
the effects of stock options are antidilutive. For the year ended December 31,
1996 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 for the year ended December 31, 1996. In conjunction with the
Combination, and as a component of the Edge Group II Exchange Offer, these fees
were settled with the general partners of Edge Group II during 1997.
At December 31, 1997, included in receivables from related parties was
$85,681 representing amounts due from directors and employees of the Company.
There were no material amounts outstanding at December 31, 1998.
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,
1998, 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 three years ended December 31, 1998, 1997 and 1996 amounted to
$3,074, $61,746 and $67,000, respectively. At December 31, 1998 and 1997, the
Company had a receivable from the Essex Joint Ventures of $167,971 and $258,887,
respectively, relating to these management fees, direct expenses, and costs.
F-19
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED):
4TH 3RD 2ND 1ST
QUARTER QUARTER QUARTER QUARTER
---------- ----------- ----------- -----------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
1998
Revenues.......................................... $ 3,847 $ 3,981 $ 3,849 $ 3,786
Operating expenses................................ 19,865 4,538 3,812 3,279
Gross profit (loss)............................... (16,017) (556) 37 506
Other income and (expenses), net.................. (44) (3) 44 46
Income tax (expense) benefit...................... 1,020 191 (34) (194)
Net income (loss)................................. (13,260) (368) 47 358
Basic earnings (loss) per share:
Net income (loss) before cumulative effect of
accounting change............................. $ (1.71) $ (0.05) $ 0.01 $ 0.05
Cumulative effect of accounting change.......... 0.23
Basic earnings (loss) per share................. $ (1.71) $ (0.05) $ 0.01 $ 0.28
Diluted earnings (loss) per share:
Net income (loss) before cumulative effect of
accounting change............................. $ (1.71) $ (0.05) $ 0.01 $ 0.05
Cumulative effect of accounting change.......... 0.23
Diluted earnings (loss) per share:.............. $ (1.71) $ (0.05) $ 0.01 $ 0.28
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), net.................. 134 266 615 (297)
Net income........................................ 772 1,016 1,106 931
Basic earnings per share.......................... $ 0.10 $ 0.13 $ 0.14 $ 0.16
Diluted earnings per share........................ $ 0.10 $ 0.13 $ 0.14 $ 0.16
The sum of the individual quarterly basic and diluted earnings (loss) per
share amounts may not agree with year-to-date basic and diluted earnings (loss)
per share amounts as a result of each period's computation being based on the
weighted average number of common shares outstanding during that period.
Included in operating expenses during the three months ended December 31,
1998 is approximately $10 million representing an impairment of oil and natural
gas properties (see Note 1) and an other charge of approximately $2.9 million
representing a one-time charge to satisfy corporate obligations under the former
CEO's employment contract (see Note 1).
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."
F-20
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
CAPITALIZED COSTS--Capitalized costs and accumulated depletion, depreciation
and amortization relating to the Company's oil and natural gas producing
activities, all of which are conducted within the continental United States, are
summarized below:
DECEMBER 31,
-----------------------------
1998 1997
-------------- -------------
Developed oil and natural gas properties....................... $ 48,441,741 $ 16,100,052
Undeveloped oil and natural gas property....................... 21,388,831 22,937,927
Accumulated depletion, depreciation and amortization........... (25,708,987) (5,698,270)
-------------- -------------
Net capitalized cost........................................... $ 44,121,585 $ 33,339,709
-------------- -------------
COSTS INCURRED--Costs incurred in oil and natural gas property acquisition,
exploration and development activities are summarized below:
YEAR ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------- ------------- ------------
Acquisition Cost:
Unproved....................................... $ 20,852,838 $ 17,659,706 $ 4,489,740
Exploration costs................................ 10,236,188 8,640,530 2,669,082
Development costs................................ 3,249,492 1,207,771 2,342,831
------------- ------------- ------------
Gross costs incurred........................... 34,338,518 27,508,007 9,501,653
Less proceeds from the sales of prospects........ 6,951,673 2,325,418 2,229,835
------------- ------------- ------------
Net cost incurred.............................. $ 27,386,845 $ 25,182,589 $ 7,271,818
------------- ------------- ------------
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:
YEAR ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------- ------------- ------------
Oil and natural gas revenues..................... $ 15,463,432 $ 13,468,042 $ 7,719,478
Operating expenses:
Oil and natural gas operating expenses and ad
valorem taxes................................ 2,438,553 1,459,291 1,063,552
Production taxes............................... 937,206 871,357 536,533
Depletion, depreciation and amortization....... 9,254,412 2,483,539 1,351,113
Impairment of oil and natural gas properties... 10,012,989
------------- ------------- ------------
Results of operations........................ $ (7,179,728) $ 8,653,855 $ 4,768,280
------------- ------------- ------------
F-21
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
RESERVES--Proved reserves are estimated quantities of oil and natural gas
which geological and engineering data demonstrate with reasonable certainty to
be recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods. Proved oil and natural gas reserve quantities
and the related discounted future net cash flows before income taxes (see
Standardized Measure) for the periods presented are based on estimates prepared
by Ryder Scott Company, independent petroleum engineers. Such estimates have
been prepared in accordance with guidelines established by the Securities and
Exchange Commission.
The Companys net ownership interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below.
NATURAL GAS (MCF)
YEAR ENDED DECEMBER 31,
----------------------------------------
1998 1997 1996
------------ ------------ ------------
Proved developed and undeveloped reserves
Beginning of year................................. 29,123,000 13,417,000 8,821,000
Revisions of previous estimates................... (6,834,982) (5,397,141) (1,178,453)
Extensions and discoveries........................ 8,231,477 25,402,000 8,154,000
Sales of natural gas properties................... (63,442)
Production........................................ (6,284,495) (4,298,859) (2,316,105)
------------ ------------ ------------
End of Year..................................... 24,235,000 29,123,000 13,417,000
------------ ------------ ------------
------------ ------------ ------------
Proved developed reserves at year end............... 15,844,000 17,866,000 11,301,000
------------ ------------ ------------
------------ ------------ ------------
Minority interest:
Proved developed and undeveloped, end of year..... 9,517,483
------------
------------
Proved developed, end of year..................... 8,016,477
------------
------------
F-22
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
OIL, CONDENSATE AND NATURAL GAS
LIQUIDS (BBLS)
YEAR ENDED DECEMBER 31,
----------------------------------
1998 1997 1996
---------- ---------- ----------
Proved developed and undeveloped reserves
Beginning of year....................................... 866,186 642,714 708,933
Revisions of previous estimates......................... (401,003) (147,917) (36,746)
Extensions and discoveries.............................. 121,404 537,029 245,703
Sales of oil properties................................. (165,951)
Production.............................................. (141,774) (165,640) (109,225)
---------- ---------- ----------
End of Year........................................... 444,813 866,186 642,714
---------- ---------- ----------
---------- ---------- ----------
Proved developed reserves at year end..................... 308,347 646,009 569,856
---------- ---------- ----------
---------- ---------- ----------
Minority interest:
Proved developed and undeveloped, end of year........... 455,916
----------
----------
Proved developed, end of year........................... 404,233
----------
----------
These quantities include the minority interest in the Joint Venture as the
Joint Venture is consolidated with Old Edge for the year ended December 31, 1996
(see Note 1).
STANDARDIZED MEASURE--The Standardized Measure of Discounted Future Net Cash
Flows relating to the Company's ownership interests in proved oil and natural
gas reserves for each of the three years ended December 31, 1998 is shown below:
YEAR ENDED DECEMBER 31,
----------------------------------------------
1998 1997 1996
-------------- -------------- --------------
Future cash inflows.......................... $ 49,444,900 $ 83,454,087 $ 63,446,170
Future oil and natural gas operating
expenses................................... (11,718,097) (16,228,391) (9,590,565)
Future development costs..................... (3,297,539) (5,957,039) (982,603)
Future income tax expenses................... (16,575,185) (13,797,568)
-------------- -------------- --------------
Future net cash flows........................ 34,429,264 44,693,472 39,075,434
10% discount factor.......................... (11,699,510) (13,450,819) (8,875,265)
-------------- -------------- --------------
Standardized measure of discounted future net
cash flows................................. $ 22,729,754 $ 31,242,653 $ 30,200,169
-------------- -------------- --------------
The Standardized Measure of Discounted Future Net Cash Flows reflects the
consolidation of the Joint Venture for the year ended December 31, 1996. The
minority interest's share of Standardized Measure of Discounted Future Net Cash
Flows is $21,422,792 at December 31, 1996.
Future cash flows are computed by applying year-end prices of oil and
natural gas to year-end quantities of proved oil and natural gas reserves.
Future oil and natural gas operating expenses and development costs are computed
primarily by the Company's petroleum engineers and are provided to Ryder Scott
as estimates of expenditures to be incurred in developing and producing the
Company's
F-23
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED) (CONTINUED)
proved oil and natural gas reserves at the end of the year, based on year end
costs and assuming the continuation of existing economic conditions.
Future income taxes are based on year-end statutory rates, adjusted for net
operating loss carryforwards and tax credits. A discount factor of 10% was used
to reflect the timing of future net cash flows. The Standardized Measure of
Discounted Future Net Cash Flows is not intended to represent the replacement
cost or fair market value of the Company's oil and natural gas properties.
The Standardized Measure of Discounted Future Net Cash Flows does not
purport, nor should it be interpreted, to present the fair value of the
Company's oil and natural gas reserves. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs, a discount
factor more representative of the time value of money and the risks inherent in
reserve estimates.
CHANGES IN STANDARDIZED MEASURE--Changes in Standardized Measure of
Discounted Future Net Cash Flows relating to proved oil and gas reserves are
summarized below:
YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1997 1996
-------------- -------------- -------------
Changes due to current year operations:
Sales of oil and natural gas, net of oil and
natural gas operating expenses............ $ (12,087,673) $ (11,137,394) $ (6,358,807)
Sales of oil and natural gas properties..... (1,884,221)
Extensions and discoveries.................. 6,417,976 34,003,639 22,901,796
Changes due to revisions in standardized
variables:
Prices and operating expenses............... (9,163,029) (15,703,096) 8,668,053
Revisions of previous quantity estimates.... (9,612,849) (8,897,696) (2,970,834)
Estimated future development costs.......... 2,659,500 (4,974,436) (341,128)
Income taxes................................ 9,645,975 3,116,093 (5,728,481)
Accretion of discount....................... 4,088,863 3,942,563 1,744,261
Production rates (timing) and other......... (461,662) 692,811 223,898
-------------- -------------- -------------
Net change.................................... (8,512,899) 1,042,484 16,254,537
Beginning of year............................. 31,242,653 30,200,169 13,945,632
-------------- -------------- -------------
End of year................................... $ 22,729,754 $ 31,242,653 $ 30,200,169
-------------- -------------- -------------
-------------- -------------- -------------
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-24