Back to GetFilings.com
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, 2002
Commission file number: 0-22149
EDGE PETROLEUM CORPORATION
(Exact name of Registrant as specified in its charter)
Delaware 76-0511037
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1301 Travis, Suite 2000
Houston, Texas 77002
(Address of principal executive offices) (Zip code)
713-654-8960
(Registrant's telephone number including area code)
----------------------------
Securities registered pursuant to Section 12(b) of the Act:
None
Securities registered pursuant to Section 12(g) of the Act:
Common Stock, Par Value $.01 Per Share
----------------------------
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
Yes [ ] No [X]
Indicate by check mark whether the registrant is an accelerated filer.
Yes [ ] No [X]
As of June 28, 2002, the aggregate market value of the voting stock held by
non-affiliates of the registrant was $50.6 million (based on a value of $5.38
per share, the closing price of the Common Stock as quoted by NASDAQ National
Market on such date). As of March 14, 2003, 9,465,734 shares of Common Stock,
par value $.01 per share, were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement for the registrant's 2003
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.
TABLE OF CONTENTS
PAGE
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES 1
ITEM 3. LEGAL PROCEEDINGS 22
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF
SECURITY HOLDERS 23
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND
RELATED STOCKHOLDER MATTERS 25
ITEM 6. SELECTED FINANCIAL DATA 26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS 27
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT
MARKET RISK 38
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 38
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURES 39
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 40
ITEM 11. EXECUTIVE COMPENSATION 40
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS 40
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 40
ITEM 14. CONTROLS AND PROCEDURES 40
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K 41
EDGE PETROLEUM CORPORATION
Unless otherwise indicated by the context, references herein to the
"Company" or "Edge" mean Edge Petroleum Corporation, a Delaware corporation, and
its corporate and partnership subsidiaries and predecessors. Certain terms used
herein relating to the oil and natural gas industry are defined in ITEMS 1 AND
2. --"BUSINESS AND PROPERTIES--CERTAIN DEFINITIONS."
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
OVERVIEW
Edge Petroleum Corporation is an independent oil and natural gas
company engaged in the exploration, development, acquisition and production of
crude oil and natural gas properties in the United States. At year-end 2002, our
net proved reserves were 49.0 Bcfe, comprised of 35.0 billion cubic feet of
natural gas, 810 thousand barrels of oil and 1,532 thousand barrels of plant
products. Natural gas and natural gas liquids accounted for approximately 90% of
those proved reserves. About 68% of total proved reserves were developed as of
year-end and they were all located onshore, in the United States.
Edge was founded in 1983 as a private company and went public in 1997
through an initial public offering. We have evolved over time from a prospect
generation organization focused solely on high-risk, high-reward exploration
projects to a team-driven organization focused on a balanced program of
exploration, exploitation, development and acquisition of oil and natural gas
properties. Following a top-level management change in late 1998, a more
disciplined style of business planning and management was integrated into our
technology-driven drilling activities. We believe these changes in our strategy
and business discipline will result in continued growth in reserves, production
and financial strength.
STRATEGY
Our strategy for growth has evolved over the past several years and is
based upon the following main elements:
- reserve growth through the drilling of a balanced portfolio of
prospects
- balancing exploration risk with the acquisition and exploitation of
existing properties that we believe have upside potential
- focusing on specific geographic areas where we believe we can add
value
- integration of the latest technological advances into our
exploration, drilling and production operations
- maintaining a conservative financial structure and controlling our
cost structure
- using equity ownership and performance-based compensation programs to
attract and retain a high-quality workforce.
DRILLING PROGRAM
During 2002, Edge's drilling program was focused in two primary areas.
We drilled 13 wells in 2002 with 11 completed as productive for an 85% apparent
success rate. Our average well cost increased substantially in 2002 as we took
larger working interest in more costly wells. This drilling program, along with
a small acquisition and positive revisions related to performance, helped to
enable us to replace 161% of our production in 2002 and grow our year-end
reserves by nine percent. We expect to drill 20 to 25 wells in 2003 with less
concentration of risk in any single well.
BALANCE
In 2002, 83 % of our reserve growth came from our drilling activity and
17 % came from acquisitions and revisions. We seek acquisitions of proven
properties that typically have exploration or exploitation upside potential. We
primarily seek properties in our existing core areas, or as a means to establish
new core areas. We spent
1
considerable effort in 2002 on acquisitions. We continue to work diligently to
identify and evaluate acquisition opportunities with the goal of identifying
those that we believe would fit our strategic plan and add shareholder value.
We believe our low and moderate-risk drilling program has the potential
to replace our production and to provide moderate reserve growth while our
higher-risk drilling program and acquisitions have the potential to rapidly
accelerate our growth as well as add to future drilling opportunities.
GEOGRAPHIC FOCUS
We believe geographic focus is a critical element of success. Long-term
success requires detailed knowledge of both geologic and geophysical attributes,
as well as operating conditions in our chosen areas. As a result, we focus on a
select number of geographic areas where our experience and strengths can be
applied with a significant influence on the outcome. We believe this focus will
allow us to manage a growing asset base while controlling increases in staffing
and allow us to add value to additional properties while controlling incremental
costs.
TECHNOLOGY
We use advanced technologies as risk reduction tools in our exploration
and development activities. Advanced visualization and data analysis techniques
and advanced processing techniques combined with our more traditional
sub-surface interpretation techniques allow our team of technical personnel to
more easily identify features, structural details and fluid contacts, that could
be overlooked using less sophisticated data interpretation techniques. As of
December 31, 2002, we had rights to approximately 2,487 square miles of 3D
seismic data. Of that amount, we had approximately 1,585 square miles in Texas,
709 square miles in Louisiana, 55 square miles in Montana and 138 square miles
in Mississippi and Alabama.
FINANCIAL STRUCTURE
We believe that a conservative financial structure is crucial to
consistent, positive financial results, management of cyclical swings in our
industry and the ability to move quickly to take advantage of acquisitions and
attractive drilling opportunities. At December 31, 2002, our debt to total
capital ratio was 26 percent. We try to fund most of our ongoing capital
expenditures from cash flow from operations, reserving our debt capacity for
potential investment opportunities that we believe can profitably add to our
program. Part of a sound financial structure is constant attention to costs,
both operating and overhead costs. Over the past three years, we have worked
diligently to control our operating costs, significantly reduced our overhead
costs and instituted a formal, disciplined capital budgeting process.
EQUITY OWNERSHIP
Following a management change in late 1998, we eliminated the previous
overriding royalty compensation system and replaced it with a system designed to
reward all employees through performance-based compensation that is competitive
with our peers and through equity ownership. As of March 14, 2003, our employees
and directors owned or had options to acquire an aggregate of about 20% of our
outstanding common stock.
OIL AND NATURAL GAS RESERVES
The following table sets forth our estimated net proved oil and natural
gas reserves and the present value of estimated future pretax net cash flows
related to such reserves as of December 31, 2002. We engaged Ryder Scott Company
("Ryder Scott") to estimate our net proved reserves, projected future
production, estimated future net revenue attributable to our proved reserves,
and the present value of such estimated future net revenue as of December 31,
2002. Ryder Scott's estimates were based upon a review of production histories
and other geologic, economic, ownership and engineering data provided by us. In
estimating the reserve quantities that are economically recoverable, Ryder Scott
used year-end oil and natural gas prices in effect at December 31, 2002 and
estimated development and production costs that were in effect during December
2002 without giving effect to hedging activities. In accordance with
requirements of the Securities and Exchange Commission
2
(the "Commission") regulations, no price or cost escalation or reduction was
considered by Ryder Scott. For further information concerning Ryder Scott's
estimate of our proved reserves at December 31, 2002, see the reserve report
included as an exhibit to this Annual Report on Form 10-K (the "Ryder Scott
Report"). The present value of estimated future net revenues before income taxes
was prepared using constant prices as of the calculation date, discounted at 10%
per annum on a pretax basis, and is not intended to represent the current market
value of the estimated oil and natural gas reserves owned by us. For further
information concerning the present value of future net revenue from these proved
reserves, see Note 14 to our consolidated financial statements. See ITEMS 1 AND
2. --"BUSINESS AND PROPERTIES-- FORWARD LOOKING INFORMATION AND RISK FACTORS"
- --The oil and natural gas reserve data included in or incorporated by reference
in this document are only estimates and may prove to be inaccurate.
PROVED RESERVES
----------------------------------------------------
DEVELOPED (1) UNDEVELOPED (2) TOTAL
----------------------------------------------------
Oil and condensate (MBbls)(3) 1,510 832 2,342
Natural gas (MMcf) 24,234 10,746 34,980
Total MMcfe 33,293 15,740 49,033
Estimated future net revenue before
income taxes $ 117,476,070 $ 53,366,852 $ 170,842,922
Present value of estimated future net
revenue before income taxes
(discounted 10% annum) (4) $ 79,126,129 $ 36,845,746 $ 115,971,875
- --------------
(1) Proved developed reserves are proved reserves that are expected to be
recovered from existing wells with existing equipment and operating
methods.
(2) Proved undeveloped reserves are proved reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells where
a relatively major expenditure is required for recompletion.
(3) Includes plant products.
(4) Estimated future net revenue represents estimated future gross revenue to
be generated from the production of proved reserves, net of estimated
future production and development costs, using year-end oil and natural gas
prices in effect at December 31, 2002, which were $4.79 per Mcf of natural
gas and $31.20 per Bbl of oil.
There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and in projecting future rates of production
and timing of development expenditures, including many factors beyond the
control of the producer. The reserve data set forth herein represents estimates
only. Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact manner,
and the accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment. As
a result, estimates made by different engineers often vary from one another. In
addition, results of drilling, testing and production subsequent to the date of
an estimate may justify revision of such estimates, and such revisions may be
material. Accordingly, reserve estimates are generally different from the
quantities of oil and natural gas that are ultimately recovered. Furthermore,
the estimated future net revenue from proved reserves and the present value
thereof are based upon certain assumptions, including future prices, production
levels and costs that may not prove correct.
No estimates of proved reserves comparable to those included herein
have been included in reports to any federal agency other than the Commission.
In accordance with Commission regulations, the Ryder Scott Report used
year-end oil and natural gas prices in effect at December 31, 2002. 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, 2002. There can be no assurance that all
of the proved reserves will be produced and sold within the periods
3
indicated, that the assumed prices will actually be realized for such production
or that existing contracts will be honored or judicially enforced.
OIL AND NATURAL GAS VOLUMES, PRICES AND OPERATING EXPENSE
The following table sets forth certain information regarding production
volumes, average sales prices and average oil and natural gas operating expense
associated with our sale of oil and natural gas for the periods indicated.
YEAR ENDED DECEMBER 31,
------------------------------------------------
2002 2001 2000
--------------- ------------- ------------
PRODUCTION:
Oil and condensate (MBbls) 120 116 97
Natural gas liquids (MBbls) 161 46 77
Natural gas (MMcf) 5,266 6,199 5,206
Natural gas equivalent (MMcfe) 6,951 7,167 6,249
AVERAGE SALES PRICE:
Oil and condensate ($ per Bbl)(1) $ 22.88 $ 23.94 $ 26.16
Natural gas liquids ($ per Bbl) $ 10.31 $ 17.74 $ 16.37
Natural gas ($ per Mcf)(1) $ 3.14 $ 4.23 $ 3.84
Natural gas equivalent ($ per Mcfe)(1) $ 3.01 $ 4.16 $ 3.80
AVERAGE OIL AND NATURAL GAS OPERATING EXPENSES INCLUDING
PRODUCTION AND AD VALOREM TAXES ($ PER MCFE)(2) $ 0.55 $ 0.70 $ 0.63
- ----------------
(1) Includes the effect of hedging activity.
(2) Includes direct lifting costs (labor, repairs and maintenance, materials
and supplies), expensed workover costs and the administrative costs of
production offices, insurance and production and ad valorem taxes.
FINDING AND DEVELOPMENT COSTS
We incurred total exploration, development and acquisition costs of
approximately $19.6 million for the year ended December 31, 2002 that added 11.2
Bcfe, net to our interest, of proved reserves. Our average finding and
development cost was $1.75 per Mcfe for 2002. For the three most recent years,
the total of these costs was $58.9 million adding 46.6 Bcfe of proved reserves
for an average finding and development cost of $1.26 per Mcfe.
EXPLORATION, DEVELOPMENT AND ACQUISITION CAPITAL EXPENDITURES
The following table sets forth certain information regarding the total
costs incurred associated with exploration, development and acquisition
activities.
YEAR ENDED DECEMBER 31,
-------------------------------------------------
2002 2001 2000
------------- ------------- -------------
(IN THOUSANDS)
Acquisition Cost:
Unproved properties $ 5,466 $ 7,052 $ 4,220
Proved properties 1,369 5,695 --
Exploration costs 4,725 11,046 2,707
Development costs 7,927 4,823 3,766
------------- ------------- -------------
Total costs incurred $ 19,487 $ 28,616 $ 10,693
============= ============= =============
Net costs incurred excludes sales of proved oil and natural gas
properties which are accounted for as adjustments of capitalized costs with no
gain or loss recognized, unless such adjustments would significantly alter the
relationship between capitalized costs and proved reserves.
4
DRILLING ACTIVITY
The following table sets forth our drilling activity for the three
years ended December 31, 2002. In the table, "gross" refers to the total wells
in which we have a working interest and "net" refers to gross wells multiplied
by our working interest therein.
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------
2002 2001 2000
-------------------- -------------------- --------------------
GROSS NET GROSS NET GROSS NET
-------- -------- ------- -------- -------- --------
EXPLORATORY:
Productive 4 3.45 11 4.95 19 7.90
Non-productive -- -- 3 1.16 2 1.43
-------- -------- ------- -------- -------- --------
Total 4 3.45 14 6.11 21 9.33
-------- -------- ------- -------- -------- --------
DEVELOPMENT:
Productive 7 2.69 6 2.13 5 1.16
Non-productive 2 0.54 2 0.96 - -
-------- -------- ------- -------- -------- --------
Total 9 3.23 8 3.09 5 1.16
-------- -------- ------- -------- -------- --------
GRAND TOTAL 13 6.68 22 9.20 26 10.49
======== ======== ======= ======== ======== ========
PRODUCTIVE WELLS
The following table sets forth the number of productive oil and natural
gas wells in which we owned an interest as of December 31, 2002.
COMPANY- OPERATED NON-OPERATED TOTAL (1)
------------------- -------------------- --------------------
GROSS NET GROSS NET GROSS NET
-------- -------- ------- -------- -------- --------
Oil 11 5.34 56 12.62 67 17.96
Natural gas 51 39.96 94 23.61 145 63.57
-------- -------- ------- -------- -------- --------
Total 62 45.30 150 36.23 212 81.53
======== ======== ======== ======== ======== ========
- ---------------
(1) Includes 75 gross wells shut-in (23.68 net).
ACREAGE DATA
The following table sets forth certain information regarding our
developed and undeveloped lease acreage as of December 31, 2002. Developed acres
refer to acreage within producing units and undeveloped acres refer to acreage
that has not been placed in producing units.
DEVELOPED ACRES UNDEVELOPED ACRES TOTAL
------------------- -------------------- --------------------
GROSS NET GROSS NET GROSS NET
-------- -------- ------- -------- -------- --------
Texas 62,681 22,899 11,526 4,489 74,207 27,388
Louisiana 3,596 790 7,977 3,230 11,573 4,020
Mississippi 2,660 87 184 36 2,844 123
Alabama 536 3 40 1 576 4
Montana -- -- 67,642 30,568 67,642 30,568
======== ======== ======= ======== ======== ========
Total 69,473 23,779 87,369 38,324 156,842 62,103
======== ======== ======= ======== ======== ========
Leases covering approximately 8,616 gross (2,021 net), 10,802 gross
(4,459 net) and 4,715 gross (2,133 net) undeveloped acres are scheduled to
expire in 2003, 2004 and 2005, respectively. In general, our leases will
continue past their primary terms if oil and natural gas production in
commercial quantities is being produced from a well on such lease.
5
The table does not include 4,305 gross (3,943 net) acres that we have a
right to acquire pursuant to various seismic option agreements at December 31,
2002. Under the terms of our option agreements, we typically have the right for
one year, subject to extensions, to exercise our option to lease the acreage at
predetermined terms.
CORE AREAS OF OPERATION
As of December 31, 2002, 65% of our proved reserves were in south Texas
and 33% in south-central Louisiana. During 2001, we added a new focus area in
the northern Rocky Mountains that could become a core area in 2003.
TEXAS
We currently own an interest in 27,388 net acres in south Texas. Our
areas of focus in this region are predominately in the Wilcox, Queen City,
Yegua, Vicksburg and Frio producing trends. As of December 31, 2002, we operated
approximately 61 wells, accounting for about 77% of our total net production in
Texas. We drilled 11 wells during 2002 in Texas, 10 of which were successfully
completed. The majority of our 2002 drilling activity took place at Gato Creek
and in the O'Connor Ranch East Project Area. We drilled three successful wells
at Gato Creek and performed four successful workovers of existing wells. We also
drilled three successful wells at O'Connor Ranch East where we acquired new 3-D
seismic data in 2002. During 2003, we currently expect to drill 15 to 20 wells
in our core areas in Texas. The majority of these wells are planned in our Gato
Creek, O'Connor Ranch East and Encinitas Field project areas.
LOUISIANA
We currently own an interest in 4,020 net acres in south-central
Louisiana. In 1997, we began to re-establish activity in Louisiana where we had
been historically active and had prior exploration success. Our operations have
been focused in the prolific gas-producing region covering parts of Acadia,
Lafayette, St. Landry and Vermilion Parishes. The exploratory focus in this area
is primarily the deep, geo-pressured gas section ranging from 12,000 to 20,000
feet in depth. We began production from our second Duson Complex discovery well,
the Thibodeaux #1, in May 2002 at a gross rate of approximately 10 MMCFPD and
475 BCPD. Edge has a 45% working interest in the well, which is operated by BTA
Oil Producers. The Thibodeaux #1 experienced increasing water production during
the second half of 2002. A workover to correct this problem was attempted in
late 2002. Due to these problems, the original completion was abandoned and a
sidetrack operation was begun in late 2002. The sidetrack was successfully
completed in 2003 and the well is currently producing at a gross rate in excess
of 10 MMCFPD and 750 BCPD. Two additional exploratory wells have reached total
depth in the first quarter 2003 and both were dry holes: the North Gueydan
prospect, a 16,500 foot Marg-Tex test in Acadia Parish and the Jericho prospect,
a Bol Mex test near the Duson Complex in Lafayette Parish. We are currently
assessing additional opportunities in South Louisiana, but have no definite
plans to drill additional wells in this area during 2003.
NORTHERN ROCKY MOUNTAINS
We have a 50% working interest in 67,642 gross acres (30,568 net acres)
in the northern Powder River Basin of Montana. In addition, we directed the
acquisition of 55 square miles of proprietary 3-D seismic covering a portion of
this acreage block. We have in excess of five drillable prospects identified
which we may drill in 2003 depending upon, among other things, capital
availability. This area has multiple objectives ranging from shallow coal bed
methane at 1,000 feet to a deeper Paleozoic section at approximately 11,000
feet. The objective section is generally non-pressured with lower dry hole costs
than many of our Gulf Coast plays.
MARKETING
Our production is marketed to third parties consistent with industry
practices. Typically, oil is sold at the well-head at field-posted prices and
natural gas is sold under contract at a negotiated monthly price based upon
factors normally considered in the industry, such as distance from the well to
the transportation pipeline, well pressure, estimated reserves, quality of
natural gas and prevailing supply/demand conditions.
6
Our marketing objective is to receive the highest possible wellhead
price for our product. We are aided by the presence of multiple outlets near our
production on the Gulf Coast. We take an active role in determining the
available pipeline alternatives for each property based upon historical pricing,
capacity, pressure, market relationships, seasonal variances and long-term
viability.
There are a variety of factors which affect the market for oil and
natural gas, including the extent of domestic production and imports of oil and
natural gas, the proximity and capacity of natural gas pipelines and other
transportation facilities, demand for oil and natural gas, the marketing of
competitive fuels and the effects of state and federal regulations on oil and
natural gas production and sales. We have not experienced any difficulties in
marketing our oil and natural gas. The oil and natural gas industry also
competes with other industries in supplying the energy and fuel requirements of
industrial, commercial and individual customers.
We market our own production where feasible with a combination of
market-sensitive pricing and forward-fixed pricing. Forward pricing is utilized
to take advantage of anomalies in the futures market and to hedge a portion of
our production at prices exceeding forecast. All such hedging transactions
provide for financial rather than physical settlement. See ITEM 7.
- --"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--General Overview."
Due to the instability of oil and natural gas prices, we have entered
into, from time to time, price risk management transactions (e.g., swaps,
collars and floors) for a portion of our oil and natural gas production to
achieve a more predictable cash flow, as well as to reduce exposure from price
fluctuations. While the use of these arrangements limits our ability to benefit
from increases in the price of oil and natural gas, it also reduces our
potential exposure to adverse price movements. Our hedging arrangements, to the
extent we enter into any, apply to only a portion of our production and provide
only partial price protection against declines in oil and natural gas prices and
limits our potential gains from future increases in prices. Our Board of
Directors sets all of our hedging policies, including volumes, types of
instruments and counter parties, on a quarterly basis. These policies are
implemented by management through the execution of trades by the Chief Financial
Officer after consultation and concurrence by the President and Chairman of the
Board. We account for these transactions as hedging activities and, accordingly,
realized gains and losses are included in oil and natural gas revenue during the
period the hedged transactions occur.
Although we take some measures to attempt to control price risk, we
remain subject to price fluctuations for natural gas sold in the spot market due
primarily to seasonality of demand and other factors beyond our control.
Domestic oil prices generally follow worldwide oil prices, which are subject to
price fluctuations resulting from changes in world supply and demand. We
continue to evaluate the potential for reducing these risks by entering into
hedge transactions. Included within natural gas revenue for the years ended
December 31, 2002, 2001, and 2000 was approximately $(0.3) million, $(0.9)
million and $(1.5) million, respectively, representing net losses from hedging
activity. Included within oil revenue for the year ended December 31, 2000 was
approximately $(0.2) million representing net losses from hedging activity.
Realized Hedging Losses
Effective Dates Price MMBtu For the Year Ended December 31,
Hedge ---------------- Per Per ---------------------------------------
Type Beg. Ending MMBtu Day 2002 2001 2000
- ------------------ ---------------- --------- -------- --------- ---------- ----------
NATURAL GAS:
$ 2.20-
Collar 02/01/00 02/29/00 $ 2.31 6,000 $ -- $ -- $ (70,470)
$ 2.20-
Collar 03/01/00 04/30/00 $ 2.50 6,000 -- -- (135,900)
$ 2.05-
Collar 05/01/00 09/30/00 $ 2.63 9,000 -- -- (1,342,320)
$ 4.50-
Collar 01/01/01 12/31/01 $ 6.70 4,000 -- (937,120) --
Put Option 04/01/02 06/30/02 $ 2.65 18,000 (163,800) -- --
Swap 09/01/02 12/31/02 $ 3.59 5,000 (110,550) -- --
Swap 09/01/02 12/31/02 $ 3.69 5,000 (52,600) -- --
---------- ---------- -----------
Total realized losses from gas hedging activities $ (326,950) $ (937,120) $(1,548,690)
========== ========== ===========
7
Realized Hedging Losses
Effective Dates Price Barrels For the Year Ended December 31,
Hedge ---------------- Per Per ---------------------------------------
Type Beg. Ending Barrel Day 2002 2001 2000
- ------------------ ---------------- --------- -------- --------- ---------- ----------
OIL:
Swap 01/01/00 03/31/00 $ 25.60 150 $ -- $ -- $ (49,999)
04/01/00 06/30/00 $ 22.87 125 -- -- (65,478)
07/01/00 09/30/00 $ 21.47 60 -- -- (55,635)
10/01/00 12/31/00 $ 20.46 50 -- -- (52,342)
--------- ---------- ----------
Total realized losses from oil hedging activities $ -- $ -- $ (223,454)
========= ========== ==========
In October 2002, we entered into a collar covering 10,000 MMbtus of gas
per day for all of calendar 2003. The collar structure provides us with a
minimum price for the covered gas volume of $4.00 per MMbtu and a maximum price
of $4.25 per MMbtu. This structure ensured a minimum level of cash flow that
gave us the certainty to plan our drilling program for 2003 in a fashion that
provided more predictability to our activities.
At December 31, 2002 and 2000, the fair value, or net unrealized loss,
of outstanding hedges, for the following year was approximately $(1.3) million
and $(1.1) million, respectively. No hedges were outstanding at December 31,
2001.
COMPETITION
We encounter competition from other oil and natural gas companies in
all areas of our operations, including the acquisition of exploratory prospects
and proven properties. Our competitors include major integrated oil and natural
gas companies and numerous independent oil and natural gas companies,
individuals and drilling and income programs. Many of our competitors are large,
well-established companies with substantially larger operating staffs and
greater capital resources than ours and which, in many instances, have been
engaged in the oil and natural gas business for a much longer time than us. Such
companies may be able to pay more for exploratory prospects and productive oil
and natural gas properties and may be able to define, evaluate, bid for and
purchase a greater number of properties and prospects than our financial or
human resources permit. In addition, such companies may be able to expend
greater resources on the existing and changing technologies that we believe are
and will be increasingly important to the current and future success of oil and
natural gas companies. Our ability to explore for oil and natural gas reserves
and to acquire additional properties in the future will be dependent upon our
ability to conduct our operations, to evaluate and select suitable properties
and to consummate transactions in this highly competitive environment. We
believe that our technological expertise, our exploration, land, drilling and
production capabilities and the experience of our management generally enable us
to compete effectively. Many of our competitors, however, have financial
resources and exploration and development budgets that are substantially greater
than ours, which may adversely affect our ability to compete with these
companies.
INDUSTRY REGULATIONS
The availability of a ready market for oil and natural gas production
depends upon numerous factors beyond our control. These factors include
regulation of oil and natural gas production, federal and state regulations
governing environmental quality and pollution control, state limits on allowable
rates of production by well or proration unit, the amount of oil and natural gas
available for sale, the availability of adequate pipeline and other
transportation and processing facilities and the marketing of competitive fuels.
For example, a productive natural gas well may be "shut-in" because of an
oversupply of natural gas or lack of an available natural gas pipeline in the
areas in which we may conduct operations. State and federal regulations
generally are intended to prevent waste of oil and natural gas, protect rights
to produce oil and natural gas between owners in a common reservoir, control the
amount of oil and natural gas produced by assigning allowable rates of
production and control contamination of the environment. Pipelines are subject
to the jurisdiction of various federal, state and local agencies. We are also
subject to changing and extensive tax laws, the effects of which cannot be
predicted. The following discussion
8
summarizes the regulation of the United States oil and natural gas industry. We
believe that we are in substantial compliance with the various statutes, rules,
regulations and governmental orders to which our operations may be subject,
although there can be no assurance that this is or will remain the case.
Moreover, such statutes, rules, regulations and government orders may be changed
or reinterpreted from time to time in response to economic or political
conditions, and there can be no assurance that such changes or reinterpretations
will not materially adversely affect our results of operations and financial
condition. The following discussion is not intended to constitute a complete
discussion of the various statutes, rules, regulations and governmental orders
to which our operations may be subject.
Regulation of Oil and Natural Gas Exploration and Production. Our
operations are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells and
regulating the location of wells, the method of drilling and casing wells, the
surface use and restoration of properties upon which wells are drilled, the
plugging and abandoning of wells and the disposal of fluids used in connection
with operations. Our operations are also subject to various conservation laws
and regulations. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells that may be drilled in
and the unitization or pooling of oil and natural gas properties. In this
regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely primarily or exclusively on
voluntary pooling of lands and leases. In areas where pooling is voluntary, it
may be more difficult to form units, and therefore more difficult to develop a
project, if the operator owns less than 100% of the leasehold. In addition,
state conservation laws establish maximum rates of production from oil and
natural gas wells, generally prohibit the venting or flaring of natural gas and
impose certain requirements regarding the ratability of production. The effect
of these regulations may limit the amount of oil and natural gas we can produce
from our wells and may limit the number of wells or the locations at which we
can drill. The regulatory burden on the oil and natural gas industry increases
our costs of doing business and, consequently, affects our profitability.
Inasmuch as such laws and regulations are frequently expanded, amended and
reinterpreted, we are unable to predict the future cost or impact of complying
with such regulations.
Regulation of Sales and Transportation of Natural Gas. Federal
legislation and regulatory controls have historically affected the price of
natural gas produced by us, and the manner in which such production is
transported and marketed. Under the Natural Gas Act ("NGA") of 1938, the Federal
Energy Regulatory Commission (the "FERC") regulates the interstate
transportation and the sale in interstate commerce for resale of natural gas.
The FERC's jurisdiction over interstate natural gas sales and transportation was
substantially modified by the Natural Gas Policy Act of 1978 (the "NGPA"), under
which the FERC continued to regulate the maximum selling prices of certain
categories of gas sold in "first sales" in interstate and intrastate commerce.
Effective January 1, 1993, however, the Natural Gas Wellhead Decontrol Act (the
"Decontrol Act") deregulated natural gas prices for all "first sales" of natural
gas, including all sales by us of our own production. As a result, all of our
domestically produced natural gas may now be sold at market prices, subject to
the terms of any private contracts that may be in effect. The Decontrol Act did
not affect the FERC's jurisdiction over natural gas transportation.
Our natural gas sales are affected by intrastate and interstate gas
transportation regulation. Following the Congressional passage of the NGPA, the
FERC adopted a series of regulatory changes that have significantly altered the
transportation and marketing of natural gas. Beginning with the adoption of
"open access" regulations in Order No. 436, issued in October 1985, these
changes were intended by the FERC to foster competition by, among other things,
transforming the role of interstate pipeline companies from wholesale marketers
of gas to the primary role of gas transporters. Through similar orders affecting
intrastate pipelines that provide similar interstate services under the NGPA,
the FERC expanded the impact of these open access regulations to intrastate
commerce.
In April 1992, the FERC issued Order No. 636 and a series of related
orders, which among other things required interstate pipelines to "unbundle"
their gas merchant services from their transportation services, thereby further
enhancing their obligation to provide open-access transportation on a not unduly
discriminatory basis for all natural gas shippers. All gas marketing by the
pipelines was required to be provided upstream at the wellhead, and, as a
result, most pipelines divested their merchant functions to a marketing
affiliate, which operates separately from the transporter and can participate in
downstream sales markets on a bundled basis, in direct competition with other
gas merchants. Order No. 636 also established a mechanism that allows shippers
to "release" their firm capacity to other shippers, either temporarily or
permanently, when it is not needed by those shippers. Although Order No. 636
9
does not directly regulate our production and marketing activities, it does
affect how buyers and sellers gain access to the necessary transportation
facilities and how natural gas is sold in the marketplace.
In February 2000, the FERC issued Order No. 637 which:
o lifted the cost-based cap on pipeline transportation rates in the
capacity release market on an experimental basis until September 30,
2002, for short-term releases of pipeline capacity of less than one
year (the FERC did not renew this program),
o permits pipelines to file for authority to charge different maximum
cost-based rates for peak and off-peak periods,
o encourages, but does not mandate, auctions for pipeline capacity,
o requires pipelines to implement imbalance management services,
o restricts the ability of pipelines to impose penalties for
imbalances, overruns and non-compliance with operational flow
orders, and
o expands the opportunities for shippers to "segment' their capacity
into multiple parts and implements a number of new pipeline
reporting requirements.
Order No. 637 also requires the FERC staff to analyze whether the FERC
should implement additional fundamental policy changes. These include whether to
pursue performance-based or other non-cost based ratemaking techniques and
whether the FERC should mandate greater standardization in terms and conditions
of service across the interstate pipeline grid. Order No. 637 was largely
affirmed by the courts and most pipelines' tariff filings to implement the
requirements of Order No. 637 have been accepted by the FERC and placed into
effect. Finally, in July 2002, the FERC commenced an inquiry into whether it
should make changes to its policy of allowing pipelines in certain circumstances
to charge "negotiated rates" for their services, including rates tied to the
natural gas commodities market indices.
As a result of these changes, sellers and buyers of gas have gained
direct access to the particular pipeline services they need and are better able
to conduct business with a larger number of counterparties. We believe these
changes generally have improved our access to markets while, at the same time,
substantially increasing competition in the natural gas marketplace. It remains
to be seen, however, what effect the FERC's other activities will have on access
to markets, the fostering of competition and the cost of doing business. We
cannot predict what new or different regulations the FERC and other regulatory
agencies may adopt, or what effect subsequent regulations may have on our
activities.
In the past, Congress has been very active in the area of gas
regulation. However, as discussed above, the more recent trend has been in favor
of deregulation, or "lighter handed" regulation, and the promotion of
competition in the gas industry. There regularly are other legislative proposals
pending in the Federal and state legislatures that, if enacted, would
significantly affect the petroleum industry. At the present time, it is
impossible to predict what proposals, if any, might actually be enacted by
Congress or the various state legislatures and what effect, if any, such
proposals might have on us. Similarly, and despite the trend toward federal
deregulation of the natural gas industry, whether or to what extent that trend
will continue, or what the ultimate effect will be on our sales of gas, cannot
be predicted.
We own certain natural gas pipelines that we believe meet the standards
the FERC has used to establish a pipeline's status as a gatherer not subject to
FERC jurisdiction under the NGA. State regulation of gathering facilities
generally includes various safety, environmental, and in some circumstances,
nondiscriminatory take requirements, but does not generally entail rate
regulation. Natural gas gathering may receive greater regulatory scrutiny at
both state and federal levels in the post-Order No. 636 environment.
Oil Price Controls and Transportation Rates. Sales of crude oil,
condensate and gas liquids by us are not currently regulated and are made at
market prices. The price we receive from the sale of these products may be
affected by the cost of transporting the products to market. Much of the
transportation is through interstate common carrier pipelines. Effective as of
January 1, 1995, the FERC implemented regulations generally grandfathering all
previously approved interstate transportation rates and establishing an indexing
system for those rates by which adjustments are made annually based on the rate
of inflation, subject to certain conditions and limitations. These regulations
have generally been approved on judicial review. Every five years, the FERC must
examine the
10
relationship between the annual change in the applicable index and the actual
cost changes experienced in the oil pipeline industry. The first such review was
completed in 2000, and on December 14, 2000, FERC reaffirmed the current index.
The FERC's regulation of oil transportation rates may tend to increase the cost
of transporting oil and natural gas liquids by interstate pipeline, although the
annual adjustments may result in decreased rates in a given year. Following a
successful court challenge of these orders by an association of oil pipelines on
February 24, 2003, the FERC acting on remand increased the index slightly for
the current five-year period, effective July 2001. We are not able at this time
to predict the effects of these regulations, if any, on the transportation costs
associated with oil production from our oil producing operations.
Environmental Regulations. Our operations are subject to numerous
federal, state and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict the types, quantities and concentration of
various substances that can be released into the environment in connection with
drilling and production activities, limit or prohibit drilling activities on
certain lands within wilderness, wetlands and other protected areas, require
remedial measures to mitigate pollution from former operations, such as pit
closure and plugging abandoned wells, and impose substantial liabilities for
pollution resulting from production and drilling operations. Public interest in
the protection of the environment has increased dramatically in recent years.
The trend of more expansive and stricter environmental legislation and
regulations applied to the oil and natural gas industry could continue,
resulting in increased costs of doing business and consequently affecting
profitability. To the extent laws are enacted or other governmental action is
taken that restricts drilling or imposes more stringent and costly waste
handling, disposal and cleanup requirements, our business and prospects could be
adversely affected.
We generate wastes that may be subject to the federal Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S.
Environmental Protection Agency ("EPA") and various state agencies have limited
the approved methods of disposal for certain hazardous and nonhazardous wastes.
Furthermore, certain wastes generated by our oil and natural gas operations that
are currently exempt from treatment as "hazardous wastes" may in the future be
designated as "hazardous wastes," and therefore be subject to more rigorous and
costly operating and disposal requirements.
We currently own or lease numerous properties that for many years have
been used for the exploration and production of oil and natural gas. Although we
believe that we have used good operating and waste disposal practices, prior
owners and operators of these properties may not have used similar practices,
and hydrocarbons or other wastes may have been disposed of or released on or
under the properties owned or leased by us or on or under locations where such
wastes have been taken for disposal. In addition, many of these properties have
been operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under our control. These properties and the
wastes disposed thereon may be subject to the Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state
laws as well as state laws governing the management of oil and natural gas
wastes. Under such laws, we could be required to remove or remediate previously
disposed wastes (including wastes disposed of or released by prior owners or
operators) or property contamination (including groundwater contamination) or to
perform remedial plugging operations to prevent future contamination.
Our operations may be subject to the Clean Air Act ("CAA") and
comparable state and local requirements. Amendments to the CAA were adopted in
1990 and contain provisions that have resulted in the gradual imposition of
certain pollution control requirements with respect to air emissions from our
operations. The EPA and states developed and continue to develop regulations to
implement these requirements. We may be required to incur certain capital
expenditures in the next several years for air pollution control equipment in
connection with maintaining or obtaining operating permits and approvals
addressing other air emission-related issues. However, we do not believe our
operations will be materially adversely affected by any such requirements.
Federal regulations require certain owners or operators of facilities
that store or otherwise handle oil, such as Edge, to prepare and implement spill
prevention, control, countermeasure ("SPCC") and response plans relating to the
possible discharge of oil into surface waters. SPCC plans at certain of our
properties were developed and implemented in 1999. The Oil Pollution Act of 1990
("OPA") contains numerous requirements relating to the prevention of and
response to oil spills into waters of the United States. The OPA subjects owners
of facilities to
11
strict joint and several liability for all containment and cleanup costs and
certain other damages arising from a spill, including, but not limited to, the
costs of responding to a release of oil to surface waters. The OPA also requires
owners and operators of offshore facilities that could be the source of an oil
spill into federal or state waters, including wetlands, to post a bond, letter
of credit or other form of financial assurance in amounts ranging from $10
million in specified state waters to $35 million in federal outer continental
shelf waters to cover costs that could be incurred by governmental authorities
in responding to an oil spill. Such financial assurances may be increased by as
much as $150 million if a formal risk assessment indicates that the increase is
warranted. Noncompliance with OPA may result in varying civil and criminal
penalties and liabilities. Our operations are also subject to the federal Clean
Water Act ("CWA") and analogous state laws. In accordance with the CWA, the
state of Louisiana has issued regulations prohibiting discharges of produced
water in state coastal waters effective July 1, 1997. Pursuant to other
requirements of the CWA, the EPA has adopted regulations concerning discharges
of storm water runoff. This program requires covered facilities to obtain
individual permits, participate in a group permit or seek coverage under an EPA
general permit. While certain of our properties may require permits for
discharges of storm water runoff, we believe that we will be able to obtain, or
be included under, such permits, where necessary, and make minor modifications
to existing facilities and operations that would not have a material effect on
us. Like OPA, the CWA and analogous state laws relating to the control of water
pollution provide varying civil and criminal penalties and liabilities for
releases of petroleum or its derivatives into surface waters or into the ground.
CERCLA, also known as the "Superfund" law, and similar state laws
impose liability, without regard to fault or the legality of the original
conduct, on certain classes of persons that are considered to have contributed
to the release of a "hazardous substance" into the environment. These persons
include the owner or operator of the disposal site or sites where the release
occurred and companies that disposed or arranged for the disposal of the
hazardous substances found at the site. Persons who are or were responsible for
releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment, for damages to natural resources and
for the costs of certain health studies, and it is not uncommon for neighboring
landowners and other third parties to file claims for personal injury and
property damage allegedly caused by the hazardous substances released into the
environment.
We also are subject to a variety of federal, state and local permitting
and registration requirements relating to protection of the environment.
Management believes that we are in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements would not have a material adverse effect on us.
OPERATING HAZARDS AND INSURANCE
The oil and natural gas business involves a variety of operating risks,
including the risk of fire, explosion, blow-out, pipe failure, casing collapse,
abnormally pressured formations and environmental hazards such as oil spills,
natural gas leaks, ruptures and discharges of toxic gases, the occurrence of any
of which could result in substantial losses to us due to injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, cleanup responsibilities, regulatory
investigation and penalties and suspension of operations.
In accordance with customary industry practice, we maintain insurance
against some, but not all, of the risks described above. Our insurance does not
cover business interruption or protect against loss of revenue. There can be no
assurance that any insurance obtained by us will be adequate to cover any losses
or liabilities. We cannot predict the continued availability of insurance or the
availability of insurance at premium levels that justify its purchase. The
occurrence of a significant event not fully insured or indemnified against could
materially and adversely affect our financial condition and operations.
TITLE TO PROPERTIES
Except as discussed under "ITEM 3. LEGAL PROCEEDINGS" below, we believe
we have satisfactory title to all of our producing properties in accordance with
standards generally accepted in the oil and natural gas industry. Our properties
are subject to customary royalty interests, liens incident to operating
agreements, liens for
12
current taxes and other burdens, which we believe, do not materially interfere
with the use of or affect the value of such properties. As is customary in the
industry in the case of undeveloped properties, little investigation of record
title is made at the time of acquisition (other than a preliminary review of
local records). Investigations, including a title opinion of local counsel, are
made before commencement of drilling operations.
EMPLOYEES
At December 31, 2002, we had 33 full-time employees. We believe that
our relationships with our employees are good. None of our employees are covered
by a collective bargaining agreement. From time to time, we utilize the services
of independent consultants and contractors to perform various professional
services, particularly in the areas of construction, design, well site
surveillance, permitting and environmental assessment. Field and on-site
production operation services, such as pumping, maintenance, dispatching,
inspection and testing are generally provided by independent contractors.
OFFICE AND EQUIPMENT
Late in 2002, we negotiated a lease for new offices beginning in
February 2003 at 1301 Travis Street, Suite 2000, Houston, Texas. The move into
our new space, covering 20,500 square feet (compared to 28,200 square feet under
our previous lease), took place during the first week of February 2003. We
believe that the combination of lower rental rates and smaller space will
significantly reduce our future general and administrative costs. See Note 6 to
our consolidated financial statements.
FORWARD LOOKING INFORMATION AND RISK FACTORS
Certain of the statements contained in all parts of this document
(including the portion, if any, to which this Form 10-K is attached), including,
but not limited to, those relating to our drilling plans, the effect of changes
in strategy and business discipline, future tax matters, our 3-D project
portfolio, future general and administrative expenses on a per unit of
production basis, increases in wells operated, future growth and expansion,
future exploration, future seismic data (including timing and results),
expansion of operation, generation of additional prospects, review of outside
generated prospects and acquisitions, additional reserves and reserve increases,
enhancement of visualization and interpretation strengths, expansion and
improvement of capabilities, integration of new technology into operations,
credit facilities, attraction of new members to the exploration team, future
compensation programs, new focus on core areas, new prospects and drilling
locations, future capital expenditures (or funding thereof), sufficiency of
future working capital, borrowings and capital resources and liquidity,
projected cash flows from operations, expectation or timing of reaching payout,
outcome, effects or timing of any legal proceedings, drilling plans, including
scheduled and budgeted wells, the number, timing or results of any wells, the
plans for timing, interpretation and results of new or existing seismic surveys
or seismic data, future production or reserves, future acquisition of leases,
lease options or other land rights and any other statements regarding future
operations, financial results, opportunities, growth, business plans and
strategy and other statements that are not historical facts are forward looking
statements. These forward-looking statements reflect our current view of future
events and financial performance. When used in this document, the words
"budgeted," "anticipate," "estimate," "expect," "may," "project," "believe,"
"intend," "plan," "potential" and similar expressions are intended to be among
the statements that identify forward looking statements. These forward-looking
statements speak only as of their dates and should not be unduly relied upon. We
undertake no obligation to publicly update or review any forward-looking
statement, whether as a result of new information, future events, or otherwise.
Such statements involve risks and uncertainties, including, but not limited to,
the numerous risks and substantial and uncertain costs associated with
exploratory drilling, the volatility of oil and natural gas prices and the
effects of relatively low prices for our products, conducting successful
exploration and development in order to maintain reserves and revenue in the
future, operating risks of oil and natural gas operations, our dependence on key
personnel, our ability to utilize changing technology and the risk of
technological obsolescence, the significant capital requirements of our
exploration and development and technology development programs, governmental
regulation and liability for environmental matters, results of litigation,
management of growth and the related demands on our resources and the ability to
achieve future growth, competition from larger oil and natural gas companies,
the potential inaccuracy of
13
estimates of oil and natural gas reserve data, property acquisition risks, and
other factors detailed in this document and our other filings with the
Commission. Should one or more of these risks or uncertainties materialize, or
should underlying assumptions prove incorrect, actual outcomes may vary
materially from those indicated.
OIL AND GAS DRILLING IS A SPECULATIVE ACTIVITY AND INVOLVES NUMEROUS RISKS AND
SUBSTANTIAL AND UNCERTAIN COSTS
Our growth will be materially dependent upon the success of our future
drilling program. Drilling for oil and gas involves numerous risks, including
the risk that no commercially productive oil or natural gas reservoirs will be
encountered. The cost of drilling, completing and operating wells is substantial
and uncertain, and drilling operations may be curtailed, delayed or cancelled as
a result of a variety of factors beyond our control, including unexpected
drilling conditions, pressure or irregularities in formations, equipment
failures or accidents, adverse weather conditions, compliance with governmental
requirements and shortages or delays in the availability of drilling rigs or
crews and the delivery of equipment. Although we believe that our use of 3-D
seismic data and other advanced technology should increase the probability of
success of our wells and should reduce average finding costs through elimination
of prospects that might otherwise be drilled solely on the basis of 2-D seismic
data and other traditional methods, drilling remains a speculative activity.
Even when fully utilized and properly interpreted, 3-D seismic data and
visualization techniques only assist geoscientists in identifying subsurface
structures and do not allow the interpreter to know if hydrocarbons will in fact
be present in such structures if they are drilled. In addition, the use of 3-D
seismic data and such technologies requires greater pre-drilling expenditures
than traditional drilling strategies and we could incur losses as a result of
such expenditures. Our future drilling activities may not be successful and, if
unsuccessful, such failure will have an adverse effect on our future results of
operations and financial condition. There can be no assurance that our overall
drilling success rate or our drilling success rate for activity within a
particular geographic area will not decline. Although we may discuss drilling
prospects that we have identified or budgeted for, we may ultimately not lease
or drill these prospects within the expected time frame, or at all. We may
identify prospects through a number of methods, some of which do not include
interpretation of 3-D or other seismic data. The drilling and results for these
prospects may be particularly uncertain. We may not be able to lease or drill a
particular prospect because, in some cases, we identify a prospect or drilling
location before seeking an option or lease rights in the prospect or location.
Similarly, our drilling schedule may vary from our capital budget. The final
determination with respect to the drilling of any scheduled or budgeted wells
will be dependent on a number of factors, including (i) the results of
exploration efforts and the acquisition, review and analysis of the seismic
data, (ii) the availability of sufficient capital resources to us and the other
participants for the drilling of the prospects, (iii) the approval of the
prospects by other participants after additional data has been compiled, (iv)
economic and industry conditions at the time of drilling, including prevailing
and anticipated prices for oil and natural gas and the availability of drilling
rigs and crews, (v) our financial resources and results and (vi) the
availability of leases and permits on reasonable terms for the prospects. There
can be no assurance that these projects can be successfully developed or that
the wells discussed will, if drilled, encounter reservoirs of commercially
productive oil or natural gas. There are numerous uncertainties in estimating
quantities of proved reserves, including many factors beyond our control. See
ITEM 7. -- "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS--General Overview" and ITEMS 1 AND 2. --"BUSINESS AND
PROPERTIES--CORE AREAS OF OPERATION."
OIL AND NATURAL GAS PRICES ARE HIGHLY VOLATILE IN GENERAL AND LOW PRICES
NEGATIVELY AFFECT OUR FINANCIAL RESULTS
Our revenue, profitability, cash flow, future growth and ability to
borrow funds or obtain additional capital, as well as the carrying value of our
properties, are substantially dependent upon prevailing prices of oil and
natural gas. Our reserves are predominantly natural gas; therefore changes in
natural gas prices may have a particularly large impact on our financial
results. Lower oil and natural gas prices also may reduce the amount of oil and
natural gas that we can produce economically. Historically, the markets for oil
and natural gas have been volatile, and such markets are likely to continue to
be volatile in the future. Prices for oil and natural gas are subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond our control. These factors include the level of consumer product
demand, weather conditions, domestic and foreign governmental regulations, the
price and availability of alternative fuels, political conditions, the foreign
supply of oil and natural gas, the price of foreign imports and overall economic
conditions. It is impossible to predict future oil and natural gas price
movements with certainty. Declines in oil and natural gas prices may materially
adversely affect our financial condition, liquidity, and ability to finance
planned capital expenditures and results of operations. See ITEM 7.
- --"MANAGEMENT'S
14
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--General Overview" and ITEMS 1 AND 2. --"BUSINESS AND PROPERTIES--OIL
AND NATURAL GAS RESERVES" AND "-- MARKETING."
We review on a quarterly basis the carrying value of our oil and
natural gas properties under the applicable rules of the Commission. Under these
rules, the carrying value of proved oil and natural gas properties may not
exceed the present value of estimated future net after-tax cash flows from
proved reserves, discounted at 10%. Application of this "ceiling" test generally
requires pricing future revenue at the unescalated prices in effect as of the
end of each fiscal quarter and requires a write down for accounting purposes if
the ceiling is exceeded, even if prices declined for only a short period of
time. We have in the past and may in the future be required to write down the
carrying value of our oil and natural gas properties when oil and natural gas
prices are depressed or unusually volatile. Whether we will be required to take
such a charge will depend on the prices for oil and natural gas at the end of
any quarter and the effect of reserve additions or revisions and capital
expenditures during such quarter. If a write down is required, it would result
in a charge to earnings and would not impact cash flow from operating
activities.
In order to reduce our exposure to short-term fluctuations in the price
of oil and natural gas, we periodically enter into hedging arrangements. Our
hedging arrangements apply to only a portion of our production and provide only
partial price protection against declines in oil and natural gas prices. Such
hedging arrangements may expose us to risk of financial loss in certain
circumstances, including instances where production is less than expected, our
customers fail to purchase contracted quantities of oil or natural gas or a
sudden, unexpected event materially impacts oil or natural gas prices. In
addition, our hedging arrangements may limit the benefit to us of increases in
the price of oil and natural gas. See ITEM 7. --"MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--General Overview" and
ITEMS 1 AND 2. --"BUSINESS AND PROPERTIES--MARKETING."
MAINTAINING RESERVES AND REVENUE IN THE FUTURE DEPENDS ON SUCCESSFUL
EXPLORATION, DEVELOPMENT AND ACQUISITIONS
In general, the volume of production from oil and natural gas
properties declines as reserves are depleted, with the rate of decline depending
on reservoir characteristics. Except to the extent we acquire properties
containing proved reserves or conduct successful exploration and development
activities, or both, our proved reserves will decline. Our future oil and
natural gas production is, therefore, highly dependent upon our level of success
in finding or acquiring additional reserves. In addition, we are dependent on
finding partners for our exploratory activity. To the extent that others in the
industry do not have the financial resources or choose not to participate in our
exploration activities, we will be adversely affected.
WE ARE SUBJECT TO SUBSTANTIAL OPERATING RISKS
The oil and natural gas business involves certain operating hazards
such as well blowouts, mechanical failures, explosions, uncontrollable flows of
oil, natural gas or well fluids, fires, formations with abnormal pressures,
pollution, releases of toxic gas and other environmental hazards and risks. We
could suffer substantial losses as a result of any of these events. We are not
fully insured against all risks incident to our business.
We are not the operator of some of our wells. As a result, our
operating risks for those wells and our ability to influence the operations for
these wells are less subject to our control. Operators of these wells may act in
ways that are not in our best interests. See ITEMS 1 AND 2. --"BUSINESS AND
PROPERTIES--OPERATING HAZARDS AND INSURANCE."
THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT US
We depend to a large extent on the services of certain key management
personnel, including our executive officers and other key employees, the loss of
any of which could have a material adverse effect on our operations. We do not
maintain key-man life insurance with respect to any of our employees. We believe
that our success is also dependent upon our ability to continue to employ and
retain skilled technical personnel. See ITEMS 1 AND 2. --"BUSINESS AND
PROPERTIES--Technology."
15
OUR OPERATIONS HAVE SIGNIFICANT CAPITAL REQUIREMENTS
We have experienced and expect to continue to experience substantial
working capital needs due to our active exploration, development and acquisition
programs. Additional financing may be required in the future to fund our growth.
No assurances can be given as to the availability or terms of any such
additional financing that may be required or that financing will continue to be
available under existing or new credit facilities. In the event such capital
resources are not available to us, our drilling and other activities may be
curtailed. See ITEM 7. --"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--Liquidity and Capital Resources."
GOVERNMENT REGULATION AND LIABILITY FOR ENVIRONMENTAL MATTERS MAY ADVERSELY
AFFECT OUR BUSINESS AND RESULTS OF OPERATIONS
Oil and natural gas operations are subject to various federal, state
and local government regulations, which may be changed from time to time.
Matters subject to regulation include discharge permits for drilling operations,
drilling bonds, reports concerning operations, the spacing of wells, unitization
and pooling of properties and taxation. From time to time, regulatory agencies
have imposed price controls and limitations on production by restricting the
rate of flow of oil and natural gas wells below actual production capacity in
order to conserve supplies of oil and natural gas. There are federal, state and
local laws and regulations primarily relating to protection of human health and
the environment applicable to the development, production, handling, storage,
transportation and disposal of oil and natural gas, by-products thereof and
other substances and materials produced or used in connection with oil and
natural gas operations. In addition, we may be liable for environmental damages
caused by previous owners of property we purchase or lease. As a result, we may
incur substantial liabilities to third parties or governmental entities. We are
also subject to changing and extensive tax laws, the effects of which cannot be
predicted. The implementation of new, or the modification of existing, laws or
regulations could have a material adverse effect on us. See ITEMS 1 AND 2.
- --"BUSINESS AND PROPERTIES--INDUSTRY REGULATIONS."
WE MAY HAVE DIFFICULTY MANAGING ANY FUTURE GROWTH AND THE RELATED DEMANDS ON OUR
RESOURCES AND MAY HAVE DIFFICULTY IN ACHIEVING FUTURE GROWTH
We have experienced growth in the past through the expansion of our
drilling program and, more recently, acquisitions. This expansion was curtailed
in 1998 and 1999, but resumed in 2000 and increased in 2001 and 2002. Further
expansion is anticipated in 2003 both through drilling efforts and possible
acquisitions. Any future growth may place a significant strain on our financial,
technical, operational and administrative resources. Our ability to grow will
depend upon a number of factors, including our ability to identify and acquire
new exploratory prospects, our ability to develop existing prospects, our
ability to continue to retain and attract skilled personnel, the results of our
drilling program and acquisition efforts, hydrocarbon prices and access to
capital. There can be no assurance that we will be successful in achieving
growth or any other aspect of our business strategy.
WE FACE STRONG COMPETITION FROM LARGER OIL AND NATURAL GAS COMPANIES
Our competitors include major integrated oil and natural gas companies
and numerous independent oil and natural gas companies, individuals and drilling
and income programs. Many of our competitors are large, well-established
companies with substantially larger operating staffs and greater capital
resources than us. We may not be able to successfully conduct our operations,
evaluate and select suitable properties and consummate transactions in this
highly competitive environment. Specifically, these larger competitors may be
able to pay more for exploratory prospects and productive oil and natural gas
properties and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than our financial or human resources permit.
In addition, such companies may be able to expend greater resources on the
existing and changing technologies that we believe are and will be increasingly
important to attaining success in the industry. See ITEMS 1 AND 2.--"BUSINESS
AND PROPERTIES--COMPETITION."
THE OIL AND NATURAL GAS RESERVE DATA INCLUDED IN OR INCORPORATED BY REFERENCE IN
THIS DOCUMENT ARE ONLY ESTIMATES AND MAY PROVE TO BE INACCURATE
16
There are numerous uncertainties inherent in estimating oil and natural
gas reserves and their estimated values. The reserve data in this report
represent only estimates that may prove to be inaccurate because of these
uncertainties. Reservoir engineering is a subjective and inexact process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and
natural gas reserves depend upon a number of variable factors, such as
historical production from the area compared with production from other
producing areas and assumptions concerning effects of regulations by
governmental agencies, future oil and natural gas prices, future operating
costs, severance and excise taxes, development costs and workover and remedial
costs, some or all of these assumptions may in fact vary considerably from
actual results. For these reasons, estimates of the economically recoverable
quantities of oil and natural gas attributable to any particular group of
properties, classifications of such reserves based on risk of recovery, and
estimates of the future net cash flows expected therefrom prepared by different
engineers or by the same engineers but at different times may vary
substantially. Accordingly, reserve estimates may be subject to downward or
upward adjustment. Actual production, revenue and expenditures with respect to
our reserves will likely vary from estimates, and such variances may be
material. The information regarding discounted future net cash flows included in
this report should not be considered as the current market value of the
estimated oil and natural gas reserves attributable to our properties. As
required by the Commission, the estimated discounted future net cash flows from
proved reserves are based on prices and costs as of the date of the estimate,
while actual future prices and costs may be materially higher or lower. Actual
future net cash flows also will be affected by factors such as the amount and
timing of actual production, supply and demand for oil and natural gas,
increases or decreases in consumption, and changes in governmental regulations
or taxation. In addition, the 10% discount factor, which is required by the
Commission to be used in calculating discounted future net cash flows for
reporting purposes, is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with us
or the oil and natural gas industry in general. See ITEMS 1 AND 2. --"BUSINESS
AND PROPERTIES--Oil and Natural Gas Reserves."
OUR CREDIT FACILITY HAS SUBSTANTIAL OPERATING RESTRICTIONS AND FINANCIAL
COVENANTS AND WE MAY HAVE DIFFICULTY OBTAINING ADDITIONAL CREDIT
Over the past few years, increases in commodity prices, in proved
reserve amounts and the resultant increase in estimated discounted future net
revenue, has allowed us to increase our available borrowing amounts. There can
be no assurance that, in the future, commodity prices will not decline, we will
not increase our borrowings or the borrowing base will not be adjusted downward.
Our credit facility is secured by a pledge of substantially all of our assets
and has covenants that limit additional borrowings, sales of assets and the
distributions of cash or properties and that prohibit the payment of dividends
and the incurrence of liens. The revolving credit facility also requires that
specified financial ratios be maintained. The restrictions of our credit
facility and the difficulty in obtaining additional debt financing may have
adverse consequences on our operations and financial results, including our
ability to obtain financing for working capital, capital expenditures, our
drilling program, purchases of new technology or other purposes may be impaired
or such financing may be on terms unfavorable to us; we may be required to use a
substantial portion of our cash flow to make debt service payments, which will
reduce the funds that would otherwise be available for operations and future
business opportunities; a substantial decrease in our operating cash flow or an
increase in our expenses could make it difficult for us to meet debt service
requirements and require us to modify operations; and we may become more
vulnerable to downturns in our business or the economy generally.
Our ability to obtain and service indebtedness will depend on our
future performance, including our ability to manage cash flow and working
capital, which are in turn subject to a variety of factors beyond our control.
Our business may not generate cash flow at or above anticipated levels or we may
not be able to borrow funds in amounts sufficient to enable us to service
indebtedness, make anticipated capital expenditures or finance our drilling
program. If we are unable to generate sufficient cash flow from operations or to
borrow sufficient funds in the future to service our debt, we may be required to
curtail portions of our drilling program, sell assets, reduce capital
expenditures, refinance all or a portion of our existing debt or obtain
additional financing. We may not be able to refinance our debt or obtain
additional financing, particularly in view of current industry conditions, the
restrictions on our ability to incur debt under our existing debt arrangements,
and the fact that substantially all of our assets are currently pledged to
secure obligations under our bank credit facility. See Item 7. --"MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Liquidity and
17
Capital Resources" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--Credit Facility."
OUR ACQUISITION PROGRAM MAY BE UNSUCCESSFUL, PARTICULARLY IN LIGHT OF OUR
LIMITED ACQUISITION EXPERIENCE
Some of our personnel have had significant acquisition experience prior
to joining Edge; however, because we have not typically purchased properties, we
may not be in as good a position as our more experienced competitors to execute
a successful acquisition program. The successful acquisition of producing
properties requires an assessment of recoverable reserves, future oil and
natural gas prices, operating costs, potential environmental and other
liabilities and other factors. Such assessments, even when performed by
experienced personnel, are necessarily inexact and their accuracy inherently
uncertain. Our review of subject properties, which generally includes on-site
inspections and the review of reports filed with various regulatory entities,
will not reveal all existing or potential problems, deficiencies and
capabilities. We may not always perform inspections on every well, and may not
be able to observe structural and environmental problems even when we undertake
an inspection. Even when problems are identified, the seller may be unwilling or
unable to provide effective contractual protection against all or part of such
problems. There can be no assurances that any acquisition of property interests
by us will be successful and, if unsuccessful, that such failure will not have
an adverse effect on our future results of operations and financial condition.
WE DO NOT INTEND TO PAY DIVIDENDS AND OUR ABILITY TO PAY DIVIDENDS IS RESTRICTED
We currently intend to retain any earnings for the future operation and
development of our business and do not currently anticipate paying any dividends
in the foreseeable future. Any future dividends also may be restricted by our
then-existing loan agreements. See ITEM 7. --"MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Liquidity and Capital
Resources" and Note 4 to our consolidated financial statements.
WE CANNOT MARKET OUR PRODUCTION WITHOUT THE ASSISTANCE OF THIRD PARTIES
The marketability of our production depends upon the proximity of our
reserves to, and the capacity of, facilities and third party services, including
oil and natural gas gathering systems, pipelines, trucking or terminal
facilities, and processing facilities. The unavailability or lack of capacity of
such services and facilities could result in the shut-in of producing wells or
the delay or discontinuance of development plans for properties. A shut-in or
delay or discontinuance could adversely affect our financial condition. In
addition, federal and state regulation of oil and natural gas production and
transportation affect our ability to produce and market our oil and natural gas
on a profitable basis.
PROVISIONS OF DELAWARE LAW AND OUR CHARTER AND BYLAWS MAY DELAY OR PREVENT
TRANSACTIONS THAT WOULD BENEFIT STOCKHOLDERS
Our Certificate of Incorporation and Bylaws and the Delaware General
Corporation Law contain provisions that may have the effect of delaying,
deferring or preventing a change of control of the company. These provisions,
among other things, provide for a classified Board of Directors with staggered
terms, restrict the ability of stockholders to take action by written consent,
authorize the Board of Directors to set the terms of Preferred Stock, and
restrict our ability to engage in transactions with 15% stockholders.
Because of these provisions, persons considering unsolicited tender
offers or other unilateral takeover proposals may be more likely to negotiate
with our board of directors rather than pursue non-negotiated takeover attempts.
As a result, these provisions may make it more difficult for our stockholders to
benefit from transactions that are opposed by an incumbent board of directors.
18
CERTAIN DEFINITIONS
The definitions set forth below shall apply to the indicated terms as
used in this Form 10-K. All volumes of natural gas referred to herein are stated
at the legal pressure base of the state or area where the reserves exist and at
60 degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
After payout. With respect to an oil or natural gas interest in a property,
refers to the time period after which the costs to drill and equip a well have
been recovered.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Bbls/d. Stock tank barrels per day.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Before payout. With respect to an oil and natural gas interest in a
property, refers to the time period before which the costs to drill and equip a
well have been recovered.
Completion. The installation of permanent equipment for the production of
oil or natural gas or, in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
Developed acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or natural
gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
oil and natural gas operating expenses and taxes.
Exploratory well. A well drilled to find and produce oil or natural gas
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of oil or natural gas in another reservoir or to extend a
known reservoir.
Farm-in or farm-out. An agreement whereunder the owner of a working interest
in an oil and natural gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage. Generally,
the assignee is required to drill one or more wells in order to earn its
interest in the acreage. The assignor usually retains a royalty and/or
reversionary interest in the lease. The interest received by an assignee is a
"farm-in" while the interest transferred by the assignor is a "farm-out."
Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Finding costs. Costs associated with acquiring and developing proved oil and
natural gas reserves which are capitalized by us pursuant to generally accepted
accounting principles, including all costs involved in acquiring acreage,
geological and geophysical work and the cost of drilling and completing wells,
excluding those costs attributable to unproved undeveloped property.
Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
19
Mcf. One thousand cubic feet.
Mcf/d. One thousand cubic feet per day.
Mcfe. One thousand cubic feet equivalent determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids,
which approximates the relative energy content of crude oil, condensate and
natural gas liquids as compared to natural gas. Prices have historically been
higher or substantially higher for crude oil than natural gas on an energy
equivalent basis although there have been periods in which they have been lower
or substantially lower.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids,
which approximates the relative energy content of crude oil, condensate and
natural gas liquids as compared to natural gas.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.
NGL's. Natural gas liquids measured in barrels.
NRI or Net Revenue Interests. The share of production after satisfaction of
all royalty, overriding royalty, oil payments and other nonoperating interests.
Normally pressured reservoirs. Reservoirs with a formation-fluid pressure
equivalent to 0.465 PSI per foot of depth from the surface. For example, if the
formation pressure is 4,650 PSI at 10,000 feet, then the pressure is considered
to be normal.
Over-pressured reservoirs. Reservoirs subject to abnormally high pressure as
a result of certain types of subsurface formations.
Petrophysical study. Study of rock and fluid properties based on well log
and core analysis.
Plant Products. Liquids generated by a plant facility and include propane,
iso-butane, normal butane, pentane and ethane.
Present value. When used with respect to oil and natural gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves, net of estimated production and future development costs, using prices
and costs in effect as of the date indicated, without giving effect to
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.
20
Proved undeveloped location. A site on which a development well can be
drilled consistent with spacing rules for purposes of recovering proved
undeveloped reserves.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible oil and/or natural gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in an oil and natural gas property entitling
the owner to a share of oil or natural gas production free of costs of
production.
3-D seismic. Advanced technology method of detecting accumulations of
hydrocarbons identified through a three-dimensional picture of the subsurface
created by the collection and measurement of the intensity and timing of sound
waves transmitted into the earth as they reflect back to the surface.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and natural gas regardless of whether such acreage contains proved
reserves.
Working interest or WI. The operating interest that gives the owner the
right to drill, produce and conduct operating activities on the property and a
share of production.
Workover. Operations on a producing well to restore or increase production.
21
ITEM 3. LEGAL PROCEEDINGS
From time to time we are a party to various legal proceedings arising
in the ordinary course of business. While the outcome of lawsuits cannot be
predicted with certainty, we are not currently a party to any proceeding that we
believe, if determined in a manner adverse to us, could have a potential
material adverse effect on our financial condition, results of operations or
cash flows.
In October 2001, the Company was sued by certain mineral owners in its
Mew lease, upon which the Company and its partners drilled and completed the Mew
No. 1 well in the Brandon Area, Duval County, Texas. The suit named the Company,
Santos USA and Mark Smith, an independent landman, as Defendants, and is filed
in the 229th Judicial District Court of Duval County, Texas. The suit sought a
declaratory judgment to set aside certain quitclaim deeds between the Mew
lessors that were intended to result in a partition of the mineral estate
between the various members of the Mew family in the land where the well is
located and other lands. The pleadings alleged failure of consideration, fraud,
failure to consummate the partition, bad faith trespass and conversion. As part
of the leasing effort for the prospect, some members of the Mew family had
sought to partition their minerals under the tracts where they owned the surface
in full. The Mew heirs, from whom the Company acquired leases, stood to lose a
portion of their mineral interest if the quitclaim deeds are set aside. Were
this to happen, it could have the effect of voiding the Company's leases as to
an undivided one-third of the unit acreage for the Mew well and the Mew lease.
Plaintiffs sought unspecified actual and exemplary damages against the Company
and Santos arising out of the alleged fraud committed by the Company and Mark
Smith. They also sought damages from Santos for the value of the oil and natural
gas produced and saved from the Mew well, or alternatively, for the value of the
oil and natural gas produced less the cost of drilling, completing and operating
the well. The Company has a 12.5% working interest in the well. To date, the Mew
well has produced $5.7 million in net revenue and has cost $3.6 million to
drill, complete and operate. Estimated gross proved reserves are 111.6 MBbls and
4.6 Bcf. In October 2002, the Company reached a mediated settlement with all
parties to the litigation whereby Edge would make a one-time payment of $264,000
to the Mews, and in return, the Mews released all claims except a potential
drainage claim involving an offsetting section, and agreed to grant a new oil
and gas lease covering the disputed mineral interest in the Mew well site tract.
In addition, all claims as between the working interest owners were released.
The settlement has been consummated and an order of dismal has been obtained
from the Court.
In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil in the 229th Judicial Court in
Starr County, Texas enjoining ExxonMobil from taking possession of the Neblett
wells. Pending resolution of the underlying title issue, the temporary
restraining order was extended voluntarily by agreement of the parties,
conditioned on GMT paying the revenues into escrow and agreeing to provide
ExxonMobil with certain discovery materials in this action. ExxonMobil filed a
counterclaim against GMT and all the non-operators, including the Company, to
establish the validity of their lease, remove cloud on title, quiet title to the
property, and for conversion, trespass and punitive damages. ExxonMobil sought
unspecified damages for the lost profits on the sale of the hydrocarbons from
this property, and for a determination of whether the Company and the other
working interest owners were in good faith or bad faith in trespassing on this
lease. If a determination of bad faith were made, the parties would not be able
to recover their costs of developing this property from the revenues therefrom.
While there is always a risk in the outcome of the litigation, the Company
believes there is no question that it acted in good faith and vigorously
defended its position. In February 2003, the Company, GMT and the other working
interest parties entered into a compromise and settlement agreement with Exxon
and Mrs. Neblett. Pursuant to the settlement, the Neblett wells have been
assigned to Exxon along with all operating responsibility, and all working
interest parties, including the Company, have been made whole for all out of
pocket costs incurred in drilling, completing, equipping and operating the
Neblett wells, including lease costs and royalty payments. The Company's share
of such reimbursed costs was $27,198. In addition, Mrs. Neblett will repay the
amount of the lease bonus and all royalty overpayments she received from GMT and
the other working interest parties, including the Company. Such payment is
secured by her future royalty interest payments in the wells, and other security
described in the settlement agreement, and is due in full on or before December
1, 2003. The Company's share of such lease bonus and royalty reimbursements is
$74,040. The parties have agreed to a dismissal of all claims in this case, and
a motion to dismiss with prejudice has been filed with the court.
22
In a separate but related matter, certain nonparticipating royalty
owners represented by attorney John Mann in Laredo, have made demands on GMT as
operator, to pay certain royalty payments previously paid to Mrs. Neblett on
production from these wells, plus future royalty payments on such production. As
part of the settlement agreement, monies that were otherwise payable to Mrs.
Neblett attributable to her valid royalty interest under the ExxonMobil lease,
subject to execution of valid division orders and approval of their title, will
be paid to the Mann clients on account of their nonparticipating royalty
interest. There are other nonparticipating royalty owners similarly situated to
the Mann clients that have not made demands on GMT or the Company, whose claims,
if any, will be dealt with if and when they are made. There can be no guarantee
that even when the Mann clients are paid that they will not contest the amount
or calculation of the royalties in a separate lawsuit.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter of the fiscal year
covered by this report to a vote of security holders, through the solicitation
of proxies or otherwise.
EXECUTIVE OFFICERS OF THE REGISTRANT
Pursuant to Instruction 3 to Item 401(b) of Regulation S-K and General
Instruction G (3) to Form 10-K the following information is included in Part I
of this Form 10-K.
JOHN W. ELIAS has served as the Chief Executive Officer and Chairman of the
Board of the Company since November 1998. Mr. Elias is a member of the
Nominating Committee of the Board. From April 1993 to September 30, 1998, he
served in various senior management positions, including Executive Vice
President, of Seagull Energy Corporation, a company engaged in oil and natural
gas exploration, development and production and pipeline marketing. Prior to
April 1993 Mr. Elias served in various positions for more than 30 years,
including senior management positions with Amoco Corporation, a major integrated
oil and gas company. Mr. Elias has more than 40 years of experience in the oil
and natural gas exploration and production business. He is 62 years old.
MICHAEL G. LONG has served as Senior Vice President and Chief Financial Officer
of the Company since December 1996. Mr. Long served as Vice President-Finance of
W&T Offshore, Inc., an oil and natural gas exploration and production company,
from July 1995 to December 1996. From May 1994 to July 1995, he served as Vice
President of the Southwest Petroleum Division for Chase Manhattan Bank, N.A.
Prior thereto, he served in various capacities with First National Bank of
Chicago, most recently that of Vice President and Senior Corporate Banker of the
Energy and Transportation Department, from March 1992 to May 1994. Mr. Long
received a B.A. in Political Science and a M.S. in Economics from the University
of Illinois. Mr. Long is 50 years old.
JOHN O. TUGWELL has served as Senior Vice President Production since December
2001 and prior to that served as Vice President of Production for the Company
since March 1997. He served as Senior Petroleum Engineer of the Company's
predecessor corporation since May 1995. From 1986 to May 1995, he held various
reservoir/production engineering positions with Shell Oil Company, most recently
that of Senior Reservoir Engineer. Mr. Tugwell holds a B.S. in Petroleum
Engineering from Louisiana State University. Mr. Tugwell is a registered
Professional Engineer in the State of Texas. Mr. Tugwell is 39 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
23
departure. Mr. Hastings holds a B.A. from Dartmouth in Earth Sciences and a M.S.
in Geology from Texas A&M University.
KIRSTEN A. HINK has served as Controller of the Company since December 31, 2000
and prior to that served as Assistant Controller from June 2000 to December
2000. She served as Controller of Benz Energy Inc., an oil and gas exploration
company, from 1998 to June 2000. Prior thereto she served in financial and SEC
reporting positions with Western Atlas, Inc. and Apache Corporation. Mrs. Hink
received a B.S. in Accounting from Trinity University, San Antonio, Texas. Mrs.
Hink is a Certified Public Accountant in the State of Texas.
C.W. MACLEOD has served as the Vice President Business Development and Planning
for the Company since January 2002. From November 1999 to December 2001, he was
Vice President Investment Banking with Raymond James and Associates, Inc. From
February 1990 to October 1999, Mr. MacLeod was a principal with Kirkpatrick
Energy Associates, Inc. where he was responsible for originating corporate
finance and research products for energy clients. His previous experience
includes positions as an independent petroleum geologist, a manager of
exploration and production for an independent oil and gas producer and geologic
positions with Ladd Petroleum Corporation and Resource Sciences Corporation. Mr.
MacLeod graduated from Eastern Michigan University with a B.S. in Geology and
earned his M.B.A. from the University of Tulsa. Mr. MacLeod is a registered
professional geologist in the state of Wyoming.
ROBERT C. THOMAS has served as Vice President, General Counsel and Corporate
Secretary since March 1997. From February 1991 to March 1997, he served in
similar capacities for the Company's corporate predecessor. From 1988 to January
1991, he was associate and acting general counsel for Mesa Limited Partnership
in Amarillo, Texas. Mr. Thomas holds a B.S. degree in Finance and a J.D. degree
in Law from the University of Texas at Austin.
24
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
As of March 14, 2003, we estimate there were approximately 2,687
beneficial holders of our Common Stock. Our Common Stock is listed on the NASDAQ
National Market ("NASDAQ") and traded under the symbol "EPEX". As of March 14,
2003, we had 9,465,734 shares outstanding and our closing price on NASDAQ was
$4.05 per share. The following table sets forth, for the periods indicated, the
high and low closing sales prices for our Common Stock as listed on NASDAQ.
COMMON STOCK PRICES
-----------------------------------------
HIGH LOW
($) ($)
------------------- ------------------
CALENDAR 2002
First Quarter 5.84 4.77
Second Quarter 6.54 5.00
Third Quarter 5.25 4.04
Fourth Quarter 4.27 2.80
CALENDAR 2001
First Quarter 9.50 6.88
Second Quarter 9.45 5.50
Third Quarter 7.10 4.05
Fourth Quarter 5.74 4.16
We have never paid a dividend, cash or otherwise, and do not intend to
in the foreseeable future. The payment of future dividends will be determined by
our Board of Directors in light of conditions then existing, including our
earnings, financial condition, capital requirements, restrictions in financing
agreements, business conditions and other factors. See ITEMS 1 AND 2. --BUSINESS
AND PROPERTIES--"FORWARD LOOKING INFORMATION AND RISK FACTORS--We do not intend
to pay dividends and our ability to pay dividends is restricted ".
25
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 our financial statements and notes
thereto, which follow:
Year Ended December 31,
-------------------------------------------------------------------------------
2002 2001(5) 2000 (1) 1999 (1) 1998 (1)
------------ ------------ ----------- ------------ ------------
(in thousands, except per share amounts)
OPERATIONAL DATA:
Oil and natural gas revenue $ 20,911 $ 29,811 $ 23,774 $ 14,486 $ 15,463
Operating expenses:
Oil and natural gas operating
expenses including production
and ad valorem taxes 3,831 5,001 3,955 3,039 3,376
Depletion, depreciation and
amortization 10,427 9,378 7,641 8,512 10,002
Impairment of oil and natural
gas properties -- -- -- -- 10,013
Litigation settlement -- 3,547 -- -- --
General and administrative
expenses 4,826 5,038 3,824 4,528 4,583
Deferred compensation expense
(2) 403 (497) 1,027 350 621
Other charge -- -- -- 1,688 2,898
------------ ------------ ----------- ------------ ------------
Total operating expenses 19,487 22,467 16,447 18,117 31,493
------------ ------------ ----------- ------------ ------------
Operating income (loss) 1,424 7,344 7,327 (3,631) (16,030)
Interest expense, net (228) (215) (172) (130) (90)
Interest income 27 128 98 52 133
Loss on sale of investment -- -- (355) -- --
------------ ------------ ----------- ------------ ------------
Income (loss) before income taxes
and cumulative effect of
accounting change 1,223 7,257 6,898 (3,709) (15,987)
Income tax benefit (expense) (473) 819 -- -- 983
------------ ------------ ----------- ------------ ------------
Income (loss) before cumulative
effect of accounting change 750 8,076 6,898 (3,709) (15,004)
Cumulative effect of accounting
change -- -- -- -- 1,781
------------ ------------ ----------- ------------ ------------
Net income (loss) $ 750 $ 8,076 $ 6,898 $ (3,709) $ (13,223)
============ =========== =========== =========== ===========
Basic earnings (loss) per share:
(3)
Income (loss) before cumulative
effect of accounting change $ 0.08 $ 0.87 $ 0.75 $ (0.43) $ (1.93)
Cumulative effect of accounting
change -- -- -- -- 0.23
------------ ------------ ----------- ------------ ------------
Basic earnings (loss) per share $ 0.08 $ 0.87 $ 0.75 $ (0.43) $ (1.70)
============ =========== =========== =========== ===========
Diluted earnings (loss) per
share: (3)
Income (loss) before cumulative
effect of accounting change $ 0.08 $ 0.83 $ 0.74 $ (0.43) $ (1.93)
Cumulative effect of accounting
change -- -- -- -- 0.23
------------ ------------ ----------- ------------ ------------
Diluted earnings (loss) per share $ 0.08 $ 0.83 $ 0.74 $ (0.43) $ (1.70)
============ =========== =========== =========== ===========
Basic weighted average number of
shares outstanding (3) 9,384 9,281 9,183 8,680 7,759
Diluted weighted average number
of shares outstanding (3) 9,606 9,728 9,330 8,680 7,759
SELECT CASH FLOW DATA:
Net income (loss) $ 750 $ 8,076 $ 6,898 $ (3,709) $ (13,223)
Interest expense 228 215 172 130 90
Income taxes 473 (819) -- -- (983)
Depletion, depreciation and
amortization 10,427 9,378 7,641 8,512 10,002
------------ ------------ ----------- ------------ ------------
EBITDA(4) 11,878 16,850 14,711 4,933 (4,114)
Other 259 (85) 1,265 1,048 10,139
Net changes in working capital (1,729) 5,386 (6,330) (373) 5,686
------------ ------------ ----------- ------------ ------------
Net cash provided by operating
activities $ 10,408 $ 22,151 $ 9,646 $ 5,608 $ 11,711
============ =========== =========== ============ ============
26
Capital expenditures $ (19,610) $ (28,989) $ (10,718) $ (14,588) $ (34,824)
Other investing activities 355 -- 5,323 7,329 6,835
------------ ----------- ----------- ---------- -----------
Net cash used in investing
activities $ (19,255) $ (28,989) $ (5,395) $ (7,259) $ (27,989)
------------ ----------- ----------- ---------- -----------
Net cash provided by (used in)
financing activities $ 10,623 $ 7,383 $ (4,003) $ 1,651 $ 12,500
============ =========== =========== ========== ===========
As of December 31,
------------------------------------------------------------------------------
2002 2001 2000 1999 1998
------------- ------------ ------------- ------------- -----------
(in thousands)
SELECT BALANCE SHEET DATA:
Working capital surplus (deficit) $ 3,311 $ 682 $ 2,879 $ (4,977) $ (8,255)
Property and equipment, net 75,682 66,853 47,242 45,976 47,259
Total assets 84,023 74,704 56,942 54,740 56,006
Long-term debt, including current
maturities 20,500 10,000 3,000 6,800 12,500
Stockholders' equity 58,533 58,099 50,129 42,174 36,956
---------------
(1) Certain prior year balances have been reclassified to conform to the
current year presentation.
(2) Deferred compensation expense includes the amortization of compensation
costs related to restricted stock grants and the non-cash charge or credit
related to requirements under FASB Interpretation No. (FIN) 44, Accounting
for Certain Transactions involving Stock Compensation. At December 31,
2000, a charge was required under FIN 44 when the daily average market
price of our stock exceeded the strike price of certain options. At
December 31, 2001, our daily average market price was below the strike
price of these options and as a result, a credit was required to reduce
compensation expense except as it related to repriced options exercised in
2001. During 2002, certain options and restricted stock were allowed to
vest earlier than the original vesting date as part of a termination
agreement. A charge under FIN 44 was required related to these
transactions.
(3) Basic and diluted earnings (loss) per share has been computed based on the
net income (loss) shown above and assuming the 4,701,361 shares of Common
Stock issued in connection with the Combination (as defined below in ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS--"General Overview") were outstanding for all periods prior
to the Combination, effective March 3, 1997.
(4) EBITDA represents income (loss) before interest expense, income taxes,
depletion, depreciation and amortization. Our management believes that
EBITDA may provide additional information about our ability to meet our
future requirements for debt service, capital expenditures and working
capital. EBITDA is a financial measure commonly used in the oil and
natural gas industry and should not be considered in isolation or as a
substitute for net income, operating income, cash flows from operating
activities or any other measure of financial performance presented in
accordance with generally accepted accounting principles or as a measure
of a company's profitability or liquidity. Because EBITDA excludes some,
but not all, items that affect net income, this measure may vary among
companies. The EBITDA data presented above may not be comparable to a
similarly titled measure of other companies.
(5) As discussed in Note 2 to the Consolidated Financial Statements, effective
January 1, 2001, we changed our method of accounting for derivative
instruments.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is a review of our financial position and results of
operations for the periods indicated. Our Consolidated Financial Statements and
Supplementary Data and the related notes thereto contain detailed information
that should be referred to in conjunction with Management's Discussion and
Analysis of Financial Condition and Results of Operations.
GENERAL OVERVIEW
We were organized as a Delaware corporation in August 1996 in
connection with our initial public offering (the "Offering") and the related
combination of certain entities that held interests in the Edge Joint Venture II
(the "Joint Venture") and certain other oil and natural gas properties, herein
referred to as the "Combination". In a series of combination transactions, we
issued an aggregate of 4,701,361 shares of common stock and received in exchange
100% of the ownership interests in the Joint Venture and certain other oil and
natural gas properties. In March 1997, and contemporaneously with the
Combination, we completed the Offering of 2,760,000 shares of our common stock
generating proceeds of approximately $40 million, net of expenses.
27
We have evolved over time from a prospect generation organization
focused solely on high-risk, high-reward exploration to a team driven
organization focused on a balanced program of exploration, exploitation,
development and acquisition of oil and natural gas properties. Following a
top-level management change in late 1998, a more disciplined style of business
planning and management was integrated into our technology-driven drilling
activities. We believe these changes in our strategy and business discipline
will result in continued growth in reserves, production and financial strength.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
The preparation of financial statements in conformity with generally
accepted accounting principles in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues, expenses and disclosure of contingent assets and
liabilities in the accompanying financial statements. Changes in these
estimates could materially affect our financial position, results of operations
or cash flows. Key estimates used by management include revenue and expense
accruals, environmental costs, depreciation and amortization, asset impairment
and fair values of assets acquired. Significant accounting policies that we
employ are presented in the notes to the consolidated financial statements.
REVENUE RECOGNITION
We recognize oil and natural gas revenue from our interests in
producing wells as oil and natural gas is produced and sold from those wells.
Oil and natural gas sold by us is not significantly different from our share of
production.
OIL AND NATURAL GAS PROPERTIES
Investments in oil and natural gas properties are accounted for using
the full cost method of accounting. All costs associated with the exploration,
development and acquisition of oil and natural gas properties, including
salaries, benefits and other internal costs directly attributable to these
activities are capitalized within a cost center. Our oil and natural gas
properties are located within the United States of America that constitutes one
cost center.
In accordance with the full cost method of accounting, we capitalized a
portion of interest expense on borrowed funds. Employee related costs that are
directly attributable to exploration and development activities are also
capitalized. These costs are considered to be direct costs based on the nature
of their function as it relates to the exploration and development function.
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.
Unevaluated properties are evaluated periodically for impairment on a
property-by-property basis. If the results of an assessment indicated 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.
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 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 our quarterly filings with
the Securities and Exchange Commission. No adjustment related to the ceiling
test was required during the years ended December 31, 2002, 2001, or 2000.
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. Abandonment of oil and natural gas properties are
accounted for as adjustments of capitalize costs with no loss recognized.
OIL AND NATURAL GAS RESERVES
There are uncertainties inherent in estimating oil and natural gas
reserve quantities, projecting future production rates and projecting the
timing of future development expenditures. In addition, reserve estimates of
new discoveries are more imprecise than those of properties with a production
history. Accordingly, the reserve estimates of new discoveries are subject to
change as additional information becomes available. Proved reserves are the
estimated quantities of crude oil, condensate and natural gas that geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions at the end of the respective years. Proved developed reserves are
those reserves expected to be recovered through existing equipment and
operating methods.
DERIVATIVES AND HEDGING ACTIVITIES
Due to the instability of oil and natural gas prices, we have entered
into, from time to time, price risk management transactions (e.g., swaps,
collars and floors) for a portion of our oil and natural gas production to
achieve a more predictable cash flow, as well as to reduce exposure from price
fluctuations. While the use of these arrangements limits the benefit to us of
increases in the price of oil and natural gas, it also limits the downside risk
of adverse price movements. Our hedging arrangements typically apply to only a
portion of our production, providing only partial price protection against
declines in oil and natural gas prices. We account for these transactions as
hedging activities and, accordingly, realized gains and losses are included in
oil and natural gas revenue during the period the hedged production occurs.
We formally assess, both at the hedge's inception and on an ongoing
basis, whether the derivatives that are used in hedging transactions are
expected to be highly effective in offsetting changes in cash flows of hedged
transactions. In the event it is determined that the use of a particular
derivative may not be or has ceased to be effective in pursuing a hedging
strategy, hedge accounting is discontinued prospectively.
Our revenue, profitability and future rate of growth and ability to
borrow funds or obtain additional capital, and the carrying value of our
properties, are substantially dependent upon prevailing prices for oil and
natural gas. These prices are dependent upon numerous factors beyond our
control, such as economic, political and regulatory developments and
competition from other sources of energy. A substantial or extended decline in
oil and natural gas prices could have a material adverse effect on our
financial condition, results of operations and access to capital, as well as
the quantities of oil and natural gas reserves that we may economically produce.
STOCK-BASED COMPENSATION
We account for stock compensation plans under the intrinsic value
method of Accounting Principles Board ("APB") Opinion No. 25, "Accounting for
Stock Issued to Employees." No compensation expense is recognized for stock
options that had an exercise price equal to the market value of their
underlying common stock on the date of grant. As allowed by SFAS No. 123,
"Accounting for Stock Based Compensation," we have continued to apply APB
Opinion No. 25 for purposes of determining net income. In December 2002, the
FASB issued SFAS No. 148, "Accounting for Stock Based Compensation - Transition
and Disclosure - an amendment of FASB Statement No. 123" to provide alternative
methods of transition for a voluntary change to the fair value based method of
accounting for stock-based employee compensation. Additionally, the statement
amend the disclosure requirements of SFAS No. 123 to require prominent
disclosures in both annual and interim financial statements about the method of
accounting for stock-based compensation and the effect of the method used on
reported results.
We are also subject to reporting requirements of FASB Interpretation
No. (FIN) 44, "Accounting for Certain Transactions involving Stock Compensation"
that requires a non-cash charge to deferred compensation expense if the market
price of our common stock at the end of a reporting period is greater than the
exercise price of certain stock options. After the first such adjustment is
made, each subsequent period is adjusted upward or downward to the extent that
the market price exceeds the exercise price of the options. The charge is
related to non-qualified stock options granted to employees and directors in
prior years conjunction with the repricing.
28
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 2002 COMPARED TO THE YEAR ENDED DECEMBER 31, 2001
REVENUE AND PRODUCTION
Oil and natural gas revenue decreased 30% from $29.8 million in 2001 to
$20.9 million in 2002. For 2002, natural gas production comprised 76% of total
production and contributed 79% of total revenue, oil and condensate comprised
10% of total production and contributed 13% of total revenue, and NGL production
comprised 14% of total production and contributed 8% of total revenue. For 2001,
natural gas production comprised 86% of total production and 88% of total
revenue, while oil and condensate production accounted for 10% of total
production and 9% of revenue, and NGL production comprised 4% of total
production and 3% of total revenue.
The following table summarizes production volumes, average sales prices
and operating revenue for our oil and natural gas operations for the years ended
December 31, 2002 and 2001.
2002 PERIOD COMPARED
TO 2001 PERIOD
--------------------------------
DECEMBER 31, INCREASE % INCREASE
(DECREASE) (DECREASE)
------------------------------------
2002 (2) 2001
---------------- ---------------- --------------- ------------
PRODUCTION VOLUMES:
Natural gas (Mcf) 5,266,390 6,198,871 (932,481) (15)%
Oil and condensate (Bbls) 119,527 115,728 3,799 3%
Natural gas liquids (Bbls) 161,301 45,701 115,600 253%
Natural gas equivalent (Mcfe) 6,951,357 7,167,445 (216,088) (3)%
AVERAGE SALES PRICE:
Natural gas ($ per Mcf)(1)
$ 3.14 $ 4.23 $ (1.09) (26)%
Oil and condensate ($ per Bbl) $ 22.88 $ 23.94 $ (1.06) (4)%
Natural gas liquids ($ per Bbl) $ 10.31 $ 17.74 $ (7.43) (42)%
Natural gas equivalent ($ per Mcfe) (1) $ 3.01 $ 4.16 $ (1.15) (28)%
OPERATING REVENUE:
Natural gas (1) $ 16,513,096 $ 26,229,567 $ (9,716,471) (37)%
Oil and condensate 2,734,491 2,770,825 (36,334) (1)%
Natural gas liquids 1,663,707 810,525 853,182 105%
--------------- -------------- -------------
Total (1) $ 20,911,294 $ 29,810,917 $ (8,899,623) (30)%
=============== ============== =============
(1) Includes the effect of hedging.
(2) Results for 2002 were favorably impacted by the recognition in the second
quarter of 2002 of revenue associated with underaccruals in prior periods. This
adjustment resulted in 142 MMcfe of additional production and $577,200
additional revenue.
Natural gas revenue decreased 37% from $26.2 million for the year ended
December 31, 2001 to $16.5 million for 2002. Significantly lower realized prices
coupled with a decline in production for the year were slightly offset by a
lower realized hedge loss. The average natural gas sales price for production in
2002 was $3.20 per Mcf, exclusive of hedging activity, compared to $4.38 per Mcf
for 2001, exclusive of hedging activity. This decrease in average price received
resulted in decreased revenue of approximately $6.2 million (based on current
year production). Included within natural gas revenue for the year ended
December 31, 2002 and 2001 was $(0.3) million and $(0.9) million, respectively,
representing losses from hedging activity. These losses decreased the effective
natural gas sales price by $(0.06) per Mcf and $(0.15) per Mcf, for the years
ended December 31, 2002 and 2001, respectively. For the year ended December 31,
2002, natural gas production decreased 15% from 17.0 Mcf/d in 2001 to 14.4 Mcf/d
in 2002 due primarily to natural declines in production at our Austin Field and
O'Connor Ranch properties, partially offset by increased production from new
wells drilled in late 2001 and in 2002. This decrease in production compared to
the prior year resulted in a decrease in revenue of approximately $4.1 million
(based on 2001 comparable period prices).
29
Revenue from the sale of oil and condensate totaled $2.7 million for
the year ended December 31, 2002, a decrease of 1% from the prior year total of
$2.8 million. The average realized price for oil and condensate for the year
ended December 31, 2002 was $22.88 per barrel compared to $23.94 per barrel in
2001. Lower average prices for the year 2002 resulted in a decrease in revenue
of approximately $127,300 (based on current year production). Production volumes
for oil and condensate increased 3% to 327 Bbls/d for the year ended December
31, 2002 compared to 317 Bbls/d for the same prior year period. The increase in
oil and condensate production resulted in an increase in revenue of
approximately $91,000 (based on 2001 comparable period average prices).
Revenue from the sale of NGLs totaled $1.7 million for the year ended
December 31, 2002, an increase of 105% from the 2001 total of $0.8 million.
Production volumes for NGLs increased 253%, from 125 Bbls/d for the year ended
December 31, 2001 to 442 Bbls/d for the year ended December 31, 2002. The
increase in NGL production increased revenue by $2.1 million (based on 2001
comparable period average prices). This increase in production was largely due
to increased liquids processing stemming from Gato Creek Field (Webb County,
Texas), an acquisition made in late 2001. Lower average realized prices for the
year ended December 31, 2002 resulted in a decrease in revenue of $1.2 million
(based on current year production). The average realized price for NGLs for the
year ended December 31, 2002 was $10.31 per barrel compared to $17.74 per barrel
for the same period in 2001.
COSTS AND OPERATING EXPENSES
Operating expenses for the year ended December 31, 2002 totaled $2.2
million compared to $2.8 million in the same period of 2001, a decrease of 22%.
Current year results were impacted by lower well control insurance and salt
water disposal costs, partially offset by higher treating costs incurred in 2002
compared to the prior year. Operating expenses averaged $0.32 per Mcfe for the
year ended December 31, 2002 compared to $0.39 per Mcfe for the prior year
period.
Severance and ad valorem taxes for the year ended December 31, 2002
decreased 26% from $2.2 million in 2001, to $1.6 million in 2002. Severance tax
expense for 2002 was 39% lower than the prior year period as a result of lower
revenue as well as severance tax exemption credits on certain properties. For
the year ended December 31, 2002, severance tax expense was approximately 5.7%
of total revenue compared to 6.5% of total revenue for the comparable 2001
period. Ad valorem costs, however, increased from approximately $222,000 in 2001
to over $419,000 in 2002 due primarily to additional costs on the Ibarra and La
Jollo Parr properties as well as the Gato Creek properties which were acquired
at year-end 2001. On an equivalent basis, severance and ad valorem taxes
averaged $0.23 per Mcfe and $0.30 per Mcfe for the years ended December 31, 2002
and 2001, respectively.
Depletion, depreciation and amortization expense ("DD&A") for the year
ended December 31, 2002 totaled $10.4 million compared to $9.4 million for the
year ended December 31, 2001. Full cost depletion on our oil and natural gas
properties totaled $9.7 million for 2002 compared to $8.7 million in 2001.
Depletion expense on a unit of production basis for the year ended December 31,
2002 was $1.40 per Mcfe, 15% higher than the 2001 rate of $1.22 per Mcfe. The
higher depletion rate per Mcfe resulted in an increase in depletion expense of
$1.2 million. For the year ended December 31, 2002, lower oil and natural gas
production compared to the prior year period resulted in a decrease in depletion
expense of $0.2 million. The increase in the depletion rate was primarily due to
a higher amortizable base in 2002 compared to the prior year.
In December 2001, we recorded costs of $3.5 million related to the
settlement of our litigation with BNP.
General and administrative expenses ("G&A") for the year ended December
31, 2002, excluding the deferred compensation expense discussed below, totaled
$4.8 million, a 4% decrease from the 2001 total of $5.0 million, due primarily
to bad debt expense of $525,000 reserved in 2001. In addition, 2002 salaries and
benefits were seven percent lower than 2001 costs. Offsetting these lower costs
were higher professional service fees (primarily legal costs and audit fees),
higher officers and directors insurance costs and higher franchise taxes for
2002 compared to 2001. For the years ended December 31, 2002 and 2001, overhead
reimbursement fees reduced G&A costs by $208,201 and $137,184, respectively. G&A
on a unit of production basis for the year ended December 31, 2002 was $0.69 per
Mcfe compared to $0.70 per Mcfe for the comparable 2001 period. We believe that
lower lease costs for our new headquarters will have a positive impact on G&A in
2003. See Part I - Office and Equipment.
30
Deferred compensation cost reported in accordance with FASB
Interpretation No. (FIN) 44, Accounting for Certain Transactions involving Stock
Compensation was a charge of $3,385 for the year ended December 31, 2002
compared to a credit of $(850,281) in the comparable prior year period. FIN 44
requires, among other things, a non-cash charge to compensation expense if the
price of our common stock on the last trading day of a reporting period is
greater than the exercise price of certain options. FIN 44 could also result in
a credit to compensation expense to the extent that the trading price declines
from the trading price as of the end of the prior period, but not below the
exercise price of the options. We adjust deferred compensation expense upward or
downward on a monthly basis based on the trading price at the end of each such
period as necessary to comply with FIN 44. We are required to report under this
rule as a result of non-qualified stock options granted to employees and
directors in prior years and re-priced in May of 1999, as well as certain
options newly issued in conjunction with the repricing.
Also included in deferred compensation is amortization related to
restricted stock awards granted during 2001 and 2002. For the years ended
December 31, 2002 and 2001, such amortization totaled $399,249 and $353,371,
respectively.
Included in other income (expense) was interest expense of $227,759 for
the year ended December 31, 2002 compared to $214,619 in the same 2001 period.
Interest expense, including facility fees, was $766,693 for the year 2002 on
weighted average debt of $15.4 million compared to interest expense of $137,623
on weighted average debt of approximately $0.7 million for the same prior year
period. Capitalized interest for the year ended December 31, 2002 totaled
$623,413 compared to $24,402 in the prior year. Also included in interest
expense for the years ended December 31, 2002 and 2001 was $84,479 and $101,398,
respectively, representing amortization of deferred loan costs associated with a
new credit facility.
Interest income totaled $26,954 for the year ended December 31, 2002
compared to $127,717 for the same period in 2001. The decrease in interest
income is due primarily to the overall decrease in funds invested in overnight
money market funds.
An income tax provision was recorded for the year ended December 31,
2002 of $473,060. As of December 31, 2002, approximately $27.4 million of net
operating loss carryforwards have been accumulated that begin to expire in 2012.
For the year ended December 31, 2001, an income tax benefit of $818,897 was
recorded as a result of reversing a valuation reserve. Currently, we do not
anticipate a federal tax liability or making federal tax payments in 2003.
For the year ended December 31, 2002, the Company had net income of
$0.7 million, or $0.08 basic earnings per share, as compared to net income of
$8.1 million, or $0.87 basic earnings per share, in 2001. Weighted average
shares outstanding increased from approximately 9.3 million for the year ended
December 31, 2001 to 9.4 million in the comparable 2002 period. The increase was
due primarily to options exercised and vesting of restricted stock during 2002.
YEAR ENDED DECEMBER 31, 2001 COMPARED TO THE YEAR ENDED DECEMBER 31, 2000
REVENUE AND PRODUCTION
Oil and natural gas revenue increased 25% from $23.8 million in 2000 to
$29.8 million in 2001. For 2001, natural gas production comprised 86% of total
production and contributed 88% of total revenue, oil and condensate comprised
10% of total production and contributed 9% of total revenue, and NGL's comprised
4% of total production and contributed 3% of total revenue. For 2000, natural
gas production comprised 83% of total production and 84% of total revenue while
oil and condensate production accounted for 9% of total production and 11% of
revenue and NGLs production comprised 8% of total production and 5% of oil and
gas revenue.
The following table summarizes production volumes, average sales prices
and operating revenue for our oil and natural gas operations for the years ended
December 31, 2001 and 2000.
31
2001 PERIOD COMPARED
TO 2000 PERIOD
--------------------------------
DECEMBER 31, %
------------------------------------ INCREASE INCREASE
2001 2000 (DECREASE) (DECREASE)
---------------- ---------------- --------------- ------------
PRODUCTION VOLUMES:
Natural gas (Mcf) 6,198,871 5,206,236 992,635 19%
Oil and condensate (Bbls) 115,728 96,925 18,803 19%
Natural gas liquids (Bbls) 45,701 76,835 (31,134) (41)%
Natural gas equivalent (Mcfe) 7,167,445 6,248,796 918,649 15%
AVERAGE SALES PRICE:
Natural gas ($ per Mcf)(1) $ 4.23 $ 3.84 $ 0.39 10%
Oil and condensate ($ per Bbl)(1) $ 23.94 $ 26.16 $ (2.22) (8)%
Natural gas liquids ($ per Bbl) $ 17.74 $ 16.37 $ 1.37 8%
Natural gas equivalent ($ per Mcfe) (1) $ 4.16 $ 3.80 $ 0.36 9%
OPERATING REVENUE:
Natural gas (1) $ 26,229,567 $ 19,980,704 $ 6,248,863 31%
Oil and condensate (1) 2,770,825 2,536,028 234,797 9%
Natural gas liquids 810,525 1,257,684 (447,159) (36)%
---------------- ---------------- ---------------
Total (1) $ 29,810,917 $ 23,774,416 $ 6,036,501 25%
---------------- ---------------- ---------------
(1) Includes the effect of hedging.
Natural gas revenue increased 31% from $20.0 million for the year ended
December 31, 2000 to $26.2 million for 2001 due primarily to increased
production and the favorable impact of higher natural gas prices. For the year
ended December 31, 2001, natural gas production increased 19% from 14.2 Mcf/d in
2000 to 17.0 Mcf/d in 2001 resulting in an increase in revenue of approximately
$4.1 million (based on 2000 comparable period prices). The average natural gas
sales price for production in 2001 was $4.38 per Mcf, exclusive of hedging
activity, compared to $4.14 per Mcf for 2000, exclusive of hedging activity.
This increase in average price received resulted in increased revenue of
approximately $1.5 million (based on current year production). Included within
natural gas revenue for the year ended December 31, 2001 and 2000 was $(0.9)
million and $(1.5) million, respectively, representing losses from hedging
activity. These losses decreased the effective natural gas sales price by
$(0.15) per Mcf and $(0.30) per Mcf, for the years ended December 31, 2001 and
2000, respectively.
Revenue from the sale of oil and condensate totaled $2.8 million for
the year ended December 31, 2001, an increase of 9% from the prior year total of
$2.5 million. The year ended December 31, 2000 included net losses from oil
hedge activity of $223,454. No oil hedges were in place for 2001. Production
volumes for oil and condensate increased 19% to 317 Bbls/d for the year ended
December 31, 2001 compared to 265 Bbls/d for the same prior year period. The
increase in oil and condensate production caused an increase in revenue of
approximately $535,300 (based on 2000 comparable period average prices before
hedges). The average price received for oil and condensate for the year ended
December 31, 2001 was $23.94 per barrel compared to $28.47 per barrel, excluding
the impact of net oil hedge losses of $(2.31) per barrel, in 2000. Lower average
prices for the year 2001 resulted in a decrease in revenue of $524,000 (based on
current year production).
Revenue from the sale of NGLs totaled $0.8 million for the year ended
December 31, 2001, a decrease of 36% from the 2000 total of $1.3 million.
Production volumes for NGLs for the year ended December 31, 2001 decreased 41%,
from 210 Bbls/d to 125 Bbls/d, as compared to the year ended December 31, 2000.
The decrease in NGL production decreased revenue by $509,600 (based on 2000
comparable period average prices). This decrease in production was largely due
to high natural gas prices decreasing the economic value of NGL's and a
resulting decision by management not to process our gas during several months of
2001. Favorable pricing for the year ended December 31, 2001 resulted in an
increase in revenue of $62,500 (based on current year production). The average
realized price for NGLs for the year ended December 31, 2001 was $17.74 per
barrel compared to $16.37 per barrel for the same period in 2000.
32
Production of oil and natural gas was significantly impacted by our
drilling results in the second half of 2000 and in 2001. We successfully drilled
and completed 17 gross (7.081 net) wells in the year ended December 31, 2001
that added additional production and revenue for 2001. Gas production increases
were due primarily to the drilling of, and strong performance from, the O'Connor
Ranch wells, the Ibarra and La Jolla Parr wells on our La Jolla prospect, the
Mire #1 well on our Horeb prospect and the Robertson #1 well on our Duson Frio
prospect. Partially offsetting the favorable results of drilling were production
declines on our older wells, primarily the Margo #1 and #2 wells.
COSTS AND OPERATING EXPENSES
Operating expenses for the year ended December 31, 2001 totaled $2.8
million compared to $2.0 million in the same period of 2000, an increase of 44%.
Current year results were impacted by the increased number of wells operating in
2001 compared to the prior year as well as higher treating costs at the Austin
facility for a portion of 2001, higher salt water disposal costs on our older
wells, and higher well control insurance costs incurred in 2001 compared to the
prior year. Operating expenses averaged $0.39 per Mcfe for the year ended
December 31, 2001 compared to $0.31 per Mcfe for the prior year period. The
increase in operating expenses on a Mcfe basis was due to the factors resulting
in an overall increase in operating expenses described previously.
Severance and ad valorem taxes for the year ended December 31, 2001
increased 9% from $2.0 million in 2000, to $2.2 million in 2001, due to higher
severance taxes paid on the increased revenue, primarily in the first quarter of
2001. On an equivalent basis, severance and ad valorem taxes were $0.30 per Mcfe
and $0.32 per Mcfe for the years ended December 31, 2001 and 2000, respectively.
Depletion, depreciation and amortization expense ("DD&A") for the year
ended December 31, 2001 totaled $9.4 million compared to $7.6 million for the
year ended December 31, 2000. Full cost DD&A on our oil and natural gas
properties totaled $8.7 million for 2001 compared to $7.0 million in 2000.
Depletion expense on a unit of production basis for the year ended December 31,
2001 was $1.22 per Mcfe, 10% higher than the 2000 rate of $1.11 per Mcfe. The
higher depletion rate per Mcfe resulted in an increase in depletion expense of
$0.8 million. For the year ended December 31, 2001, higher oil and natural gas
production compared to the prior year period resulted in an increase in
depletion expense of $1.0 million. The increase in the depletion rate was
primarily due to a higher amortizable base in 2001 compared to the prior year.
In December 2001, we recorded costs of $3.5 million related to the
settlement of our litigation with BNP.
General and administrative expenses ("G&A") for the year ended December
31, 2001, excluding the deferred compensation expense discussed below, totaled
$5.0 million, a 32% increase from the 2000 total of $3.8 million. The increase
in costs was due primarily to bad debt expense of $525,000 reserved in 2001
($225,000 of which related to purchases by an Enron affiliate), costs of
$100,000 to purchase options from a former employee, higher salaries and related
benefits, and higher legal and audit fees. For the years ended December 31, 2001
and 2000, overhead reimbursement fees of approximately $137,200 and $120,300,
respectively, reduced G&A costs. G&A on a unit of production basis for the year
ended December 31, 2001 was $0.70 per Mcfe ($0.62 per Mcfe excluding the bad
debt expense and the purchase of options) compared to $0.61 per Mcfe for the
comparable 2000 period.
Deferred compensation cost reported in accordance with FASB
Interpretation No. (FIN) 44, Accounting for Certain Transactions involving Stock
Compensation was a credit of $(850,281) for the year ended December 31, 2001
compared to a charge of $899,548 in the comparable prior year period. FIN 44
requires, among other things, a non-cash charge to compensation expense if the
price of our common stock on the last trading day of a reporting period is
greater than the exercise price of certain options. FIN 44 could also result in
a credit to compensation expense to the extent that the trading price declines
from the trading price as of the end of the prior period, but not below the
exercise price of the options. We adjust deferred compensation expense upward or
downward on a monthly basis based on the trading price at the end of each such
period as necessary to comply with FIN 44. We are required to report under this
rule as a result of non-qualified stock options granted to employees and
directors in prior years and re-priced in May of 1999, as well as certain
options newly issued in conjunction with the repricing.
33
Also included in deferred compensation is amortization related to
restricted stock awards totaling $353,371 and $127,946 for the years ended
December 31, 2001 and 2000, respectively.
Included in other income (expense) was interest expense of $214,619 for
the year ended December 31, 2001 compared to $171,783 in the same 2000 period.
Interest expense, including facility fees, was $137,623 for the year 2001 on
weighted average debt of $0.7 million compared to interest expense of $546,340
on weighted average debt of approximately $5.6 million for the same prior year
period. Also included in interest expense for the years ended December 31, 2001
and 2000 was $101,398 and $24,720, respectively, representing amortization of
deferred loan costs associated with a new credit facility. Capitalized interest
for the year ended December 31, 2001 totaled $24,402 compared to $399,277 in the
prior year. The reduction in capitalized interest resulted from lower interest
costs incurred during the year ended December 31, 2001 compared to the same
prior year period. Although gross interest expense has decreased compared to the
prior year, the effect of less interest being capitalized to oil and natural gas
properties has resulted in higher net interest costs reported in our results of
operations.
Interest income totaled $127,717 for the year ended December 31, 2001
compared to $97,860 for the same period in 2000. The increase in interest income
is due to the overall increase in funds invested in overnight money market
funds.
Other income (expense) for the year ended December 31, 2000 also
included a loss on the sale of our investment in Frontera of $(354,733) or
$(0.04) per share.
An income tax benefit was recorded for the year ended December 31, 2001
of $818,897. As of December 31, 2001, approximately $18.2 million of net
operating loss carryforwards have been accumulated that begin to expire in 2012.
Based on our year-end 2001 projections, we determined that we would fully
realize our recorded tax assets. Accordingly, $818,897 in associated valuation
reserves was reversed in 2001. Future financial statement income will
necessitate income tax provisions at our effective rate. For the year ended
December 31, 2000, no tax expense or benefit was recorded because an allowance
was provided to offset the tax benefits of certain tax assets.
For the year ended December 31, 2001, the Company had net income of
$8.1 million, or $0.87 basic earnings per share, as compared to net income of
$6.9 million, or $0.75 basic earnings per share, in 2000.
Weighted average shares outstanding increased from approximately 9.2
million for the year ended December 31, 2000 to 9.3 million in the comparable
2001 period. The increase was due primarily to options exercised and vesting of
restricted stock during 2001.
LIQUIDITY AND CAPITAL RESOURCES
In March 1997, we completed the Offering of 2,760,000 shares of our
common stock at a public offering price of $16.50 per share. The Offering
provided us with proceeds of approximately $40 million, net of expenses. We used
approximately $12.7 million to repay our long-term outstanding indebtedness
incurred under our revolving credit facility in place at the time, subordinated
loans and equipment loans. The remaining proceeds from the Offering, together
with cash flows from operations, were used to fund capital expenditures,
commitments, and other working capital requirements and for general corporate
purposes.
On May 6, 1999, we completed a "Private Offering" of 1,400,000 shares
of common stock at a price of $5.40 per share. We also issued warrants, which
were purchased for $0.125 per warrant, to acquire an additional 420,000 shares
of common stock at $5.35 per share and are exercisable through May 6, 2004. At
our election, the warrants may be called at a redemption price of $0.01 per
warrant at any time after any date at which the average daily per share closing
bid price for the immediately proceeding 20 consecutive trading days exceeds
$10.70. No warrants have been exercised as of December 31, 2002. Total proceeds,
net of offering costs, were approximately $7.4 million of which $4.9 million was
used to repay debt under our revolving credit facility in place at the time,
with the remainder being utilized to satisfy working capital requirements and to
fund a portion of our exploration program. Pursuant to the terms of the private
placement, we filed a registration statement with the Commission registering the
resale of the shares of Common Stock and the warrants sold in the private
placement, as well as the resale of any shares of Common Stock issued pursuant
to such warrants.
34
We had cash and cash equivalents at December 31, 2002 of $2,568,176
consisting primarily of short-term money market investments, as compared to
$793,287 at December 31, 2001. Working capital was $3.3 million as of December
31, 2002, as compared to $0.7 million at December 31, 2001.
Cash flows provided by operating activities were $10.4 million, $22.2
million and $9.6 million, for the years ended December 31, 2002, 2001, and 2000,
respectively. The decrease in cash flows provided by operating activities in
2002 compared to 2001 was due primarily to lower net income in 2002, a larger
decrease in accrued liabilities for 2002 and a lower decrease in accounts
receivable for 2002 compared to 2001. The significant increase in cash flows
provided by operating activities for the year ended December 31, 2001 compared
to 2000 was primarily due to higher net income in 2001, lower accounts
receivable balance and higher accrued liabilities at December 31, 2001 compared
to the prior year.
We reinvest a substantial portion of our cash flows in our drilling,
acquisition, land and geophysical activities. As a result, we used $19.3 million
in investing activities during 2002. Capital expenditures of $19.6 million for
the year ended December 31, 2002, were partially offset by $0.4 million in
proceeds from the sale of oil and gas properties during 2002. Capital
expenditures of $12.7 million were attributable to the drilling of 13 gross
wells, 11 of which were successful. Acquisition costs totaled $1.4 million for
the year ended December 31, 2002, and an additional $5.5 million in expenditures
was attributable to land holdings, including $1.0 million for increased seismic
data and other geological and geophysical expenditures. The remaining capital
expenditures were associated with computer hardware and office equipment.
During the year ended December 31, 2001, we used $29.0 million in
investing activities, all of which were capital expenditures. Capital
expenditures of $15.9 million were attributed to drilling 22 gross wells, 17 of
which were successful. Acquisition costs totaled $6.7 million for the year ended
December 31, 2001, and an additional $6.0 million was attributable to land
holdings, including $2.6 million for seismic data and other geological and
geophysical expenditures. The remaining capital expenditures were associated
with computer hardware and office equipment.
During the year ended December 31, 2000, we used $5.4 million of cash
in investing activities including capital expenditures of approximately $10.7
million. Capital expenditures of $5.7 million were attributed to the drilling of
26 gross wells, 24 of which were successful. Capital expenditures of $3.2
million were attributable to increased land holdings and $1.8 million was
attributable to increased seismic data and other geologic and geophysical
expenditures. These expenditures were offset by proceeds from the sale of oil
and natural gas properties of $1.8 million and net proceeds from the sale of our
investment in Frontera of $3.5 million.
We currently anticipate capital expenditures in 2003 to be
approximately $15.3 million. Approximately $10.7 million is allocated to our
expected drilling and production activities; $1.9 million is allocated to land
and seismic activities; and $2.7 million relates to capitalized interest and G&A
and other. We plan to fund these expenditures largely from cash flow from
operations plus some modest incremental borrowings. We have not explicitly
budgeted for acquisitions; however, we do expect to spend considerable effort
evaluating acquisition opportunities. We expect to fund acquisitions through
traditional reserve-based bank debt and/or the issuance of equity and, if
required, through additional debt and equity financings.
Cash flows provided by financing activities totaled $10.6 million for
the year ended December 31, 2002 including $11.0 million in borrowings and $0.5
million in repayments under our current credit facility. In addition, we
received $122,653 in proceeds from the issuance of common stock related to
options exercised in 2002. Cash flows provided by financing activities in 2001
were $7.4 million, including borrowings of $11.0 million and repayments of $4.0
million under our credit facility. In addition, we received $390,421 in proceeds
from the issuance of common stock related to options exercised in 2001. Cash
flows used in financing activities in 2000 were $(4.0) million, including
borrowings of $5.4 million and repayments of $9.2 million under our credit
facility and the predecessor facility. We incurred loan costs of approximately
$202,900 during 2000 in establishing our new credit facility.
Due to our active exploration, development and acquisition activities,
we have experienced and expect to continue to experience substantial working
capital requirements. We intend to fund our 2003 capital expenditures,
35
commitments and working capital requirements through cash flows from operations,
and to the extent necessary other financing activities. The projected 2003 cash
flows from operations are estimated to be sufficient to fund our budgeted
exploration and development program. We believe we will be able to generate
capital resources and liquidity sufficient to fund our capital expenditures and
meet such financial obligations as they come due. In the event such capital
resources are not available to us, our drilling and other activities may be
curtailed. See ITEMS 1 AND 2.-- "BUSINESS AND PROPERTIES-- FORWARD LOOKING
INFORMATION AND RISK FACTORS--Our operations have significant capital
requirements."
CREDIT FACILITY
In October 2000, the Company entered into a new credit facility (the
"Credit Facility") with a bank. Borrowings under the Credit Facility bear
interest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%. As of December
31, 2002, $20.5 million in borrowings were outstanding under the Credit
Facility. The Credit Facility matures October 6, 2004 and is secured by
substantially all of the Company's assets.
Originally the borrowing base under the Credit Facility was $5 million
and was subject to automatic reductions at a rate of $300,000 per month
beginning October 31, 2000. In March 2001, the Credit Facility was amended to
increase the borrowing base to $14 million, and to eliminate the $300,000 per
month automatic reduction. In January 2002, the borrowing base was increased to
$18 million. In August 2002, the borrowing base was increased to $25 million.
The borrowing base is expected to be redetermined in the first half of 2003.
The Credit Facility provides for certain restrictions, including but
not limited to, limitations on additional borrowings and issues of capital
stock, sales of oil and natural gas properties or other collateral, engaging in
merger or consolidation transactions. The Credit Facility also prohibits
dividends and certain distributions of cash or properties and certain liens. The
Credit Facility also contains certain financial covenants. The EBITDA to
Interest Expense Ratio requires that (a) our consolidated EBITDA, as defined in
the agreement, for the four fiscal quarters then ended to (b) our consolidated
interest expense for the four fiscal quarters then ended, to not be less than
3.5 to 1.0. The Working Capital ratio requires that the amount of our
consolidated current assets less our consolidated current liabilities, as
defined in the agreement, be at least $1.0 million. The Allowable Expenses ratio
requires that (a) the aggregate amount of our year-to-date consolidated general
and administrative expenses for the period from January 1 of such year through
the fiscal quarter then ended to (b) our year-to-date consolidated oil and gas
revenues, net of hedging activity, for the period from January 1 of such year
through the fiscal quarter then ended, to be less than 0.40 to 1.0.
CONTRACTUAL CASH OBLIGATIONS
The following table summarizes our contractual cash obligations as of
December 31, 2002 by payment due date:
Less
than 1 1-3 4-5 After 5
Total Year Years Years Years
-------- ------ --------- ------- -------
(In thousands)
Long-term debt $ 20,500 $ -- $ 20,500 $ -- $ --
Operating leases 4,257 238 1,249 818 1,952
-------- ------ -------- ------- -------
Total contractual cash
obligations $ 24,757 $ 238 $ 21,749 $ 818 $ 1,952
======== ====== ======== ======= =======
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." SFAS No. 142 applies to all acquired intangible assets
whether acquired singly, as part of a group, or in a business combination. The
statement supersedes Accounting Principals Board, ("APB"), Opinion No. 17,
"Intangible Assets," and carries forward provisions in APB Opinion No. 17
related to internally developed intangible assets. Under this statement,
goodwill is no longer to be amortized but is subject to annual impairment
analysis. We adopted this statement as of January 1, 2002, and we do not have
any goodwill or intangible assets recorded as of December 31, 2002.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." The statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of the
related long-lived asset. Accretion of the liability is recognized each period,
and the capitalized cost is depreciated over the useful life of the related
asset. Upon settlement of the liability, an entity either settles the obligation
for its recorded amount or incurs a gain or loss upon settlement. The standard
is effective for fiscal years beginning after June 15, 2002, therefore we have
adopted SFAS No. 143 effective January 1, 2003 using a cumulative effect
approach to recognize transition amounts for asset retirement obligations, asset
retirement costs and accumulated depreciation. We currently do not include
dismantlement and abandonment costs in the depletion calculation as the vast
majority of our properties are onshore and the salvage value of the tangible
equipment typically offsets our dismantlement and abandonment costs. This
standard will require us to record a liability for the fair value of our
dismantlement and abandonment costs, excluding salvage values. We expect that
36
the adoption of the statement will result in the recognition of additional
liabilities related to asset retirement obligations of approximately $1.1
million.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses the
accounting and reporting for the impairment or disposal of long-lived assets and
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of" and APB Opinion No. 30, "Reporting the
Results of Operations -- Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions." SFAS No. 144 establishes one accounting model for long-lived
assets to be disposed of by sale as well as resolves implementation issues
related to SFAS No. 121. The standard also expands the scope of discontinued
operations to include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The Company adopted
SFAS No. 144 effective January 1, 2002. Because we have elected the full-cost
method of accounting for oil and gas exploration and development activities, the
impairment provisions of SFAS No. 144 do not apply to our oil and gas assets,
which are instead subject to ceiling limitations. For our non-oil and gas
assets, the adoption of SFAS No. 144 did not have a material impact on the
consolidated financial statements.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections". This statement rescinds SFAS No. 4, Reporting Gains and Losses
from Extinguishment of Debt, which required all gains and losses from
extinguishment of debt to be aggregated and, if material, classified as an
extraordinary item, net of income taxes. As a result, the criteria in APB No. 30
will now be used to classify those gains and losses. Any gain or loss on the
extinguishment of debt that was classified as an extraordinary item in prior
periods presented that does not meet the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this Statement
are effective for fiscal years beginning after January 1, 2003. We do not expect
that adoption of this statement will have a material impact on our future
financial condition or results of operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Exit or
Disposal Activities". SFAS No. 146 addresses significant issues regarding the
recognition, measurement and reporting of disposal activities, including
restructuring activities that are currently covered in EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Activity." The
provisions of SFAS No. 146 are effective for exit or disposal activities
initiated after December 31, 2002.
In October 2002, the FASB issued SFAS No. 147, "Acquisitions of Certain
Financial Institutions--an amendment of FASB Statements No. 72 and 144 and FASB
Interpretation No. 9". SFAS No. 147 provided interpretive guidance on the
application of the purchase method to acquisitions of financial institutions.
The provisions of SFAS No. 147 are effective for acquisitions occurring or after
October 1, 2002. We did not participate in any applicable activities as of and
for the period ending December 31, 2002.
In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation--Transition and Disclosure", an amendment of FASB
Statement No. 123, "Accounting for Stock Based Compensation," ("SFAS No. 123"),
which provides alternative methods of transition for a voluntary change to the
fair value based method of accounting for stock-based employee compensation. In
addition, this Statement amends the disclosure requirements of Statement 123 to
require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based employee compensation and the
effect of the method used on reported results. The provisions of SFAS No. 148
are effective for fiscal years ending after December 15, 2002. As allowed by
SFAS No. 123, we have continued to apply APB Opinion No. 25 for purposes of
determining net income and to present the pro forma disclosure required by SFAS
No. 123.
We do not expect the adoption of any of the above-mentioned standards
to have a material effect on our consolidated financial statements.
HEDGING ACTIVITIES
In March 2002, we purchased a floor on 18,000 MMbtus per day at $2.65
per MMbtu for the period April 1, 2002 through June 30, 2002, at a cost of
$163,800. On August 22, 2002, we entered into a price swap on 5,000
37
MMbtus per day at $3.59 per MMbtu for the period September 1, 2002 through
December 31, 2002. On August 23, 2002, we entered into a second price swap on an
additional 5,000 MMbtus per day at $3.685 per MMbtu for the period September 1,
2002 through December 31, 2002.
In October 2002, we entered into a natural gas collar that covered
10,000 MMbtus per day for the period January 1, 2003 to December 31, 2003 at a
floor of $4.00 per MMbtu and a ceiling of $4.25 per MMbtu. At December 31, 2002,
the market value of outstanding hedges was approximately $(1.3) million and is
included in accrued liabilities.
Due to the instability of oil and natural gas prices, we have entered
into, from time to time, price risk management transactions (e.g., swaps,
collars and floors) for a portion of our oil and natural gas production to
achieve a more predictable cash flow, as well as to reduce exposure from price
fluctuations. While the use of these arrangements limits our ability to benefit
from increases in the price of oil and natural gas, it also reduces our
potential exposure to adverse price movements. Our hedging arrangements, to the
extent we enter into any, apply to only a portion of our production and provide
only partial price protection against declines in oil and natural gas prices and
limits our potential gains from future increases in prices. Our Board of
Directors sets all of our hedging policies, including volumes, types of
instruments and counter parties, on a quarterly basis. These policies are
implemented by management through the execution of trades by the Chief Financial
Officer after consultation and concurrence by the President and Chairman of the
Board. We account for these transactions as hedging activities and, accordingly,
realized gains and losses are included in oil and natural gas revenue during the
period the hedged transactions occur. See ITEMS 1 AND 2. - "Business and
Properties - Marketing."
TAX MATTERS
At December 31, 2002, we have cumulative net operating loss
carryforwards ("NOLs") for federal income tax purposes of approximately $27.4
million that will begin to expire in 2012. We anticipate that all of these NOLs
will be utilized in connection with federal income taxes payable in the future.
NOLs assume that certain items, primarily intangible drilling costs have been
written off for tax purposes in the current year. However, we have not made a
final determination if an election will be made to capitalize all or part of
these items for tax purposes in the future.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk from changes in interest rates and
commodity prices. We use a credit facility, which has a floating interest rate,
to finance a portion of our operations. We are not subject to fair value risk
resulting from changes in our floating interest rates. The use of floating rate
debt instruments provide a benefit due to downward interest rate movements but
does not limit us to exposure from future increases in interest rates. Based on
the year-end December 31, 2002 outstanding borrowings and a floating interest
rate of 3.88%, a 10% change in interest rate would result in an increase or
decrease of interest expense of approximately $75,900 on an annual basis.
In the normal course of business we enter into hedging transactions,
including commodity price collars, swaps and floors to mitigate our exposure to
commodity price movements, but not for trading or speculative purposes. During
October 2002, due to the instability of prices and to achieve a more predictable
cash flow, we put in place a natural gas collar for a portion of our 2003
production. While the use of these arrangements may limit the benefit to us of
increases in the price of oil and natural gas, it also limits the downside risk
of adverse price movements. The natural gas collar covers 10,000 MMbtu per day
for the period January 1, 2003 to December 31, 2003 at a floor of $4.00 per
MMbtu and ceiling of $4.25 per MMbtu. At December 31, 2002, the fair value of
the outstanding hedge was approximately $(1.3) million. A 10% change in the gas
price per MMbtu, as long as the price is either above the ceiling or below the
floor price would cause the fair value total of the hedge to increase or
decrease by approximately $1.7 million.
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.
38
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
As noted in the Company's Current Report on Form 8-K filed on July 18,
2002, the Company dismissed its independent accountant, Arthur Andersen LLP, and
engaged KPMG LLP as its new independent accountant and auditor. The decision to
engage KPMG LLP and dismiss Arthur Andersen LLP was recommended by the Audit
Committee and approved by the Board of Directors.
None of the reports of Arthur Andersen LLP on the financial statements
of the Company during their engagement contained an adverse opinion or was
qualified or modified as to uncertainty, audit scope or accounting principles.
Further, during the Company's fiscal year ended December 31, 2001 and for the
period from January 1, 2002 to July 18, 2002, there were no disagreements
between the Company and Arthur Andersen LLP on any matter of accounting
principles, or auditing scope or procedure, which disagreement, if not resolved
to the satisfaction of Arthur Andersen LLP, would have caused them to make
reference to the subject matter of the disagreements in connection with their
report on the financial statements for such years. There were no reportable
events (as defined in Regulation S-K, Item 304(a)(1)(v)) during the Company's
fiscal year ended December 31, 2001 and for the period from January 1, 2002 to
July 18, 2002. During the Company's fiscal year ended December 31, 2001 and for
the period from January 1, 2002 to July 18, 2002, the Company did not consult
with KPMG LLP regarding any of the matters or events set forth in Item
304(a)(2)(i) or (ii) of Regulation S-K.
Subsequent to the appointment of KPMG and prior to the issuance of
their 2002 report, the Company requested that KPMG perform a re-audit of
the Company's consolidated financial statements for the fiscal year ended
December 31, 2001. The re-audit was completed in March 2003, and KPMG's report
dated March 14, 2003, which includes the 2001 period in its scope and was
unmodified, is included herein.
As noted in the Company's Current Report on Form 8-K filed on October
10, 2001, on October 4, 2001, the Company dismissed its independent accountant,
Deloitte & Touche LLP, and engaged Arthur Andersen LLP as its new independent
accountant and auditor. The decision to engage Arthur Andersen, LLP and dismiss
Deloitte & Touche LLP was recommended by the Audit Committee and approved by the
Board of Directors.
None of the reports of Deloitte & Touche LLP on the financial
statements of the Company during their engagement contained an adverse opinion
or was qualified or modified as to uncertainty, audit scope or accounting
principles. Further, during the Company's fiscal year ended December 31, 2000
and for the period from January 1, 2001 to October 4, 2001, there were no
disagreements between the Company and Deloitte & Touche LLP on any matter of
accounting principles, or auditing scope or procedure, which disagreement, if
not resolved to the satisfaction of Deloitte & Touche LLP, would have caused
them to make reference to the subject matter of the disagreements in connection
with their report on the financial statements for such years. There were no
reportable events (as defined in Regulation S-K, Item 304(a)(1)(v)) during the
Company's fiscal year ended December 31, 2000 and for the period from January 1,
2001 to October 4, 2001. During the Company's fiscal year ended December 31,
2000 and for the period from January 1, 2001 to October 4, 2001, the Company did
not consult with Arthur Andersen LLP or KPMG LLP regarding any of the matters or
events set forth in Item 304(a)(2)(i) or (ii) of Regulation S-K.
39
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 for the
Company's 2003 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, 2002. Pursuant to
Item 401(b) of Regulation S-K certain of the information required by this item
with respect to executive officers of the Company is set forth in Part I of this
report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by ITEM 11 will be contained in the Proxy
Statement under the heading "Executive Compensation, Other Information and
Related Stockholder Matters" and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
The information required by ITEM 12 will be contained in the Proxy
Statement under the headings "Security Ownership of Management and Certain
Beneficial Owners" and "Equity Compensation Plan Information" 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.
ITEM 14. CONTROLS AND PROCEDURES
Within the 90 days prior to the date of this report, the Company
carried out an evaluation, under the supervision and with the participation of
the Company's management, including the Chief Executive Officer and Chief
Financial and Accounting Officer, of the effectiveness of the design and
operation of the Company's disclosure controls and procedures pursuant to
Exchange Act Rule 13a-14. Based on that evaluation, the Chief Executive Officer
and the Chief Financial and Accounting Officer concluded that the Company's
disclosure controls and procedures are effective in timely alerting them to
material information relating to the Company (including its consolidated
subsidiaries) required to be included in the Company's periodic filings with the
Securities and Exchange Commission. Subsequent to the date of their evaluation,
there were no significant changes in the Company's internal controls or in other
factors that could significantly affect the internal controls, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
40
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Financial Statements and Schedules:
1. Financial Statements: See Index to the Consolidated Financial Statements
and Supplementary Information immediately following the signature page of
this report.
2. Financial Statement Schedule: See Index to the Consolidated Financial
Statements and Supplementary Information immediately following the signature
page of this report.
3. Exhibits: The following documents are filed as exhibits to this report.
+2.1 -- Amended and Restated Combination Agreement by and among (i)
Edge Group II Limited Partnership, (ii) Gulfedge Limited
Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum
Corporation, (v) Edge Mergeco, Inc. and (vi) the Company,
dated as of January 13, 1997 (Incorporated by reference from
exhibit 2.1 to the Company's Registration Statement on Form
S-4 (Registration No. 333-17269)).
+3.1 -- Restated Certificate of Incorporated of the Company, as
amended (Incorporated by reference from exhibit 3.1 to the
Company's Registration Statement on Form S-4 (Registration No.
333-17269)).
+3.2 -- Bylaws of the Company (Incorporated by Reference from exhibit
3.3 to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 1999).
+3.3 -- First Amendment to Bylaws of the Company on September 28, 1999
(Incorporated by Reference from exhibit 3.2 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1999).
+4.1 -- Second Amended and Restated Credit Agreement dated October
6, 2000 by and between Edge Petroleum Corporation, Edge
Petroleum Exploration Company and Edge Petroleum Operating
Company, Inc. (collectively, the "Borrowers") and Union Bank
Of California, N.A., a national banking association, as Agent
for itself and as lender. (Incorporated by Reference from
exhibit 4.5 to the Company's Quarterly Report on Form 10-Q for
the quarterly period ended September 31, 2000).
+4.2 -- Amendment No. 1 and Waiver dated as of November 11, 2001 by
and among the lenders party to the Second Amended and Restated
Credit Agreement dated October 6, 2000 ("Lenders"), Union Bank
of California, N.A., a national banking association, as agent
for such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement. (Incorporated by
Reference from exhibit 4.2 to the Company's Annual Report on
Form 10K for the annual period ended December 31, 2001).
*4.3 -- Amendment No. 2 dated as of May 29, 2002 by and among the
lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for
such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement.
41
*4.4 -- Amendment No. 3 dated as of August 8, 2002 by and among the
lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for
such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement.
+4.5 -- Letter Agreement dated October 31, 2000 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company and
Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender.
(Incorporated by Reference from exhibit 4.6 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 31, 2000).
+4.6 -- Letter Agreement dated March 23, 2001 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company and
Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender.
(Incorporated by Reference from exhibit 4.5 to the Company's
Annual Report on Form 10K for the annual period ended December
31, 2000).
+4.7 -- Letter Agreement dated September 21, 2001 by and between
Edge Petroleum Corporation, Edge Petroleum Exploration Company
and Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender.
(Incorporated by Reference from exhibit 4.6 to the Company's
Quarterly Report on Form 10Q for the quarterly period ended
September 30, 2001).
+4.8 -- Letter Agreement dated January 18, 2002 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company and
Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender.
(Incorporated by Reference from exhibit 4.6 to the Company's
Annual Report on Form 10K for the annual period ended December
31, 2001).
+4.9 -- Letter Agreement dated August 9, 2002 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company and
Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender.
(Incorporated by Reference from exhibit 4.7 to the Company's
Quarterly Report on Form 10Q for the quarterly period ended
June 30, 2002).
+4.10 -- Common Stock Subscription Agreement dated as of April 30,
1999 between the Company and the purchasers named therein
(Incorporated by reference from exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q/A for the quarter ended March
31, 1999).
+4.11 -- Warrant Agreement dated as of May 6, 1999 between the Company
and the Warrant holders named therein (Incorporated by
reference from exhibit 4.5 to the Company's Quarterly Report
on Form 10-Q/A for the quarter ended March 31, 1999).
+4.12 -- Form of Warrant for the purchase of the Common Stock
(Incorporated by reference from the Common Stock Subscription
Agreement from exhibit 4.5 to the Company's Quarterly Report
on Form 10-Q/A for the quarter ended March 31, 1999).
+10.1 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership II, dated as of May 10, 1994
(Incorporated by reference from exhibit 10.2 to the Company's
Registration Statement on Form S-4 (Registration No.
333-17269)).
+10.2 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership, dated as of April 11, 1992
(Incorporated by reference from exhibit 10.3 to the Company's
Registration Statement on Form S-4 (Registration No.
333-17269)).
42
*10.2 -- Amendment dated August 21, 2000 to the Joint Venture
Agreement between Edge Joint Venture II and Essex Royalty
Limited Partnership II, dated as of May 10, 1994.
*10.3 -- Amendment dated August 21, 2000 to the Joint Venture
Agreement between Edge Joint Venture II and Essex Royalty
Limited Partnership, dated as of April 11, 1992.
*10.4 -- Letter Agreement between Edge Petroleum Corporation and Essex
Royalty Limited Partnership, dated as of July 30, 2002.
+10.5 -- 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)).
+10.6 -- Stock Option Plan of Edge Petroleum Corporation, a Texas
corporation (Incorporated by reference from exhibit 10.13 to
the Company's Registration on Form S-4 (Registration No.
333-17269)).
+10.7 -- Employment Agreement dated as of November 16, 1998, by and
between the Company John W. Elias. (Incorporated by reference
from 10.12 to the Company's Annual on Form 10-K for the year
ended December 31, 1998).
*10.8 -- Incentive Plan of Edge Petroleum Corporation as Amended and
Restated Effective as of February 20, 2003.
+10.9 -- Edge Petroleum Corporation Incentive Plan "Standard
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Officers named therein.
(Incorporated by reference from exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1999).
+10.10 -- Edge Petroleum Corporation Incentive Plan "Director
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Directors named therein.
(Incorporated by reference from exhibit 10.3 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1999).
+10.11 -- Form of Employee Restricted Stock Award Agreement under the
Incentive Plan of Edge Petroleum Corporation (Incorporated by
Reference from exhibit 10.15 to the Company's Quarterly Report
on Form 10-Q/A for the quarterly period ended March 31, 1999).
+10.12 -- Edge Petroleum Corporation Amended and Restated Elias Stock
Incentive Plan. (Incorporated by reference from exhibit 4.5
to the Company's Registration on Form S-8 filed May 30, 2001
(Registration No. 333-61890)).
+10.13 -- Form of Edge Petroleum Corporation John W. Elias Non-Qualified
Stock Option Agreement (Incorporated by reference from exhibit
4.6 to the Company's Registration Statement on Form S-8 filed
May 30, 2001 (Registration No. 333-61890)).
*21.1 -- Subsidiaries of the Company.
*23.1 -- Consent of KPMG LLP, independent auditors.
*23.2 -- Consent of Deloitte & Touche LLP.
*23.3 -- Consent of Ryder Scott Company.
*99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers as of December 31, 2002 (included as an appendix to
Form 10-K).
43
*99.2 -- Certification by John W. Elias, Chief Executive Officer,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title
18, United States Code).
*99.3 -- Certification by Michael G. Long , Chief Financial and
Accounting Officer, pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section
1350, Chapter 63 of Title 18, United States Code).
* Filed herewith.
+ Incorporated by reference as indicated.
(b) Reports on Form 8-K: The Company filed the following reports on Form 8-K
during the quarter ended December 31, 2002:
None.
44
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
EDGE PETROLEUM CORPORATION
/S/ John W. Elias
- ------------------------------
John W. Elias
Chief Executive Officer and
Chairman of the Board
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.
/S/ John W. Elias Date: March 27, 2003
- ------------------------------ ---------------------
John W. Elias
Chief Executive Officer and
Chairman of the Board
(Principal Executive Officer)
/S/ Michael G. Long Date: March 27, 2003
- ------------------------------ ---------------------
Michael G. Long
Senior Vice President and
Chief Financial Officer
(Principal Financial and
Principal Accounting Officer)
/S/ Thurmon Andress Date: March 27, 2003
- ------------------------------ ---------------------
Thurmon Andress
Director
/S/ Vincent Andrews Date: March 27, 2003
- ------------------------------ ---------------------
Vincent Andrews
Director
/S/ Joseph R. Musolino Date: March 27, 2003
- ------------------------------ ---------------------
Joseph R. Musolino
Director
Date:
- ------------------------------ ---------------------
Nils P. Peterson
Director
/S/ Stanley S. Raphael Date: March 27, 2003
- ------------------------------ ---------------------
Stanley S. Raphael
Director
/S/ John Sfondrini Date: March 27, 2003
- ------------------------------ ---------------------
John Sfondrini
Director
/S/ Robert W. Shower Date: March 27, 2003
- ------------------------------ ---------------------
Robert W. Shower
Director
/S/ David F. Work Date: March 27, 2003
- ------------------------------ ---------------------
David F. Work
Director
45
CERTIFICATIONS
Principal Executive Officer
I, John W. Elias, certify that:
1. I have reviewed this annual report on Form 10-K of Edge Petroleum
Corporation.
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
fulfilling the equivalent function);
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: March 27, 2003 /s/ John W. Elias
------------------------------------------
John W. Elias
President, Chief Executive Officer
and Chairman of the Board
Principal Financial and Accounting Officer
46
I, Michael G. Long, certify that:
1. I have reviewed this annual report on Form 10-K of Edge Petroleum
Corporation.
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this annual report (the "Evaluation Date");
and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons
fulfilling the equivalent function);
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
Date: March 27, 2003 /s/ Michael G. Long
-------------------------------------------
Michael G. Long
Senior Vice President and Chief Financial
and Accounting Officer
47
EDGE PETROLEUM CORPORATION
Index to Consolidated Financial Statements and Supplementary Information
CONSOLIDATED FINANCIAL STATEMENTS
Audited Financial Statements:
Independent Auditors' Report - 2002 and 2001 F-2
Independent Auditors' Report - 2000 F-3
Consolidated Balance Sheets as of December 31, 2002 and 2001 F-4
Consolidated Statements of Operations for the Years Ended
December 31, 2002, 2001 and 2000 F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2002, 2001 and 2000 F-6
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 2002, 2001 and 2000 F-7
Notes to Consolidated Financial Statements F-8
Unaudited Information:
Supplementary Information to Consolidated Financial Statements F-24
CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
Independent Auditors' Report on Consolidated Financial
Statement Schedule F-28
Schedule II - Valuation and Qualifying Accounts and Reserves F-29
All schedules for which provision is made in the applicable accounting
regulations of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable and therefore have been omitted.
F-1
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Stockholders
Edge Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of Edge Petroleum
Corporation and subsidiaries as of December 31, 2002 and 2001, and the related
consolidated statements of operations, cash flows and stockholders' equity for
each of the years in the two-year period ended December 31, 2002. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Edge Petroleum
Corporation and subsidiaries as of December 31, 2002 and 2001, and the results
of their operations and their cash flows for each of the years in the two-year
period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America.
As discussed in Note 2 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for derivative
instruments.
KPMG LLP
Houston, Texas
March 14, 2003
F-2
INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors,
Edge Petroleum Corporation
Houston, Texas
We have audited the accompanying consolidated statements of operations,
stockholders' equity, and cash flows of Edge Petroleum Corporation (a Delaware
Corporation) (the "Company") for the year ended December 31, 2000. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
materials respects, the Company's results of operations and cash flows for the
year ended December 31, 2000 in conformity with accounting principles generally
accepted in the United States of America.
/s/ Deloitte & Touche LLP
March 19, 2001
F-3
EDGE PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
- -------------------------------------------------------------------------------
DECEMBER 31,
-----------------------------------------
2002 2001
----------------- ----------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 2,568,176 $ 793,287
Accounts receivable, trade, net of allowance of $525,248 as of
December 31, 2002 and 2001 4,259,607 5,184,522
Accounts receivable, joint interest owners, net of allowance of
$82,000 and $163,000 as of December 31, 2002 and 2001, respectively 208,446 322,001
Current deferred tax asset 832,343 337,580
Other current assets 430,930 649,566
--------------- --------------
8,299,502 7,286,956
Total current assets
PROPERTY AND EQUIPMENT, Net - full cost method of accounting for oil and
natural gas properties 75,681,772 66,853,094
DEFERRED TAX ASSET 41,338 556,317
OTHER ASSETS -- 7,788
---------------- --------------
$ 84,022,612 $ 74,704,155
TOTAL ASSETS
================ ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade $ 1,533,972 $ 1,412,451
Accrued liabilities 2,033,802 5,192,440
Derivative financial instrument 1,293,840 --
Accrued interest payable 127,698 --
---------------- --------------
Total current liabilities 4,989,312 6,604,891
LONG-TERM DEBT 20,500,000 10,000,000
---------------- --------------
25,489,312 16,604,891
Total liabilities
---------------- --------------
COMMITMENTS AND CONTINGENCIES (Note 6)
STOCKHOLDERS' EQUITY
Preferred stock, $0.01 par value; 5,000,000 shares authorized; none
issued and outstanding -- --
Common stock, $0.01 par value; 25,000,000 shares authorized; 9,416,254
and 9,305,079 shares issued and outstanding at December 31, 2002 and
2001, respectively 94,163 93,051
Additional paid-in capital 56,663,626 56,139,451
Retained earnings 2,616,507 1,866,762
Accumulated other comprehensive loss (840,996) --
---------------- --------------
Total stockholders' equity 58,533,300 58,099,264
---------------- --------------
$ 84,022,612 $ 74,704,155
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
================== ==================
See accompanying notes to the consolidated financial statements.
F-4
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
- -------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
2002 2001 2000
------------------ ------------------ ------------------
$ 20,911,294 $ 29,810,917 $ 23,774,416
OIL AND NATURAL GAS REVENUE
OPERATING EXPENSES:
Oil and natural gas operating expenses including
production and ad valorem taxes 3,831,590 5,000,666 3,954,938
Depletion, depreciation and amortization 10,426,667 9,377,974 7,640,778
Litigation settlement -- 3,546,645 --
General and administrative expenses 4,826,793 5,038,050 3,824,385
Deferred compensation expense - restricted stock 399,249 353,371 127,946
Deferred compensation expense - repriced options 3,385 (850,281) 899,548
----------------- ---------------- ----------------
Total operating expenses 19,487,684 22,466,425 16,447,595
----------------- ---------------- ----------------
1,423,610 7,344,492 7,326,821
OPERATING INCOME
OTHER INCOME AND (EXPENSE):
Interest expense, net of amounts capitalized (227,759) (214,619) (171,783)
Interest income 26,954 127,717 97,860
Loss on sale of investment in Frontera -- -- (354,733)
----------------- ---------------- ----------------
1,222,805 7,257,590 6,898,165
INCOME BEFORE INCOME TAXES
INCOME TAX BENEFIT (EXPENSE) (473,060) 818,897 --
----------------- ---------------- ----------------
749,745 8,076,487 6,898,165
NET INCOME
OTHER COMPREHENSIVE INCOME:
Cumulative effect transition adjustment -- (1,137,221) --
Realization of hedging losses -- 937,120 --
Change in fair value of hedging instruments (840,996) 200,101 --
----------------- ---------------- ----------------
Other comprehensive income (loss) (840,996) -- --
----------------- ---------------- ----------------
COMPREHENSIVE INCOME (LOSS) $ (91,251) $ 8,076,487 $ 6,898,165
================= ================ ================
EARNINGS PER SHARE:
Basic earnings per share $ 0.08 $ 0.87 $ 0.75
================= ================ ================
Diluted earnings per share $ 0.08 $ 0.83 $ 0.74
================= ================ ================
BASIC WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING 9,384,097 9,280,605 9,182,737
================= ================ ================
DILUTED WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING 9,605,571 9,728,228 9,330,049
================= ================ ================
See accompanying notes to the consolidated financial statements.
F-5
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
2002 2001 2000
----------------- ---------------- ----------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 749,745 $ 8,076,487 $ 6,898,165
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization 10,426,667 9,377,974 7,640,778
Amortization of deferred loan costs 84,479 101,398 24,720
Deferred tax provision (benefit) 473,060 (818,897) --
Non-cash compensation expense 402,634 (496,910) 1,057,494
Bad debt expense -- 525,248 --
Loss on sale of investment in Frontera -- -- 354,733
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable, trade 924,915 3,043,101 (5,263,162)
Decrease in accounts receivable, joint interest owners 113,555 69,933 845,572
(Increase) decrease in other assets 141,945 (519,322) 40,791
Increase (decrease) in accounts payable, trade 121,521 135,011 (13,904)
Increase (decrease) in accrued interest payable 127,698 (50,385) 34,016
Increase (decrease) in accrued liabilities (3,158,638) 2,707,575 (1,973,616)
----------------- ---------------- ----------------
Net cash provided by operating activities 10,407,581 22,151,213 9,645,587
----------------- ---------------- ----------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase of prospects, property and equipment (19,609,639) (28,988,659) (10,717,839)
Proceeds from the sale of prospects and oil and natural
gas properties 354,294 -- 1,810,659
Proceeds from the sale of our investment in Frontera,
net -- -- 3,512,500
----------------- ---------------- ----------------
Net cash used in investing activities (19,255,345) (28,988,659) (5,394,680)
----------------- ---------------- ----------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Borrowings from long-term debt 11,000,000 11,000,000 5,350,000
Payments on long-term debt (500,000) (4,000,000) (9,150,000)
Net proceeds from issuance of common stock 122,653 390,421 --
Loan costs -- (7,669) (202,926)
----------------- ---------------- ----------------
Net cash provided by (used in) financing activities 10,622,653 7,382,752 (4,002,926)
----------------- ---------------- ----------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 1,774,889 545,306 247,981
CASH AND CASH EQUIVALENTS, BEGINNING OF YEAR 793,287 247,981 --
----------------- ---------------- ----------------
CASH AND CASH EQUIVALENTS, END OF YEAR $ 2,568,176 $ 793,287 $ 247,981
================= ================ ================
See accompanying notes to the consolidated financial statements.
F-6
EDGE PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
- -------------------------------------------------------------------------------
Accumulated Unearned
Additional Retained Other Compensation - Total
Paid-in Earnings Comprehensive Restricted Stockholders'
Shares Amount Capital (Deficit) Income (Loss) Stock Equity
--------- ---------- ------------- -------------- -------------- -------------- --------------
BALANCE, 9,182,023 $ 91,820 $ 55,223,901 $ (13,107,890) $ -- $ (34,224) $ 42,173,607
DECEMBER 31, 1999
Forfeitures of
restricted
common stock (5,600) (56) (11,472) -- -- 11,528 --
Issuance of
common stock 9,648 97 29,903 -- -- -- 30,000
Deferred
compensation
expense -
restricted stock -- -- 105,250 -- -- 22,696 127,946
Deferred
compensation
expense -
repriced options -- -- 899,548 -- -- -- 899,548
Net income -- -- -- 6,898,165 -- -- 6,898,165
--------- --------- ------------- -------------- -------------- -------------- -------------
BALANCE, 9,186,071 91,861 56,247,130 (6,209,725) -- -- 50,129,266
DECEMBER 31, 2000
Issuance of 119,008 1,190 389,231 -- -- -- 390,421
common stock
Deferred
compensation
expense -
restricted stock -- -- 353,371 -- -- -- 353,371
Deferred
compensation
expense -
repriced options -- -- (850,281) -- -- -- (850,281)
Transition
adjustment -- -- -- -- (1,137,221) -- (1,137,221)
Realization of
hedging loss -- -- -- -- 937,120 -- 937,120
Change in
valuation of
hedging
instruments -- -- -- -- 200,101 -- 200,101
Net income -- -- -- 8,076,487 -- -- 8,076,487
--------- --------- ------------- -------------- -------------- -------------- -------------
BALANCE, 9,305,079 93,051 56,139,451 1,866,762 -- -- 58,099,264
DECEMBER 31, 2001
Issuance of 111,175 1,112 121,541 -- -- -- 122,653
common stock
Deferred
compensation
expense -
restricted stock -- -- 399,249 -- -- -- 399,249
Deferred
compensation
expense -
repriced options -- -- 3,385 -- -- -- 3,385
Change in
valuation of
hedging
instruments -- -- -- -- (840,996) -- (840,996)
Net income -- -- -- 749,745 -- -- 749,745
--------- --------- ------------ -------------- ------------- ------------- -------------
BALANCE,
DECEMBER 31, 2002 9,416,254 $ 94,163 $ 56,663,626 $ 2,616,507 $ (840,996) $ -- $ 58,533,300
========= ========= ============ ============== ============= ============= =============
See accompanying notes to the consolidated financial statements.
F-7
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND NATURE OF OPERATIONS
GENERAL - Edge Petroleum Corporation (the "Company") was organized as a
Delaware corporation in August 1996 in connection with its initial public
offering and the related combination of certain entities that held interests in
Edge Joint Venture II (the "Joint Venture") and certain other oil and natural
gas properties; herein referred to as the "Combination". In a series of
combination transactions the Company issued an aggregate of 4,701,361 shares of
common stock and received in exchange 100% of the ownership interests in the
Joint Venture and certain other oil and natural gas properties. In March 1997,
and contemporaneously with the Combination, the Company completed the initial
public offering of 2,760,000 shares of its common stock (the "Offering")
generating proceeds of approximately $40 million, net of expenses.
NATURE OF OPERATIONS - The Company is an independent energy company engaged
in the exploration, development, acquisition and production of oil and natural
gas. The Company conducts its operations primarily along the onshore United
States Gulf Coast, with its primary emphasis in South Texas and Louisiana.
During 2001, the Company added a new focus area in the northern Rocky Mountains
that it expects to become a core area in 2003. The Company currently controls
interests in almost 160,000 gross acres held under lease or option. In its
exploration efforts the Company emphasizes an integrated geologic interpretation
method incorporating 3-D seismic technology and advanced visualization and data
analysis techniques utilizing state-of-the-art computer hardware and software.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements include
the accounts of all majority owned subsidiaries of the Company, including Edge
Petroleum Operating Company Inc., and Edge Petroleum Exploration Company, which
are 100% owned subsidiaries of the Company. All intercompany transactions have
been eliminated in consolidation.
REVENUE RECOGNITION - The Company recognizes oil and natural gas revenue
from its interests in producing wells as oil and natural gas is produced and
sold from those wells. Oil and natural gas sold by the Company is not
significantly different from the Company's share of production.
OIL AND NATURAL GAS PROPERTIES - Investments in oil and natural gas
properties are accounted for using the full cost method of accounting. All costs
associated with the exploration, development and acquisition of oil and natural
gas properties, including salaries, benefits and other internal costs directly
attributable to these activities, are capitalized within a cost center. The
Company's oil and natural gas properties are located within the United States of
America, which constitutes one cost center. The Company capitalized $1.5
million, $1.6 million, and $1.3 million of these internal costs in 2002, 2001
and 2000, respectively. Interest costs related to unproved properties are also
capitalized to unproved oil and gas properties. The Company capitalized
$623,400, $24,400, and $399,300 of these costs in 2002, 2001 and 2000,
respectively.
Oil and natural gas properties are amortized using the unit-of-production
method using estimates of proved reserve quantities. Investments in unproved
properties are not amortized until proved reserves associated with the prospects
can be determined or until impairment occurs. Unevaluated properties are
evaluated periodically for impairment on a property-by-property basis. If the
results of an assessment indicate that an unproved property is impaired, the
amount of impairment is added to the proved oil and natural gas property costs
to be amortized. The amortizable base includes estimated future development
costs and, where significant, dismantlement, restoration and abandonment costs,
net of estimated salvage values. The vast majority of our properties are
onshore, and historically the salvage value of the tangible equipment offsets
our site restoration and dismantlement and abandonment costs. The depletion
rates per Mcfe for the years ended December 31, 2002, 2001 and 2000 were $1.40,
$1.22, and $1.11, respectively.
Sales of proved and unproved properties are accounted for as adjustments of
capitalized costs with no gain or loss recognized, unless such adjustments would
significantly alter the relationship between capitalized costs and proved
reserves. Abandonments of oil and natural gas properties are accounted for as
adjustments of capitalized costs with no loss recognized.
F-8
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
In addition, the capitalized costs of oil and natural gas properties are
subject to a "ceiling test," whereby to the extent that such capitalized costs
subject to amortization in the full cost pool (net of depletion, depreciation
and amortization and related deferred taxes) exceed the present value (using 10%
discount rate) of estimated future net after-tax cash flows from proved oil and
natural gas reserves, such excess costs are charged to operations. Once
incurred, an impairment of oil and natural gas properties is not reversible at a
later date. Impairment of oil and natural gas properties is assessed on a
quarterly basis in conjunction with the Company's quarterly filings with the
Securities and Exchange Commission. No adjustment related to the ceiling test
was required during the years ended December 31, 2002, 2001, or 2000.
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 ("SFAS") No. 109 - "Accounting
for Income Taxes," which provides for an asset and liability approach for
accounting for income taxes. Under this approach, deferred tax assets and
liabilities are recognized based on anticipated future tax consequences, using
currently enacted tax laws, attributable to differences between financial
statement carrying amounts of assets and liabilities and their respective tax
bases (see Note 7).
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 - The Company sold its cost basis investment in
Frontera Resources Corporation in June 2000 for proceeds of $3.6 million and
paid related fees of $87,500 resulting in a loss on the sale of investment of
$354,733.
STOCK-BASED COMPENSATION - The Company accounts for stock compensation
plans under the intrinsic value method of Accounting Principles Board ("APB")
Opinion No. 25, "Accounting for Stock Issued to Employees." No compensation
expense is recognized for stock options that had an exercise price equal to the
market value of their underlying common stock on the date of grant. As allowed
by SFAS No. 123, "Accounting for Stock Based Compensation," the Company has
continued to apply APB Opinion No. 25 for purposes of determining net income. In
December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure - an amendment of FASB Statement No.
123" to provide alternative methods of transition for a voluntary change to the
fair value based method of accounting for stock-based employee compensation.
Additionally, the statement amends the disclosure requirements of SFAS No. 123
to require prominent disclosures in both annual and interim financial statements
about the method of accounting for stock-based compensation and the effect of
the method used on reported results.
Had compensation expense for stock-based compensation been determined based
on the fair value at the date of grant, our net income, earnings available to
common stockholders and earnings per share would have been reduced and the
stock-based compensation cost would have been increased to the pro forma amounts
indicated below:
Year Ended December 31,
----------------------------------------------------
2002 2001 2000
-------------- -------------- --------------
Net income as reported $ 749,745 $ 8,076,487 $ 6,898,165
Add:
Stock based employee compensation expense
included in reported net income, net of
related income tax 2,075 (899,104) 899,548
Deduct:
Total stock based employee compensation
expense determined under fair value
based method for all awards, net of related
income tax (261,927) (594,129) (584,316)
-------------- -------------- --------------
$ 489,893 $ 6,583,254 $ 7,213,397
Pro Forma Net Income
============== ============== ==============
Earnings Per Share
Basic - as reported $ 0.08 $ 0.87 $ 0.75
Basic - pro forma 0.05 0.71 0.79
Diluted - as reported $ 0.08 $ 0.83 $ 0.74
Diluted - pro forma 0.05 0.68 0.77
F-9
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The weighted-average fair value of options granted during 2002, 2001 and
2000 was $4.19, $6.76 and $2.43. The fair value of each option grant is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following weighted-average assumptions: expected stock price volatility of
77%, 80%, and 83% in 2002, 2001 and 2000, respectively; risk free interest of
3.82%, 5.42% and 5.12% in 2002, 2001 and 2000, respectively; average expected
option lives of eight years in 2002, 2001 and 2000, respectively; and a
forfeiture rate of 10% over the vesting period of such options.
The Company is also subject to reporting requirements of Financial
Accounting Standards Board ("FASB") Interpretation No. (FIN) 44, Accounting for
Certain Transactions involving Stock Compensation that requires a non-cash
charge to deferred compensation expense if the market price of the Company's
common stock at the end of a reporting period is greater that the exercise price
of certain stock options. After the first such adjustment is made, each
subsequent period is adjusted upward or downward to the extent that the market
price exceeds the exercise price of the options. The charge is related to
non-qualified stock options granted to employees and directors in prior years
and re-priced in May 1999, as well as certain options newly issued in
conjunction with the repricing (see Note 9).
EARNINGS PER SHARE - The Company accounts for its earnings per share in
accordance with SFAS No. 128 - "Earnings per Share," which establishes the
requirements for presenting earnings per share ("EPS"). SFAS No. 128 requires
the presentation of "basic" and "diluted" EPS on the face of the income
statement. Basic earnings per common share amounts are calculated using the
average number of common shares outstanding during each period. Diluted earnings
per share assumes the exercise of all stock options and warrants having exercise
prices less than the average market price of the common stock using the treasury
stock method (See Note 9).
FINANCIAL INSTRUMENTS - The Company's financial instruments consist of
cash, receivables, payables, long-term debt and oil and natural gas commodity
hedges. The carrying amount of cash, receivables and payables approximates fair
value because of the short-term nature of these items. The carrying amount of
long-term debt as of December 31, 2002 and 2001 approximates fair value because
the interest rates are variable and reflective of market rates. The fair value
of outstanding commodity sales price hedges was approximately $(1.3) million at
December 31, 2002. No hedges were outstanding at December 31, 2001.
DERIVATIVES AND HEDGING ACTIVITIES - Due to the instability of oil and
natural gas prices, the Company has entered into, from time to time, price risk
management transactions (e.g., swaps, collars and floors) for a portion of its
oil and natural gas production to achieve a more predictable cash flow, as well
as to reduce exposure from price fluctuations. While the use of these
arrangements limits the Company's ability to benefit from increases in the price
of oil and natural gas, it also reduces the Company's potential exposure to
adverse price movements. The Company's hedging arrangements, to the extent it
enters into any, apply to only a portion of its production and provide only
partial price protection against declines in oil and natural gas prices and
limits the Company's potential gains from future increases in prices. The
Company's Board of Directors sets all of the Company's hedging policies,
including volumes, types of instruments and counterparties, on a quarterly
basis. These policies are implemented by management through the execution of
trades by the Chief Financial Officer after consultation and concurrence by the
President and Chairman of the Board. The Company accounts for these transactions
as hedging activities and, accordingly, realized gains and losses are included
in oil and natural gas revenue during the period the hedged transactions occur
(see Note 5).
The Company adopted SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities" effective January 1, 2001. The statement, as amended by
SFAS No. 137 and SFAS No. 138, requires that all derivatives be recognized as
either assets or liabilities and measured at fair value, and changes in the fair
value of
F-10
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
derivatives be reported in current earnings, unless the derivative is designated
and effective as a hedge. If the intended use of the derivative is to hedge the
exposure to changes in the fair value of an asset, a liability or firm
commitment, then the changes in the fair value of the derivative instrument will
generally be offset in the income statement by the change in the item's fair
value. However, if the intended use of the derivative is to hedge the exposure
to variability in expected future cash flows then the changes in the fair value
of the derivative instrument will generally be reported in Other Comprehensive
Income (OCI). The gains and losses on the derivative instrument that are
reported in OCI will be reclassified to earnings in the period in which earnings
are impacted by the hedged item. The Company adopted SFAS No. 133 effective on
January 1, 2001, and recorded a transition adjustment of approximately $(1.1)
million in accumulated other comprehensive income to record the fair value of
the natural gas hedges that were outstanding at that date.
Upon entering into a derivative contract, the Company designates the
derivative instruments as a hedge of the variability of cash flow to be received
(cash flow hedge). In accordance with SFAS No. 133, the Company formally
documents all relationships between hedging instruments and hedged items, as
well as its risk management objectives and strategy for undertaking various
hedge transactions. The Company also formally assesses, both at the hedge's
inception and on an ongoing basis, the effectiveness of transactions that
receive hedge accounting. All of the Company's derivative instruments at
December 31, 2002 and 2001 were designated and effective as cash flow hedges.
When hedge accounting is discontinued because it is probable that a
forecasted transaction will not occur, the derivative will continue to be
carried on the balance sheet at its fair value and gains and losses that were
accumulated in other comprehensive income will be recognized in earnings
immediately. In all other situations in which hedge accounting is discontinued,
the derivative will be carried at fair value on the balance sheet with future
changes in its fair value recognized in earning prospectively.
At December 31, 2002, all unrealized hedging gains and losses had been
recognized in accumulated other comprehensive income and the fair value of
outstanding hedges were reflected in the consolidated balance sheet as
derivative financial instruments.
At December 31, 2002, we had recorded $0.9 million, net of related taxes of
$0.4 million, of cumulative hedging losses, which will be reclassified to
earnings within the next twelve months. The amounts ultimately reclassified to
earnings will vary due to changes in the fair value of the open derivative
instruments prior to settlement.
COMPREHENSIVE INCOME - The Company follows the provisions of SFAS No. 130,
"Reporting Comprehensive Income". SFAS No. 130 establishes standards for
reporting and presentation of comprehensive income and its components. SFAS No.
130 requires that all items that are required to be recognized under accounting
standards as components of comprehensive income be reported in a financial
statement that is displayed with the same prominence as other financial
statements. In accordance with the provisions of SFAS No. 130, the Company has
presented the components of comprehensive income below the total for net income
on the face of the Consolidated Statements of Operation. As of December 31,
2002, the Company had an unrealized loss from derivative hedging instruments of
$(840,996) that was deducted from net income to arrive at comprehensive loss of
$(91,251). For the years ended December 31, 2001 and 2000, there were no
adjustments to net income in deriving comprehensive income. The components of
other comprehensive income consist of unrealized and realized gain (loss) on
cash flow hedges, net.
USE OF ESTIMATES - The preparation of financial statements in conformity
with accounting principles generally accepted in the United States of America
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.
Significant estimates include volumes of oil and gas reserves used in
calculating depreciation, depletion and amortization of proved oil and natural
gas properties, future net revenues and abandonment obligations used in
computing the ceiling test limitations, impairment of undeveloped properties,
future income taxes and related assets/liabilities, bad debts, derivatives,
contingencies and litigation. Oil and natural gas reserve estimates, which are
F-11
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
the basis for unit-of-production depletion and the ceiling test, have numerous
inherent uncertainties. The accuracy of any reserve estimate is a function of
the quality of available data and of engineering and geological interpretation
and judgment. Results of drilling, testing, and production subsequent to the
date of the estimate may justify revision of such estimate. Accordingly,
reserves estimates are often different from the quantities of oil and natural
gas that are ultimately recovered. In addition, reserve estimates are vulnerable
to changes in wellhead prices of crude oil and natural gas. Such prices have
been volatile in the past and can be expected to be volatile in the future.
CONCENTRATION OF CREDIT RISK - Substantially all of the Company's
accounts receivable result from oil and natural gas sales or joint interest
billings to third parties in the oil and natural gas industry. This
concentration of customers and joint interest owners may impact the Company's
overall credit risk in that these entities may be similarly affected by changes
in economic and other conditions. Historically, the Company has not experienced
significant credit losses on such receivables; however, in 2001, the Company
reserved $525,248 related to non-payments from two purchasers of the Company's
oil and natural gas. No bad debt expense was recorded in 2002 or 2000. The
Company cannot ensure that similar such losses may not be realized in the
future.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS - In June 2001, the FASB issued
SFAS No. 142 , "Goodwill and Other Intangible Assets." SFAS No. 142 applies to
all acquired intangible assets whether acquired singly, as part of a group, or
in a business combination. The statement supersedes Accounting Principals Board,
("APB"), Opinion No. 17, "Intangible Assets," and carries forward provisions in
APB Opinion No. 17 related to internally developed intangible assets. Under this
statement, goodwill is no longer to be amortized but is subject to annual
impairment analysis. The Company adopted this statement as of January 1, 2002,
and the Company does not have any goodwill or intangible assets recorded as of
December 31, 2002.
In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." The statement requires entities to record the fair
value of a liability for legal obligations associated with the retirement of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of the
related long-lived asset. Accretion of the liability is recognized each period,
and the capitalized cost is depreciated over the useful life of the related
asset. Upon settlement of the liability, an entity either settles the obligation
for its recorded amount or incurs a gain or loss upon settlement. The standard
is effective for fiscal years beginning after June 15, 2002, therefore the
Company has adopted SFAS No. 143 effective January 1, 2003 using a cumulative
effect approach to recognize transition amounts for asset retirement
obligations, asset retirement costs and accumulated depreciation. The Company
currently does not include dismantlement and abandonment costs in the depletion
calculation as the vast majority of our properties are onshore and the salvage
value of the tangible equipment typically offsets our dismantlement and
abandonment costs. This standard will require the Company to record a liability
for the fair value of our dismantlement and abandonment costs, excluding salvage
values. The Company expects that its adoption of the statement will result in
additional liabilities related to asset retirement obligations of approximately
$1.1 million.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 addresses the
accounting and reporting for the impairment or disposal of long-lived assets and
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of" and APB Opinion No. 30, "Reporting the
Results of Operations -- Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions." SFAS No. 144 establishes one accounting model for long-lived
assets to be disposed of by sale as well as resolves implementation issues
related to SFAS No. 121. The standard also expands the scope of discontinued
operations to include all components of an entity with operations that can be
distinguished from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The Company adopted
SFAS No. 144 effective January 1, 2002. Because the Company has elected the
full-cost method of accounting for oil and gas exploration and development
activities, the impairment provisions of SFAS No. 144 do not apply to the
Company's oil and gas assets, which are instead subject to ceiling limitations.
For the Company's non-oil and gas assets, the adoption of SFAS No. 144 did not
have a material impact on the consolidated financial statements.
In April 2002, the FASB issued SFAS No. 145, "Recission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections". This statement rescinds SFAS No. 4, Reporting Gains and Losses
from Extinguishment of Debt, which required all gains and losses from
extinguishment of debt to be aggregated and, if material, classified as an
extraordinary item, net of income taxes. As a result, the criteria in APB
F-12
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
No. 30 will now be used to classify those gains and losses. Any gain or loss on
the extinguishment of debt that was classified as an extraordinary item in prior
periods presented that does not meet the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this Statement
are effective for fiscal years beginning after January 1, 2003. The Company does
not expect that adoption of this statement will have a material impact on the
Company's future financial condition or results of operations.
In June 2002, the FASB issued SFAS No. 146, "Accounting for Exit or
Disposal Activities". SFAS No. 146 addresses significant issues regarding the
recognition, measurement and reporting of disposal activities, including
restructuring activities that are currently covered in EITF Issue No. 94-3,
"Liability Recognition for Certain Employee Termination Activity." The
provisions of SFAS No. 146 are effective for exit or disposal activities
initiated after December 31, 2002.
The Company does not expect the adoption of any of the above-mentioned
standards to have a material effect on our consolidated financial statements.
RECLASSIFICATIONS - Certain prior year balances have been reclassified to
conform to the current year presentation.
3. PROPERTY AND EQUIPMENT
At December 31, 2002 and 2001, property and equipment consisted of the
following:
DECEMBER 31,
------------------------------------------
2002 2001
------------------- -------------------
Developed oil and natural gas properties $ 125,640,971 $ 101,303,892
Unevaluated oil and natural gas properties 7,901,315 13,105,817
Computer equipment and software 4,067,405 4,035,598
Other office property and equipment 1,509,095 1,428,728
------------------- -------------------
Total property and equipment 139,118,786 119,874,035
Accumulated depletion, depreciation and amortization (63,437,014) (53,020,941)
------------------- -------------------
Property and equipment, net $ 75,681,772 $ 66,853,094
=================== ==================
The Company uses the full-cost method of accounting for its oil and
natural gas properties. Unevaluated oil and natural gas properties are not
subject to amortization and consist of the cost of unevaluated leaseholds, cost
of seismic data, exploratory and developmental wells in progress, and secondary
recovery projects before the assignment of proved reserves. These costs are
reviewed periodically by management for impairment, with any costs impaired
added to the cost of oil and natural gas properties subject to amortization.
Factors considered by management in its impairment assessment include drilling
results by the Company and other operators, the terms of oil and natural gas
leases not held by production, production response to secondary recovery
activities and available funds for exploration and development.
The following table summarizes the cost of the properties not subject to
amortization for the year the cost was incurred:
DECEMBER 31,
----------------------------------------
2002 2001
------------------ ----------------
Year cost incurred:
1997 $ -- $ 213,216
1998 -- 3,152,756
1999 193,060 1,264,424
2000 1,126,667 2,441,465
2001 3,069,611 6,033,956
2002 3,511,977 --
------------------ ----------------
Total $ 7,901,315 $ 13,105,817
================== ================
F-13
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Under the full-cost method, a sale of oil and natural gas properties,
whether or not being amortized currently, is accounted for as an adjustment of
capitalized costs, with no gain or loss recognized unless such adjustment would
significantly alter the relationship between capitalized costs and proved
reserves.
4. LONG-TERM DEBT
In October 2000, the Company entered into a new credit facility (the
"Credit Facility") with a bank. Borrowings under the Credit Facility bear
interest at a rate equal to prime plus 0.50% or LIBOR plus 2.75%. As of December
31, 2002, $20.5 million in borrowings were outstanding under the Credit
Facility, none of which is due in 2003. The Credit Facility matures October 6,
2004 and is secured by substantially all of the Company's assets.
Originally the borrowing base under the Credit Facility was $5 million
and was subject to automatic reductions at a rate of $300,000 per month
beginning October 31, 2000. In March 2001, the Credit Facility was amended to
increase the borrowing base to $14 million, and to eliminate the $300,000 per
month automatic reduction. In January 2002, the borrowing base was increased to
$18 million. In August 2002, the borrowing base was increased to $25 million.
The borrowing base is expected to be redetermined in the first half of 2003.
The Credit Facility provides for certain restrictions, including but
not limited to, limitations on additional borrowings and issues of capital
stock, sales of oil and natural gas properties or other collateral, and engaging
in merger or consolidation transactions. The Credit Facility also prohibits
dividends and certain distributions of cash or properties and certain liens. The
Credit Facility also contains certain financial covenants. The EBITDA to
Interest Expense Ratio requires that (a) consolidated EBITDA, as defined in the
agreement, of the Company for the four fiscal quarters then ended to (b) the
consolidated interest expense of the Company for the four fiscal quarters then
ended, not be less than 3.5 to 1.0. The Working Capital ratio requires that the
amount of the Company's consolidated current assets less its consolidated
current liabilities, as defined in the agreement, be at least $1.0 million. The
Allowable Expenses ratio requires that (a) the aggregate amount of the Company's
year to date consolidated general and administrative expenses for the period
from January 1 of such year through the fiscal quarter then ended to (b) the
Company's year to date consolidated oil and gas revenues, net of hedging
activity, for the period from January 1 of such year through the fiscal quarter
then ended, be less than 0.40 to 1.0. At December 31, 2002, the Company was in
compliance with the above-mentioned covenants.
5. HEDGING ACTIVITIES
The impact on oil and natural gas revenue from hedging activities for
the three years ended December 31, 2002, 2001 and 2000 was as follows:
Realized Hedging Losses
Effective Dates Price MMBtu For the Year Ended December 31,
Hedge ---------------- Per Per ---------------------------------------
Type Beg. Ending MMBtu Day 2002 2001 2000
- ------------------ ---------------- --------- -------- --------- ---------- ----------
NATURAL GAS:
$ 2.20-
Collar 02/01/00 02/29/00 $ 2.31 6,000 $ -- $ -- $ (70,470)
$ 2.20-
Collar 03/01/00 04/30/00 $ 2.50 6,000 -- -- (135,900)
$ 2.05-
Collar 05/01/00 09/30/00 $ 2.63 9,000 -- -- (1,342,320)
$ 4.50-
Collar 01/01/01 12/31/01 $ 6.70 4,000 -- (937,120) --
Put Option 04/01/02 06/30/02 $ 2.65 18,000 (163,800) -- --
Swap 09/01/02 12/31/02 $ 3.59 5,000 (110,550) -- --
Swap 09/01/02 12/31/02 $ 3.69 5,000 (52,600) -- --
------------- --------- -----------
Total realized losses from gas hedging activities $ (326,950) $(937,120) $(1,548,690)
============= ========= ===========
F-14
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
Realized Hedging Losses
Effective Dates Price Barrels For the Year Ended December 31,
Hedge ---------------- Per Per ---------------------------------------
Type Beg. Ending Barrel Day 2002 2001 2000
- ------------------ ---------------- --------- -------- --------- ---------- ----------
OIL:
Swap 01/01/00 03/31/00 $ 25.60 150 $ -- $ -- $ (49,999)
04/01/00 06/30/00 $ 22.87 125 -- -- (65,478)
07/01/00 09/30/00 $ 21.47 60 -- -- (55,635)
10/01/00 12/31/00 $ 20.46 50 -- -- (52,342)
--------- --------- ----------
Total realized losses from oil hedging activities $ -- $ -- $ (223,454)
========= ========= ==========
The Company's natural gas hedging activities are entered into on a per
MMbtu delivered price basis, Houston Ship Channel, with settlement for each
calendar month occurring five business days following the publishing of the
Inside F.E.R.C. Gas Marketing Report.
In October 2002, the Company entered into a natural gas collar
covering 10,000 MMbtu per day for the period January 1, 2003 to December 31,
2003 with a floor of $4.00 per MMbtu and a ceiling of $4.25 per MMbtu. At
December 31, 2002 and 2000, the fair value of outstanding hedges was
approximately $(1.3) and $(1.1) million, respectively. No hedges were
outstanding at December 31, 2001.
6. COMMITMENTS AND CONTINGENCIES
From time to time the Company is a party to various legal proceedings
arising in the ordinary course of business. While the outcome of lawsuits cannot
be predicted with certainty, the Company is not currently a party to any
proceeding that it believes, if determined in a manner adverse to the Company,
could have a potential material adverse effect on its financial condition,
results of operations or cash flows.
In October 2001, the Company was sued by certain mineral owners in its
Mew lease, upon which the Company and its partners drilled and completed the Mew
No. 1 well in the Brandon Area, Duval County, Texas. The suit named the Company,
Santos USA and Mark Smith, an independent landman, as Defendants, and is filed
in the 229th Judicial District Court of Duval County, Texas. The suit sought a
declaratory judgment to set aside certain quitclaim deeds between the Mew
lessors that were intended to result in a partition of the mineral estate
between the various members of the Mew family in the land where the well is
located and other lands. The pleadings alleged failure of consideration, fraud,
failure to consummate the partition, bad faith trespass and conversion. As part
of the leasing effort for the prospect, some members of the Mew family had
sought to partition their minerals under the tracts where they owned the surface
in full. The Mew heirs, from whom the Company acquired leases, stood to lose a
portion of their mineral interest if the quitclaim deeds are set aside. Were
this to happen, it could have the effect of voiding the Company's leases as to
an undivided one-third of the unit acreage for the Mew well and the Mew lease.
Plaintiffs sought unspecified actual and exemplary damages against the Company
and Santos arising out of the alleged fraud committed by the Company and Mark
Smith. They also sought damages from Santos for the value of the oil and natural
gas produced and saved from the Mew well, or alternatively, for the value of the
oil and natural gas produced less the cost of drilling, completing and operating
the well. The Company has a 12.5% working interest in the well. To date, the Mew
well has produced $5.7 million in net revenue and has cost $3.6 million to
drill, complete and operate. Estimated gross proved reserves are 111.6 MBbls and
4.6 Bcf. In October 2002, the Company reached a mediated settlement with all
parties to the litigation whereby Edge would make a one-time payment of $264,000
to the Mews, and in return, the Mews released all claims except a potential
drainage claim involving an offsetting section, and agreed to grant a new oil
and gas lease covering the disputed mineral interest in the Mew well site tract.
In addition, all claims as between the working interest owners were released.
The settlement has been consummated and an order of dismal has been obtained
from the Court.
In July 2001, the Company was notified of a prior lease in favor of a
predecessor of ExxonMobil purporting to be valid and covering the same property
as the Company's Neblett lease in Starr County, Texas. The Neblett lease is part
of a unit in the N. LaCopita Prospect in which the Company owns a non-operating
interest. The operator of the lease, GMT, filed a petition for, and was granted,
a temporary restraining order against ExxonMobil
F-15
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
in the 229th Judicial Court in Starr County, Texas enjoining ExxonMobil from
taking possession of the Neblett wells. Pending resolution of the underlying
title issue, the temporary restraining order was extended voluntarily by
agreement of the parties, conditioned on GMT paying the revenues into escrow and
agreeing to provide ExxonMobil with certain discovery materials in this action.
ExxonMobil filed a counterclaim against GMT and all the non-operators, including
the Company, to establish the validity of their lease, remove cloud on title,
quiet title to the property, and for conversion, trespass and punitive damages.
ExxonMobil sought unspecified damages for the lost profits on the sale of the
hydrocarbons from this property, and for a determination of whether the Company
and the other working interest owners were in good faith or bad faith in
trespassing on this lease. If a determination of bad faith were made, the
parties would not be able to recover their costs of developing this property
from the revenues therefrom. While there is always a risk in the outcome of the
litigation, the Company believes there is no question that it acted in good
faith and vigorously defended its position. In February 2003, the Company, GMT
and the other working interest parties entered into a compromise and settlement
agreement with Exxon and Mrs. Neblett. Pursuant to the settlement, the Neblett
wells have been assigned to Exxon along with all operating responsibility, and
all working interest parties, including the Company, have been made whole for
all out of pocket costs incurred in drilling, completing, equipping and
operating the Neblett wells, including lease costs and royalty payments. The
Company's share of such reimbursed costs was $27,198. In addition, Mrs. Neblett
will repay the amount of the lease bonus and all royalty overpayments she
received from GMT and the other working interest parties, including the Company.
Such payment is secured by her future royalty interest payments in the wells,
and other security described in the settlement agreement, and is due in full on
or before December 1, 2003. The Company's share of such lease bonus and royalty
reimbursements is $74,040. The parties have agreed to a dismissal of all claims
in this case, and a motion to dismiss with prejudice has been filed with the
court.
In a separate but related matter, certain nonparticipating royalty
owners represented by attorney John Mann in Laredo, have made demands on GMT as
operator, to pay certain royalty payments previously paid to Mrs. Neblett on
production from these wells, plus future royalty payments on such production. As
part of the settlement agreement, monies that were otherwise payable to Mrs.
Neblett attributable to her valid royalty interest under the ExxonMobil lease,
subject to execution of valid division orders and approval of their title, will
be paid to the Mann clients on account of their nonparticipating royalty
interest. There are other nonparticipating royalty owners similarly situated to
the Mann clients that have not made demands on GMT or the Company, whose claims,
if any, will be dealt with if and when they are made. There can be no guarantee
that even when the Mann clients are paid that they will not contest the amount
or calculation of the royalties in a separate lawsuit.
In December 2001, the Company agreed to settle its litigation with BNP
Petroleum Corporation ("BNP"), Seiskin Interests, LTD, Pagenergy Company, LLC
and Gap Marketing Company, LLC. Pursuant to the settlement, the Company agreed
to pay $2.5 million and to release its claims to interest in an area known as
the Slick Prospect in Duval County, Texas. The parties to the settlement agreed
to the dismissal of all claims, both in the 229th Judicial District Court of
Duval County, Texas and in the 165th District Court in Harris County, Texas. The
parties also agreed to set aside the judgment of the 229th Judicial District
Court of Duval County, Texas against the Company and to a mutual release of all
claims. The Company recorded approximately $3.5 million paid to settle the
litigation including approximately $1.0 million in related legal costs in 2001
and reflected such total amount in the accompanying statement of operations as
litigation settlement.
Additionally, the Company's operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. Public interest in the
protection of the environment has increased dramatically in recent years. The
trend of more expansive and stricter environmental legislation and regulations
could continue. To the extent laws are enacted or other governmental action is
taken that restricts drilling or imposes environmental protection requirements
that result in increased costs to the oil and natural gas industry in general,
the business and prospects of the Company could be adversely affected.
At December 31, 2002, the Company was obligated under noncancelable
operating leases. Following is a schedule of the remaining future minimum lease
payments under these leases:
F-16
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
2003 $ 237,635
2004 419,814
2005 418,809
2006 410,644
Remainder 2,770,524
------------
Total $ 4,257,426
============
Rent expense for the years ended December 31, 2002, 2001 and 2000 was
$566,663, $578,952, and $499,033, respectively.
7. INCOME TAXES
Deferred income taxes reflect the tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts calculated for income tax purposes in accordance with
SFAS No. 109. Significant components of the Company's deferred tax liabilities
and assets as of December 31, 2002 and 2001 are as follows:
DECEMBER 31,
--------------------------------------
2002 2001
----------------- -----------------
Deferred tax liability:
Book basis of oil and natural gas properties in
excess of tax basis $ (9,636,351) $ (6,119,041)
Deferred tax asset:
Expenses not currently deductible for tax
purposes 26,250 221,550
Net operating loss carryforwards 9,602,689 6,353,358
Deferred compensation 112,362 122,143
Federal alternative minimum tax credits 75,000 75,000
Price risk management liability 452,844 --
Other 240,887 240,887
--------------- ---------------
Total deferred tax asset 10,510,032 7,012,938
--------------- ---------------
Net deferred tax asset $ 873,681 $ 893,897
=============== ===============
The Company's provision (benefit) for income taxes consists of the
following:
2002 2001 2000
--------------- --------------- --------------
Current $ -- $ 75,000 $ --
Deferred 473,060 (893,897) --
-------------- -------------- --------------
Total income tax benefit $ 473,060 $ (818,897) $ --
============== ============== ==============
During 2001, the Company determined that it was more likely than not
that future taxable income would be sufficient to realize its recorded tax
assets, accordingly a valuation allowance totaling $3.2 million was reversed.
The differences between the statutory federal income taxes calculated
using a federal tax rate of 35% and the Company's effective tax rate is
summarized as follows:
2002 2001 2000
--------------- --------------- ---------------
Statutory federal income taxes $ 427,982 $ 2,540,157 $ 2,414,358
Non-deductible compensation expense (7,545) (175,802) 1,223,424
Other expenses not deductible for tax
purposes 52,623 43,338 12,216
Reduction in valuation allowance -- (3,226,590) (3,649,998)
--------------- --------------- ---------------
Income tax expense (benefit) $ 473,060 $ (818,897) $ --
================ =============== ===============
F-17
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
At December 31, 2002, the Company had cumulative net operating loss
carryforwards ("NOLs") for federal income tax purposes of approximately $27.4
million that will begin to expire in 2012. The Company anticipates that all of
these NOLs will be utilized in connection with federal income taxes payable in
the future. NOLs assume that certain items, primarily intangible drilling costs,
have been written off for tax purposes in the current year. However, the Company
has not made a final determination if an election will be made to capitalize all
or part of these items for tax purposes in the future.
8. EMPLOYEE BENEFIT PLANS
Effective July 1, 1997, the Company established a defined-contribution
401(k) Savings & Profit Sharing Plan Trust (the "Plan") covering employees of
the Company who are age 21 or older. The Company's matching contributions to the
Plan are discretionary. For the years ended December 31, 2002, 2001 and 2000,
the Company contributed $83,223, $60,516, and $53,926, respectively, to the
Plan.
9. EQUITY AND STOCK PLANS
Private Offering - On May 6, 1999, the Company completed a private
offering of 1,400,000 shares of common stock at a price of $5.40 per share. The
Company also issued warrants, which were purchased for $0.125 per warrant, to
acquire an additional 420,000 shares of common stock at $5.35 per share and are
exercisable through May 6, 2004. At the election of the Company, the warrants
may be called at a redemption price of $0.01 per warrant at any time after any
date at which the average daily per share closing bid price for the immediately
preceding 20 consecutive trading days exceeds $10.70. No warrants have been
exercised as of December 31, 2002.
Stock Plan - In conjunction with the Offering, the Company established
the Incentive Plan of Edge Petroleum Corporation (the "Incentive Plan"). The
Incentive Plan is discretionary and provides for the granting of awards,
including options for the purchase of the Company's common stock and for the
issuance of restricted and/or unrestricted common stock to directors, officers,
employees and independent contractors of the Company. The options and restricted
stock granted to date vest over periods of 2-10 years. An aggregate of 1,200,000
shares of common stock have been reserved for grants under the Incentive Plan,
of which 175,866 shares were available for future grants at December 31, 2002.
Shares of common stock awarded as restricted stock are subject to vesting
requirements and subject to risk of forfeiture until earned by continued
employment or service. During 2002, awards of 199,800 nonqualified stock options
were issued having an exercise price of $3.40 to $5.69 per share based on the
market value on the date of grant. Also during 2002, awards for 15,800 shares of
restricted stock were made having a value in the range of $3.40 to $5.21 per
share based on the market value on each award date. During 2001, awards for
100,800 shares of restricted stock were made having a value in the range of
$4.58 to $8.88 per share based on the market value on each award date. Shares of
common stock associated with these awards will be issued, subject to continued
employment, ratably over three years in accordance with the award's vesting
schedule, beginning on the first anniversary of the date of grant. Compensation
expense is amortized over the vesting period and offset to additional paid in
capital. Amortization of deferred compensation related to restricted stock
awards totaled $399,249, $353,371 and $127,946, respectively, for the years
ended December 31, 2002, 2001 and 2000.
Effective May 21, 1999, the Company amended and restated the Incentive
Plan. In conjunction with those and other amendments of the Incentive Plan, the
Company exchanged, on a voluntary basis, 556,488 outstanding nonqualified stock
options of certain employees and Directors of the Company for 326,700 new common
stock options in replacement of those options. The exercise price of the
replacement options was $7.06 per share, which represents the fair market value
on the date of grant. The replaced options have a ten-year term with 50% of the
options vesting immediately on the date of grant with the remaining 50% vesting
on May 21, 2000. On May 21, 1999, in conjunction with the repricing, the Company
also issued 99,800 new ten-year common stock options to employees, which vested
100% on May 21, 2001. The exercise price of the new options was $7.06, which
represents the fair market value on the date of grant. On June 1, 1999, the
Company issued 21,000 ten-year
F-18
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
common stock options to non-employee directors with an exercise price of $7.28
per share, which represented their fair market value at the date of grant,
vesting 100% on June 1, 2001.
Deferred compensation cost reported in accordance with FASB
Interpretation No. (FIN) 44, "Accounting for Certain Transactions involving
Stock Compensation" was a charge of $3,385 for the year ended December 31, 2002
compared to a credit of $(850,281), or $(0.09) per share in 2001 and a charge of
$899,548, or $0.10 per share, in 2000. FIN 44 requires, among other things, a
non-cash charge to compensation expense if the market price of Edge's common
stock at the end of a reporting period is greater than the exercise price of
certain options. FIN 44 could also result in a credit to compensation expense to
the extent that the trading price declines from the market price as of the end
of the prior period, but not below the exercise price of the options. The
Company will adjust deferred compensation expense upward or downward on a
monthly basis, based on the market price at the end of each such period as
necessary to comply with FIN 44. We are required to report under this rule as a
result of the replacement and issuance of new options in conjunction with the
repricing as discussed above.
Effective January 8, 1999, as a component of his employment agreement
with the Company, John Elias, CEO and Chairman of the Board, was granted options
outside of the Incentive Plan for the purchase of 200,000 shares of common
stock. These options vest and become exercisable one-third upon issue, and
one-third upon each of January 1, 2000 and January 1, 2001. These amounts are
included within options granted for 1999. In January 2000, Mr. Elias was granted
additional options outside of the Incentive Plan for the purchase of 50,000
shares of common stock. These options vested and became 100% exercisable in
January 2002. In January 2001, Mr. Elias was granted additional options outside
the Incentive Plan for the purchase of another 50,000 shares of common stock.
These options vest and become 100% exercisable in January 2003. In January 2002,
Mr. Elias was granted additional options outside the Incentive Plan for the
purchase of another 50,000 shares of common stock that vest and become 100%
exercisable in January 2004. In April 2002, Mr. Elias was granted additional
options outside the Incentive Plan for the purchase of another 24,000 shares of
common stock. These options vest and become 100% exercisable in April 2004. In
April 2001, Mr. Elias was granted 14,000 shares of restricted stock outside the
Incentive Plan valued at $7.75 per share, the market value on the award date.
These shares are issued ratable over three years in accordance with the award's
vesting schedule, beginning on the first anniversary of the date of grant.
Compensation expense is amortized over the vesting period and offset to
additional paid in capital. The amortization of compensation expense related to
this award was included in the amounts discussed above. Below is a summary of
option and restricted stock grants to Mr. Elias:
SHARES EXERCISE
DATE GRANTED OUTSTANDING PRICE DATE EXERCISABLE
- --------------------------------------------------------------------------------
OPTIONS (1):
5/21/1999 200,000 $ 4.22 One-third upon issue and
one-third upon each
of January 1, 2000 and 2001
1/3/2000 50,000 $ 3.16 100% January 2002
1/3/2001 50,000 $ 8.88 100% January 2003
1/3/2002 50,000 $ 5.18 100% January 2004
4/2/2002 24,000 $ 5.59 100% April 2004
RESTRICTED STOCK (2):
4/2/2001 14,000 Ratable over three years
beginning on the first
anniversary of the date of
grant
(1) Exercise price equals the fair market value on the date of grant.
(2) Value was $7.75 per share, the market value on the date of grant.
In addition, as of the date of the Combination, Old Edge had in place a
stock incentive plan that was administered by non-employee members of the Board
of Directors of Old Edge. Prior to the Combination, two executives of the
Company each held outstanding options for the purchase of 2,193 shares of Old
Edge common stock granted under the Old Edge incentive plan. Upon completion of
the Combination, such options were converted into incentive stock options for
the purchase of an aggregate of 97,844 (48,922 for each of the two
F-19
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
individuals) shares of common stock of the Company (such number of shares of
common stock as would have existed if such options had been exercised
immediately prior to the Combination Transactions). After adjustment for the
conversion, the option price per share of common stock for each of the two
48,922 grants was approximately $4.09 and $2.04, respectively. Options for the
purchase of 48,922 shares of common stock were exercised during 1997. The
remaining options to purchase 48,922 shares of common stock were exercised
during 2001.
A summary of the status of the Company's stock options and changes as
of and for each of the three years ended December 31, 2002 is presented below:
2002 2001 2000
---------------------------- --------------------------- ----------------------------
SHARES WEIGHTED SHARES WEIGHTED SHARES WEIGHTED
AVERAGE AVERAGE AVERAGE
EXERCISE EXERCISE EXERCISE
PRICE PRICE PRICE
----------- ----------- ---------- ----------- ------------ -----------
Outstanding, January 1 866,200 $5.62 993,517 $6.76 818,567 $7.74
Granted 273,800 $5.46 92,200 $8.49 284,100 $3.36
Purchased -- (133,645) $16.50 --
Forfeited (24,650) $5.70 (10,000) $3.66 (109,150) $5.20
Exercised (17,300) $3.01 (75,872) $5.15 --
----------- ----------- ---------- ----------- ------------ -----------
Outstanding, December 31 1,098,050 $5.62 866,200 $5.62 993,517 $6.76
=========== ========== ============
Exercisable, December 31, 752,050 $5.34 574,200 $6.07 626,651 $8.24
=========== ========== ============
Weighted average fair value
of options granted during
the period $4.19 $6.76 $2.43
=========== ========== ============
The Company purchased 133,645 options from a former employee at a cost
of $100,000 that was included in general and administrative costs for the year
ended December 31, 2001.
A summary of the Company's stock options categorized by class of grant
at December 31, 2002 is presented below:
All Options Options Exercisable
- ----------------------------------------------------------------- ---------------------------------------------
Weighted
Average Weighted Weighted
Remaining Average Range of Average
Range of Shares Contractual Exercise Exercise Shares Exercise
Exercise Price Outstanding Life Price Price Outstanding Price
- --------------- ----------- ------------ ---------- -------------- ------------ -----------
$2.11 - $6.44 185,700 7.20 $3.08 $2.11 - $6.44 182,300 $ 3.06
$4.22 200,000 6.02 $4.22 $4.22 200,000 $ 4.22
$8.56 - $8.88 66,000 8.02 $8.87 -- -- --
$7.06 - $7.58 384,650 6.39 $7.09 $7.06 - $7.28 369,650 $ 7.07
$5.18 - $5.69 261,600 9.21 $5.50
$13.50 100 4.98 $13.50 $13.50 100 $ 13.50
Computation of Earnings per Share - The following is presented as a
reconciliation of the numerators and denominators of basic and diluted earnings
per share computations, in accordance with SFAS No. 128.
F-20
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
YEAR ENDED DECEMBER 31, 2002
-----------------------------------------------------
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
-------------- ---------------- -------------
BASIC EPS
Income available to common stockholders $ 749,745 9,384,097 $ 0.08
EFFECT OF DILUTIVE SECURITIES
Common stock options -- 85,633 (0.00)
Restricted stock -- 135,841 (0.00)
-------------- ---------------- -------------
DILUTED EPS
Income available to common stockholders $ 749,745 9,605,571 $ 0.08
============== ================ ============
YEAR ENDED DECEMBER 31, 2001
-----------------------------------------------------
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
-------------- ---------------- -------------
BASIC EPS
Income available to common stockholders $ 8,076,487 9,280,605 $ 0.87
EFFECT OF DILUTIVE SECURITIES
Common stock options -- 185,177 (0.02)
Restricted stock -- 178,238 (0.02)
Warrants -- 84,208 --
-------------- ---------------- -------------
DILUTED EPS
Income available to common stockholders $ 8,076,487 9,728,228 $ 0.83
============== ================ ============
YEAR ENDED DECEMBER 31, 2000
-----------------------------------------------------
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
--------------- ----------------- -------------
BASIC EPS
Income available to common stockholders $ 6,898,165 9,182,737 $ 0.75
EFFECT OF DILUTIVE SECURITIES
Common stock options -- 27,130 --
Restricted stock -- 120,182 (0.01)
-------------- ---------------- -----------
DILUTED EPS
Income available to common stockholders $ 6,898,165 9,330,049 $ 0.74
============== ================ ============
10. RELATED PARTY TRANSACTIONS
Essex Royalty Joint Ventures - A company wholly owned by Mr. Sfondrini,
a director of the Company, is the general partner of each of Essex Royalty
Limited Partnership ("Essex I L.P.") and Essex Royalty Limited Partnership II
("Essex II L.P."). In April 1992, a predecessor partnership of the Company and
Essex I L.P. entered into a Joint Venture Agreement (the "Essex I Joint
Venture") with respect to the purchase of certain royalty and nonoperating
interests in oil and natural gas properties. In May 1994, the Company's
predecessor partnership and Essex II L.P. entered into a Joint Venture Agreement
(the "Essex II Joint Venture") similar in nature to the Essex I Joint Venture.
The Company previously served as manager of the Essex I and II Joint Ventures.
Effective January 1, 2001, Mr. Sfondrini and a company wholly owned by Mr.
Sfondrini assumed the Company's duties as manager of the Essex I and II Joint
Ventures.
The Essex I Joint Venture terminated in April 1997. Under the terms of
the Essex I Joint Venture Agreement, Essex I L.P. made capital contributions
aggregating $3 million and the Company and its predecessor made no capital
contributions. The Essex I Joint Venture Agreement provides that quarterly
distributions of cash be made, in accordance with specified sharing ratios, in
an amount, subject to certain adjustments, not less than that equal to revenues
received from royalties less the management fee paid to the managing venturer
and the expenses of the Essex I Joint Venture. Initially, Essex I L.P. receives
100% of all cash distributions pursuant to the sharing ratios until a certain
payout amount has been recouped as defined in the Essex I Joint Venture
Agreement, as
F-21
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
amended, at which time the sharing ratios shift to 40% for the Company and 60%
for Essex I L.P. Pursuant to an amendment of the Essex I Joint Venture in August
2000, the time at which the sharing ratio shifts, or payout under the joint
venture agreement for Essex I Joint Venture would occur, was extended until the
limited partners of Essex I L.P. had recovered 100% of their initial capital
investment in Essex I L.P. and certain additional amounts had been distributed
by Essex I Joint Venture to Essex I L.P. As a result of the August 2000
amendment, the sharing ratio shift for Essex I Joint Venture occurs when the
aggregate amount of cash and property interests (valued as determined by the
Joint Venture agreement) actually distributed to the Essex I L.P. during 2001
and subsequent years equals $510,159. The sharing ratio shift, or payout, for
Essex I Joint Venture occurred in 2001, and the Company became entitled to
receive from Essex I Joint Venture 40% of the net royalty distributions.
In July 2002, Essex I L.P. and the Company modified the August 2000
amendment to the Essex I Joint Venture Agreement. The modification provided,
among other things, that the managing venturer of Essex I Joint Venture would be
entitled to a management fee of 3% per month of the gross distributions from
Essex I Joint Venture. In addition, in consideration of the granting of mutual
releases between Essex I Joint Venture, Essex I L.P., the new managers of the
venture and the Company of any claims, losses and demands arising out of the
Company's prior management of the Essex I Joint Venture, the Company agreed to
waive the amount owed to it as of March 31, 2002 on account of its 40%
after-payout interest in Essex I Joint Venture, which amount the Company
calculated to be $111,480. Finally, the parties agreed that Edge Group
Partnership, a general partnership, the partners of which are three limited
partnerships, the general partner of each of which is a company wholly owned by
Mr. Sfondrini, would be entitled to a de-minimus (less than .4%) portion of the
after-payout distributions from Essex I Joint Venture. In accordance with the
terms of the 2002 amendment, commencing effective in April 2002, Essex I Joint
Venture began making cash payments to the Company on account of its 40%
after-payout interest in the royalty properties. During 2002, the Essex I Joint
Venture distributed $202,685, $632 and $59,146 in net royalty distributions to
Essex I L.P., Edge Group Partnership and the Company, respectively.
The Essex II Joint Venture terminated in December 31, 1998. Essex II
L.P. made capital contributions aggregating approximately $4.6 million and the
Company and its predecessor made no capital contributions. Initially, Essex II
L.P. receives 100% of all cash distributions pursuant to the sharing ratios
until a certain payout amount has been recouped as defined in the Essex II Joint
Venture Agreement, as amended, at which time the sharing ratios shift to 25% for
the Company and 75% for Essex II L.P. Provisions with respect to mandatory
quarterly distributions are similar to those described for the Essex I Joint
Venture. Pursuant to an amendment of the Essex II Joint Venture in August 2000,
the time at which the sharing ratio shifts, or payout under the joint venture
agreement for Essex II Joint Venture would occur, was extended until the limited
partners of Essex II L.P. had recovered 100% of their initial capital investment
in Essex II L.P. As a result of the July 2000 amendment, the sharing ratio shift
for Essex II Joint Venture occurs when the aggregate amount of cash and property
interests (valued as determined by the joint venture agreement) actually
distributed to the Essex II L.P. during 2001 and subsequent years equals
$3,324,587. During 2001 and 2002, the aggregate amount of cash distributed to
Essex II L.P. was $1,325,092 and $436,899, respectively, leaving an amount of
$1,562,596 remaining to be recovered by Essex II L.P. before payout and a
sharing ratio shift occurs for Essex II Joint Venture.
During 2002, Mr. Sfondrini accrued management and administration fees
(including expenses he is entitled to be reimbursed for) in the amount of
$29,817 for managing the Essex I and II Joint Ventures, $27,825 of which was
paid to third parties who performed management, administration and tax services
for Mr. Sfondrini on behalf of the Joint Ventures.
Affiliates' Ownership in Prospects - A company wholly owned by Mr.
Sfondrini and another corporation of which Mr. Andrews (a director of the
Company) is an officer, are the general partners of Jovin, L.P., a limited
partnership that previously has invested, on the same basis as outside parties,
in certain wells in prospects generated by the Company. As a result of such
investments, Jovin, L.P. is entitled to an approximate 2% working interest in
the Company's Phoenix Prospect in Live Oak County, Texas. Jovin, L.P. made
payments to the Company during 2002 on account of Jovin, L.P.'s pro rata share
of certain land and lease operating expenses for this prospect in the aggregate
amount of $100,094.
Edge Group Partnership, Edge Holding Company, L.P., a limited
partnership of which Mr. Sfondrini and a corporation wholly owned by him are the
general partners, Andex Energy Corporation and Texedge Energy Corporation,
corporations of which Mr. Andrews is an officer and members of his immediate
family hold ownership interests, Mr. Raphael (a director of the Company), Jovin,
L.P. and Essex II Joint Venture, own certain working
F-22
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
interests in the Company's Nita and Austin Prospects and certain other wells and
prospects operated by the Company. These working interests aggregate 7.19% in
the Austin Prospect, 6.27% in the Nita Prospect and are negligible in other
wells and prospects. These working interests bear their share of lease operating
costs and royalty burdens on the same basis as the Company. In addition,
Bamaedge, L.P., a limited partnership of which Andex Energy Corporation is the
general partner, and Mr. Raphael also hold overriding royalty interests with
respect to the Company's working interest in certain wells and prospects.
Neither Mr. Raphael nor Bamaedge L.P. has an overriding interest in excess of
..075% in any one well or prospect. Essex I and II Joint Ventures own royalty and
overriding royalty interests in various wells operated by the Company. The
combined royalty and overriding royalty interests of the Essex I and Essex II
Joint Ventures do not exceed 6.2% in any one well or prospect. The gross amounts
paid or accrued to these persons by the Company in 2002 (including net revenue,
royalty and overriding royalty interests) and the amounts these same persons
paid to the Company for their respective share of lease operating expenses is
set forth in the following table:
Total Amounts Lease
Paid by the Operating
Company to Expenses
Owners in 2002 paid to the
including Company by
Overriding Owners in
Owner Royalty (1) 2002
- --------------------------------------- -------------- -------------
Andex Corporation / Texedge Corporation $ 3,370 $ 391
Bamaedge, L.P. 1,247 --
Edge Group Partnership 316,512 80,716
Edge Holding Company, L.P. 59,491 15,460
Essex I Joint Venture 15,043 1,658
Essex II Joint Venture 87,066 15,507
Jovin, L.P. -- 100,094
Stanley Raphael 3,455 750
----------- ----------
Total $ 486,184 $ 214,576
=========== ==========
(1) In the case of Essex I and II Joint Ventures, amount includes
royalty income in addition to working interest and overriding royalty income.
11. SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES
A summary of non-cash investing and financing activities for the years
ended December 31, 2002, 2001 and 2000 is presented below:
Number
of Fair
shares Market
Description issued Value
- ------------------------------------------------ --------- ----------
2002:
Shares issued to satisfy restricted stock grants 76,337 $ 409,777
Shares issued to fund the Company's matching
contribution under the Company's 401 (k) plan 17,538 $ 70,513
2001:
Shares issued to satisfy restricted stock grant 43,136 $ 131,134
2000:
Shares issued to satisfy restricted stock grant 9,648 $ 30,000
Forfeitures of restricted stock 5,600 $ 11,528
Supplemental Disclosure of Cash Flow Information
F-23
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
For the Year Ended December 31,
----------------------------------------------------
2002 2001 2000
-------------- ------------- --------------
Cash paid during the period for:
Interest, net of amounts capitalized $ 15,582 $ 54,081 $ 133,093
Federal alternative minimum tax payments -- 322,000 --
12. SUPPLEMENTAL FINANCIAL QUARTERLY RESULTS (UNAUDITED):
FOURTH THIRD SECOND FIRST
QUARTER QUARTER QUARTER QUARTER
------------ ----------- ----------- -------------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
2002
Oil and natural gas revenue $ 4,407 $ 5,164 $ 6,432 $ 4,908
Operating expenses 4,238 4,820 5,219 5,210
Operating income (loss) 169 344 1,213 (302)
Other expense, net (76) (81) (22) (22)
Income tax benefit (expense) (56) (107) (427) 117
Net income (loss) $ 37 $ 156 $ 764 $ (207)
Basic earnings (loss) per share $ 0.00 $ 0.02 $ 0.08 $ (0.02)
Diluted earnings (loss) per share $ 0.00 $ 0.02 $ 0.08 $ (0.02)
2001
Oil and natural gas revenue $ 4,062 $ 6,181 $ 8,045 $ 11,523
Operating expenses 7,386 5,831 5,210 4,040
Operating income (loss) (3,324) 350 2,835 7,483
Other expense, net (53) (4) (19) (11)
Income tax benefit (expense) 1,478 123 240 (1,022)
Net income (loss) $ (1,899) $ 469 $ 3,056 $ 6,450
Basic earnings (loss) per share $ (0.20) $ 0.05 $ 0.33 $ 0.70
Diluted earnings (loss) per share $ (0.20) $ 0.05 $ 0.31 $ 0.67
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.
Second quarter results for 2002 were impacted by the recognition of
revenue associated with underaccruals in prior periods. This adjustment resulted
in 142 MMcfe of additional production and $577,200 additional revenue. After
adjusting for related operating costs, the impact to net income for the second
quarter of 2002 was an increase of $212,300.
Included in operating expenses for the three months ended December 31,
2001 is $3.5 million for the settlement of litigation with BNP.
Included in operating expenses for the three months ended March 31,
2001, is a non-cash credit of $(755,372) to compensation expense as required by
FASB Interpretation No. (FIN) 44, Accounting for Certain Transactions involving
Stock Compensation. In the second quarter of 2001, an additional credit of
$(95,353) was included in operating expenses related to FIN 44.
F-24
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
13. SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION,
DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
This footnote provides unaudited information required by SFAS No. 69,
"Disclosures About Oil and Natural Gas Producing Activities."
CAPITALIZED COSTS - Capitalized costs and accumulated depletion,
depreciation and amortization relating to the Company's oil and natural gas
producing activities, all of which are conducted within the continental United
States, are summarized below:
DECEMBER 31,
--------------------------------------
2002 2001
----------------- -----------------
Developed oil and natural gas properties 125,640,971 101,303,892
$ $
Unevaluated oil and natural gas properties 7,901,315 13,105,817
Accumulated depletion, depreciation and
amortization (58,917,399) (49,220,255)
----------------- -----------------
Net capitalized cost $ 74,624,887 $ 65,189,454
================= =================
COSTS INCURRED - Costs incurred in oil and natural gas property
acquisition, exploration and development activities are summarized below:
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
2002 2001 2000
------------------ ----------------- -----------------
Acquisition Cost:
Unproved properties $ 5,465,794 $ 7,052,246 $ 4,219,936
Proved properties 1,369,464 5,695,000 --
Exploration costs 4,725,032 11,046,117 2,707,015
Development costs 7,926,579 4,822,589 3,765,945
------------------ ----------------- -----------------
Total costs incurred $ 19,486,869 $ 28,615,952 $ 10,692,896
================== ================= ================
RESULTS OF OPERATIONS - Results of operations for the Company's oil and natural
gas producing activities are summarized below:
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
2002 2001 2000
--------------- ------------------ -----------------
Oil and natural gas revenue $ 20,911,294 $ 29,810,917 $ 23,774,416
Operating expenses:
Oil and natural gas operating expenses and ad
valorem taxes 2,628,320 3,041,073 2,152,638
Production taxes 1,203,270 1,959,593 1,802,300
Depletion, depreciation and amortization 9,697,144 8,737,101 6,961,634
--------------- ------------------ -----------------
Results of operations from oil and gas
producing activities $ 7,382,560 $ 16,073,150 $ 12,857,844
=============== ================== =================
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.
F-25
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
The Company's net ownership interests in estimated quantities of proved oil
and natural gas reserves and changes in net proved reserves, all of which are
located in the continental United States, are summarized below.
NATURAL GAS
(MCF)
YEAR ENDED DECEMBER 31,
------------------------------------------------------
2002 2001 2000
-------------- --------------- ---------------
Proved developed and undeveloped reserves
Beginning of year 38,934,000 25,360,000 20,761,000
Revisions of previous estimates (5,579,800) (3,800,400) 892,000
Purchase of oil and gas properties 521,300 5,275,600 --
Extensions and discoveries 6,376,900 19,222,300 9,646,700
Sales of natural gas properties (6,000) (924,600) (733,700)
Production (5,266,400) (6,198,900) (5,206,000)
-------------- --------------- ---------------
End of year 34,980,000 38,934,000 25,360,000
============== =============== ===============
Proved developed reserves at year end 24,234,000 31,750,000 21,965,000
============== =============== ===============
OIL, CONDENSATE AND NATURAL GAS LIQUIDS
(BBLS)
YEAR ENDED DECEMBER 31,
------------------------------------------------------
2002 2001 2000
-------------- --------------- ---------------
Proved developed and undeveloped reserves
Beginning of year 978,361 720,090 701,382
Revisions of previous estimates 1,090,845 (94,255) 7,568
Purchase of oil and gas properties 62,939 47,340 --
Extensions and discoveries 491,519 538,108 197,400
Sales of natural gas properties (521) (71,493) (12,500)
Production (280,828) (161,429) (173,760)
-------------- --------------- ---------------
End of year 2,342,315 978,361 720,090
============== =============== ===============
Proved developed reserves at year end 1,509,950 879,058 674,845
============== =============== ===============
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, 2002 is
shown below:
YEAR ENDED DECEMBER 31,
------------------------------------------------------
2002 2001 2000
-------------- --------------- ---------------
Future cash inflows $ 212,064,453 $ 129,715,973 $ 285,318,442
Future oil and natural gas operating expenses (33,151,831) (23,105,695) (33,271,286)
Future development costs (8,069,700) (7,810,246) (2,921,526)
Future income tax expense (36,475,435) (16,116,421) (73,922,604)
---------------- --------------- ---------------
Future net cash flows 134,367,487 82,683,611 175,203,026
10% discount factor (36,811,015) (19,400,764) (49,844,011)
---------------- --------------- ---------------
Standardized measure of discounted future net
cash flows $ 97,556,472 $ 63,282,847 $ 125,359,015
================ =============== ===============
Future cash flows are computed by applying year-end prices of oil and
natural gas to year-end quantities of proved oil and natural gas reserves.
Future oil and natural gas operating expenses and development costs are computed
primarily by the Company's petroleum engineers and are provided to Ryder Scott
as estimates of expenditures to be incurred in developing and producing the
Company's proved oil and natural gas reserves at the end of the year, based on
year end costs and assuming the continuation of existing economic conditions.
F-26
EDGE PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (CONTINUED)
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,
----------------------------------------------------------------
2002 2001 2000
------------------- ------------------ -----------------
Changes due to current year operations:
Sales of oil and natural gas, net of oil and
natural gas operating expenses $ (17,079,705) $ (24,810,251) $ (19,819,478)
Sales of oil and natural gas properties (5,629) (5,295,221) (1,274,036)
Purchase of oil and gas properties 1,402,730 4,050,393 --
Extensions and discoveries 15,519,251 43,653,229 80,545,294
Changes due to revisions of standardized variables:
Prices and operating expenses 38,029,737 (121,516,045) 66,248,224
Revisions of previous quantity estimates 2,378,838 (7,971,645) 3,881,207
Estimated future development costs (20,172) (4,258,998) 553,576
Income taxes (11,143,442) 40,956,396 (47,083,522)
Accretion of discount 6,328,285 12,535,901 3,406,135
Production rates (timing) and other (1,136,268) 580,073 4,840,263
------------------- ------------------ -----------------
Net change 34,273,625 (62,076,168) 91,297,663
Beginning of year 63,282,847 125,359,015 34,061,352
------------------- ------------------ -----------------
End of year $ 97,556,472 $ 63,282,847 $ 125,359,015
=================== ================== =================
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-27
INDEPENDENT AUDITORS' REPORT ON CONSOLIDATED FINANCIAL
STATEMENT SCHEDULE
The Board of Directors and Stockholders
Edge Petroleum Corporation:
Under date of March 14, 2003, we reported on the consolidated balance sheets of
Edge Petroleum Corporation as of December 31, 2002 and 2001, and the related
consolidated statements of operations, cash flows and stockholder's equity for
the years then ended. In connection with our audits of the aforementioned
consolidated financial statements, we also audited the related consolidated
financial statement schedule for the periods indicated above. This consolidated
financial statement schedule is the responsibility of the Company's management.
Our responsibility is to express an opinion on the consolidated financial
statement schedule based on our audits.
In our opinion, the consolidated financial statement schedule, when considered
in relation to the basic consolidated financial statements taken as a whole,
presents fairly, in all material respect, the information set forth therein.
KPMG LLP
Houston, Texas
March 14, 2003
F-28
SCHEDULE II
EDGE PETROLEUM CORPORATION
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
FOR THE YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN THOUSANDS)
Balance at Charged to Balance at
Beginning of Costs and Deductions End of
Year Expenses and Other Year
-------------- ------------- --------------- ------------
YEAR ENDED DECEMBER 31, 2002:
Allowance for doubtful accounts $ 688 $ -- $ 81 $ 607
YEAR ENDED DECEMBER 31, 2001:
Allowance for doubtful accounts $ 163 $ 525 $ -- $ 688
YEAR ENDED DECEMBER 31, 2000:
Allowance for doubtful accounts $ 163 $ -- $ -- $ 163
F-29
EXHIBIT INDEX
+2.1 -- Amended and Restated Combination Agreement by and among (i)
Edge Group II Limited Partnership, (ii) Gulfedge Limited
Partnership, (iii) Edge Group Partnership, (iv) Edge Petroleum
Corporation, (v) Edge Mergeco, Inc. and (vi) the Company,
dated as of January 13, 1997 (Incorporated by reference from
exhibit 2.1 to the Company's Registration Statement on Form
S-4 (Registration No. 333-17269)).
+3.1 -- Restated Certificate of Incorporated of the Company, as
amended (Incorporated by reference from exhibit 3.1 to the
Company's Registration Statement on Form S-4 (Registration No.
333-17269)).
+3.2 -- Bylaws of the Company (Incorporated by Reference from exhibit
3.3 to the Company's Quarterly Report on Form 10-Q for the
quarterly period ended September 30, 1999).
+3.3 -- First Amendment to Bylaws of the Company on September 28, 1999
(Incorporated by Reference from exhibit 3.2 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1999).
+4.1 -- Second Amended and Restated Credit Agreement dated October
6, 2000 by and between Edge Petroleum Corporation, Edge
Petroleum Exploration Company and Edge Petroleum Operating
Company, Inc. (collectively, the "Borrowers") and Union Bank
Of California, N.A., a national banking association, as Agent
for itself and as lender. (Incorporated by Reference from
exhibit 4.5 to the Company's Quarterly Report on Form 10-Q for
the quarterly period ended September 31, 2000).
+4.2 -- Amendment No. 1 and Waiver dated as of November 11, 2001 by
and among the lenders party to the Second Amended and Restated
Credit Agreement dated October 6, 2000 ("Lenders"), Union Bank
of California, N.A., a national banking association, as agent
for such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement. (Incorporated by
Reference from exhibit 4.2 to the Company's Annual Report on
Form 10K for the annual period ended December 31, 2001).
*4.3 -- Amendment No. 2 dated as of May 29, 2002 by and among the
lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for
such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement.
*4.4 -- Amendment No. 3 dated as of August 8, 2002 by and among the
lenders party to the Second Amended and Restated Credit
Agreement dated October 6, 2000 ("Lenders"), Union Bank of
California, N.A., a national banking association, as agent for
such Lenders, Edge Petroleum Corporation, Edge Petroleum
Exploration Company, and Edge Petroleum Operating Company,
Inc. (collectively, the "Borrowers"), as borrowers under the
Second Amended and Restated Credit Agreement.
+4.5 -- Letter Agreement dated October 31, 2000 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company and
Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender.
(Incorporated by Reference from exhibit 4.6 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 31, 2000).
+4.6 -- Letter Agreement dated March 23, 2001 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company and
Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender.
(Incorporated by Reference from exhibit 4.5 to the Company's
Annual Report on Form 10K for the annual period ended December
31, 2000).
+4.7 -- Letter Agreement dated September 21, 2001 by and between
Edge Petroleum Corporation, Edge Petroleum Exploration Company
and Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender.
(Incorporated by Reference from exhibit 4.6 to the Company's
Quarterly Report on Form 10Q for the quarterly period ended
September 30, 2001).
+4.8 -- Letter Agreement dated January 18, 2002 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company and
Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender.
(Incorporated by Reference from exhibit 4.6 to the Company's
Annual Report on Form 10K for the annual period ended December
31, 2001).
+4.9 -- Letter Agreement dated August 9, 2002 by and between Edge
Petroleum Corporation, Edge Petroleum Exploration Company and
Edge Petroleum Operating Company, Inc. (collectively, the
"Borrowers") and Union Bank Of California, N.A., a national
banking association, as Agent for itself and as lender.
(Incorporated by Reference from exhibit 4.7 to the Company's
Quarterly Report on Form 10Q for the quarterly period ended
June 30, 2002).
+4.10 -- Common Stock Subscription Agreement dated as of April 30,
1999 between the Company and the purchasers named therein
(Incorporated by reference from exhibit 4.5 to the Company's
Quarterly Report on Form 10-Q/A for the quarter ended March
31, 1999).
+4.11 -- Warrant Agreement dated as of May 6, 1999 between the Company
and the Warrant holders named therein (Incorporated by
reference from exhibit 4.5 to the Company's Quarterly Report
on Form 10-Q/A for the quarter ended March 31, 1999).
+4.12 -- Form of Warrant for the purchase of the Common Stock
(Incorporated by reference from the Common Stock Subscription
Agreement from exhibit 4.5 to the Company's Quarterly Report
on Form 10-Q/A for the quarter ended March 31, 1999).
+10.1 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership II, dated as of May 10, 1994
(Incorporated by reference from exhibit 10.2 to the Company's
Registration Statement on Form S-4 (Registration No.
333-17269)).
+10.2 -- Joint Venture Agreement between Edge Joint Venture II and
Essex Royalty Limited Partnership, dated as of April 11, 1992
(Incorporated by reference from exhibit 10.3 to the Company's
Registration Statement on Form S-4 (Registration No.
333-17269)).
*10.2 -- Amendment dated August 21, 2000 to the Joint Venture
Agreement between Edge Joint Venture II and Essex Royalty
Limited Partnership II, dated as of May 10, 1994.
*10.3 -- Amendment dated August 21, 2000 to the Joint Venture
Agreement between Edge Joint Venture II and Essex Royalty
Limited Partnership, dated as of April 11, 1992.
*10.4 -- Letter Agreement between Edge Petroleum Corporation and Essex
Royalty Limited Partnership, dated as of July 30, 2002.
+10.5 -- 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)).
+10.6 -- Stock Option Plan of Edge Petroleum Corporation, a Texas
corporation (Incorporated by reference from exhibit 10.13 to
the Company's Registration on Form S-4 (Registration No.
333-17269)).
+10.7 -- Employment Agreement dated as of November 16, 1998, by and
between the Company John W. Elias. (Incorporated by reference
from 10.12 to the Company's Annual on Form 10-K for the year
ended December 31, 1998).
*10.8 -- Incentive Plan of Edge Petroleum Corporation as Amended and
Restated Effective as of February 20, 2003.
+10.9 -- Edge Petroleum Corporation Incentive Plan "Standard
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Officers named therein.
(Incorporated by reference from exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1999).
+10.10 -- Edge Petroleum Corporation Incentive Plan "Director
Non-Qualified Stock Option Agreement" by and between Edge
Petroleum Corporation and the Directors named therein.
(Incorporated by reference from exhibit 10.3 to the Company's
Quarterly Report on Form 10-Q for the quarterly period ended
September 30, 1999).
+10.11 -- Form of Employee Restricted Stock Award Agreement under the
Incentive Plan of Edge Petroleum Corporation (Incorporated by
Reference from exhibit 10.15 to the Company's Quarterly Report
on Form 10-Q/A for the quarterly period ended March 31, 1999).
+10.12 -- Edge Petroleum Corporation Amended and Restated Elias Stock
Incentive Plan. (Incorporated by reference from exhibit 4.5
to the Company's Registration on Form S-8 filed May 30, 2001
(Registration No. 333-61890)).
+10.13 -- Form of Edge Petroleum Corporation John W. Elias Non-Qualified
Stock Option Agreement (Incorporated by reference from exhibit
4.6 to the Company's Registration Statement on Form S-8 filed
May 30, 2001 (Registration No. 333-61890)).
*21.1 -- Subsidiaries of the Company.
*23.1 -- Consent of KPMG LLP, independent auditors.
*23.2 -- Consent of Deloitte & Touche LLP.
*23.3 -- Consent of Ryder Scott Company.
*99.1 -- Summary of Reserve Report of Ryder Scott Company Petroleum
Engineers as of December 31, 2002 (included as an appendix to
Form 10-K).
*99.2 -- Certification by John W. Elias, Chief Executive Officer,
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(Subsections (a) and (b) of Section 1350, Chapter 63 of Title
18, United States Code).
*99.3 -- Certification by Michael G. Long , Chief Financial and
Accounting Officer, pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section
1350, Chapter 63 of Title 18, United States Code).
* Filed herewith.
+ Incorporated by reference as indicated.
(b) Reports on Form 8-K: The Company filed the following reports on Form 8-K
during the quarter ended December 31, 2002:
None.