FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED
DECEMBER 31, 2002
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No. 0-20100
BELDEN & BLAKE CORPORATION
(Exact name of registrant as specified in its charter)
OHIO 34-1686642
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
5200 STONEHAM ROAD
NORTH CANTON, OHIO 44720
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (330) 499-1660
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, WITHOUT PAR VALUE
(Title of Class)
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. X
----
Indicate by check mark whether the Registrant is an accelerated filer
(as defined in Rule 12b-2 of the Act). Yes No X
--- ---
As of February 28, 2003, Belden & Blake Corporation had outstanding
10,304,251 shares of common stock, without par value, which is its only class of
stock. The common stock of Belden & Blake Corporation is not traded on any
exchange and, therefore, its aggregate market value and the value of shares held
by non-affiliates cannot be determined as of the last business day of the
registrant's most recently completed second fiscal quarter.
DOCUMENTS INCORPORATED BY REFERENCE
None.
The information in this document includes forward-looking statements
that are made pursuant to Safe Harbor Provisions of the Private Securities
Litigation Reform Act of 1995. Statements preceded by, followed by or that
otherwise include the statements "should," "believe," "expect," "anticipate,"
"intend," "will," "continue," "estimate," "plan," "outlook," "may," "future,"
"projection," variations of these statements and similar expressions are
forward-looking statements. These forward-looking statements are based on
current expectations and projections about future events. Forward-looking
statements, and the business prospects of Belden & Blake Corporation (the
"Company") are subject to a number of risks and uncertainties which may cause
the Company's actual results in future periods to differ materially from the
forward-looking statements contained herein. These risks and uncertainties
include, but are not limited to, the Company's access to capital, the market
demand for and prices of oil and natural gas, the Company's oil and gas
production and costs of operation, results of the Company's future drilling
activities, the uncertainties of reserve estimates, general economic conditions,
new legislation or regulatory changes, changes in accounting principles,
policies or guidelines and environmental risks. These and other risks are
described in the Company's 10-K and 10-Q reports and other filings with the
Securities and Exchange Commission ("SEC").
PART I
Item 1. BUSINESS
GENERAL
Belden & Blake Corporation is a privately held company owned by TPG
Partners II L.P. ("TPG") and certain other investors. The Company is an
independent energy company engaged in producing oil and natural gas; exploring
for and developing oil and gas reserves; acquiring and enhancing the economic
performance of producing oil and gas properties; and marketing and gathering
natural gas for delivery to intrastate and interstate gas transmission
pipelines. The Company provides oilfield services to itself and third-party
customers through its Arrow Oilfield Service Company ("Arrow"). Until 1995, the
Company conducted business exclusively in the Appalachian Basin where it has
operated since 1942 through several predecessor entities. It is currently among
the largest exploration and production companies operating in the Appalachian
Basin in terms of reserves, acreage held and wells operated. In 1995, the
Company commenced production and drilling operations in the Michigan Basin
through the acquisition of Ward Lake Drilling, Inc. ("Ward Lake"), an
independent energy company, which owns and operates oil and gas properties in
Michigan's lower peninsula. On March 17, 2000, the Company sold Peake Energy,
Inc. ("Peake"), a wholly owned subsidiary, which owned oil and gas properties in
West Virginia and Kentucky. At December 31, 2002, the Company operated in Ohio,
Pennsylvania, New York, Michigan, Indiana and West Virginia.
In the fourth quarter of 2002, the Company's net production, excluding
wells sold in 2002, was approximately 45 Mmcfe (million cubic feet of natural
gas equivalent) per day consisting of 39 Mmcf (million cubic feet) of natural
gas and 1,000 Bbls (barrels) of oil per day. At December 31, 2002, the Company
owned interests in 4,030 gross (3,056 net) productive oil and gas wells in Ohio,
Pennsylvania, New York and Michigan with proved reserves totaling 375 Bcfe
(billion cubic feet of natural gas equivalent) consisting of 336 Bcf (billion
cubic feet) of natural gas and 6.6 Mmbbl (million barrels) of oil. The estimated
future net cash flows from these reserves had a present value (discounted at 10
percent) before income taxes of approximately $480 million at December 31, 2002.
The weighted average prices related to proved reserves at December 31, 2002 were
$4.99 per Mcf (thousand cubic feet) for natural gas and $27.81 per Bbl for oil.
At December 31, 2002, the Company operated approximately 3,330 wells (83% of the
Company's gross wells), including wells operated for third parties. At that
date, the Company held leases on 1,377,930 gross (1,187,875 net) acres,
including 919,024 gross (772,164 net)
1
undeveloped acres. The Company owned and operated 1,217 miles of gas gathering
systems with access to the commercial and industrial gas markets of the
northeastern United States at December 31, 2002.
The Company has a track record of reserve replacement through both
drilling and acquisitions. Since its formation in 1992 through December 31,
2002, the Company has added approximately 459 Bcfe of proved developed reserves
through drilling and acquisitions at an average cost of $0.82 per Mcfe (thousand
cubic feet of natural gas equivalent). This represented approximately 189% of
the oil and gas produced by the Company during that period.
During 2002, the Company drilled 112 gross (79.2 net) wells at a direct
cost, including exploratory dry hole expense, of approximately $20.8 million for
the net wells. The 2002 drilling activity added 16.8 Bcfe of proved developed
reserves at an average cost of $1.23 per Mcfe. The cost was impacted by
exploratory dry hole costs from wells drilled in the Trenton Black River ("TBR")
formations. Excluding the costs of 5 exploratory dry holes drilled in the TBR
during 2002, the average cost of developing proved reserves was $1.03 per Mcfe.
The Company also made production enhancements to existing wells during the year
which increased proved developed reserves by 0.9 Bcfe at an average cost of
$0.85 per Mcfe. Acquisitions of properties in 2002 added 4.2 Bcfe of proved
developed reserves at an average cost of $0.28 per Mcfe. Proved developed
reserves added through drilling, enhancements and acquisitions in 2002
represented approximately 109% of production.
The Company maintains its corporate offices at 5200 Stoneham Road,
North Canton, Ohio 44720. Its telephone number at that location is (330)
499-1660. Unless the context otherwise requires, all references herein to the
"Company" are to Belden & Blake Corporation, its subsidiaries and predecessor
entities.
SIGNIFICANT EVENTS
During 2001, the Company locked-in natural gas prices on over 13.3 Bcf
of its natural gas production in 2002 and 10.7 Bcf of its production in 2003 by
entering into fixed price gas contracts and through financial gas hedging
instruments. In January 2002, the Company monetized $22.7 million of these
positions and entered into additional gas hedging instruments for 2002. At
December 31, 2002, the Company had locked-in natural gas prices on 12.9 Tbtu
(trillion British Thermal Units) of its 2003 production, 8.4 Tbtu of its 2004
production and 6.2 Tbtu of its 2005 production.
During 2002, amendments to the Company's $100 million revolving credit
facility ("the Revolver") extended the Revolver's final maturity date to
December 31, 2005, from April 22, 2004, increased the letter of credit
sub-limit from $30 million to $40 million and permitted the Company to enter
into the transactions to sell oil and gas properties consisting of 1,138 wells
in Ohio and 962 wells in New York and Pennsylvania.
On August 1, 2002, the Company sold oil and gas properties consisting
of 1,138 wells in Ohio that had approximately 10 Bcfe of reserves. At the time
of the sale, the Company's net production from these wells was approximately 3.1
Mmcfe per day (3 Mcfe per day per well). The Company disposed of these
properties due to the low production volume per well and high per unit operating
costs. The proceeds of approximately $8.0 million were used to pay down the
Company's revolving credit facility.
On October 10, 2002, the Company combined its Pennsylvania/New York
District with its Ohio District to form a new "Appalachian District". A total of
28 positions were eliminated in the Ohio and Pennsylvania/New York Districts and
in the corporate office. These actions were necessary to capitalize on
operational and administrative efficiencies and bring the Company's employment
level in line with
2
current and anticipated future staffing. The Company recorded a nonrecurring
charge of approximately $700,000 in the fourth quarter of 2002 related to
severance and other costs associated with these actions. The Company expects to
reduce its future expenses by approximately $1.7 million annually beginning in
the fourth quarter of 2002 as a result of combining the two districts and staff
reductions.
On December 10, 2002, the Company sold 962 oil and natural gas wells in
New York and Pennsylvania. The sale included substantially all of the Company's
Medina formation wells in New York and a smaller number of Pennsylvania Medina
wells. The properties had approximately 23 Bcfe of reserves. At the time of the
sale, the Company's net production from these wells was approximately 3.9 Mmcfe
per day (4 Mcfe per day per well). The Company disposed of these properties due
to the low production volume per well and high cost characteristics.
The sale resulted in proceeds of approximately $16.2 million. On
December 10, 2002, the Company received $15.5 million in cash with the remaining
amount of approximately $700,000 received in February 2003. The proceeds were
used to pay down the Company's revolving credit facility. As a result of the
sale, the Company disposed of all of its properties producing from the New York
Medina formation. As a result of the disposition of its entire New York Medina
geographical/geological pool, the Company recorded a loss on the sale of $3.2
million ($1.8 million net of tax). According to Financial Accounting Standards
Board (FASB) Statement of Financial Accounting Standards No. (SFAS) 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets," the
disposition of this group of wells is classified as discontinued operations. The
loss on the sale of the New York Medina wells and the related results of these
properties have been reclassified as discontinued operations for all periods
presented.
DESCRIPTION OF BUSINESS
OVERVIEW
The Company conducts operations in the United States in one reportable
segment which is oil and gas exploration and production. The Company is actively
engaged in producing oil and natural gas; exploring for and developing oil and
gas reserves; acquiring and enhancing the economic performance of producing oil
and gas properties; and marketing and gathering natural gas for delivery to
intrastate and interstate gas transmission pipelines. The Company operates
primarily in the Appalachian and Michigan Basins (a region which includes Ohio,
Pennsylvania, New York, West Virginia and Michigan) where it is one of the
largest oil and gas companies in terms of reserves, acreage held and wells
operated.
The Appalachian Basin is the oldest and geographically one of the
largest oil and gas producing regions in the United States. Although the
Appalachian Basin has sedimentary formations indicating the potential for oil
and gas reservoirs to depths of 30,000 feet or more, oil and natural gas is
currently produced primarily from shallow, highly developed blanket formations
at depths of 1,000 to 6,200 feet. Drilling completion rates of the Company and
others drilling in these formations historically have exceeded 90% with
production generally lasting longer than 20 years.
The combination of long-lived production and high drilling completion
rates at these shallower depths has resulted in a highly fragmented, extensively
drilled, low technology operating environment in the Appalachian Basin. As a
result of this environment, there has been limited testing or development of the
formations below the existing shallow production in the Appalachian Basin. The
Company believes that there are significant exploration and development
opportunities in these less developed formations for those operators with the
capital, technical expertise and ability to assemble the large acreage positions
needed to justify the use of advanced exploration and production technologies.
3
During 2002, the Company acquired approximately 56,000 gross (43,000
net) leasehold acres with potential in the deeper, less developed TBR
formations. The Company acquired seismic data on multiple TBR locations and
drilled 8 gross (3.6 net) wells to this horizon, at a cost of $5.7 million. Five
of these wells (2.3 net wells) were dry holes and three (1.3 net) wells are
still being evaluated. If these three wells are determined to be dry holes,
their cost ($2.3 million) will be charged to exploratory dry hole expense in
2003. Hydrocarbons were encountered in all wells but economic production has not
been established.
The Company currently holds approximately 342,000 gross (241,000 net)
leasehold acres and approximately 500 miles of seismic in prospective TBR areas
in the Appalachian Basin and intends to continue to lease additional acreage and
acquire additional seismic data. The Company plans to drill 14 gross (8.5 net)
wells in these TBR areas in 2003.
The Company operates 132 producing coalbed methane ("CBM") wells in
Pennsylvania and holds leases on approximately 101,000 acres of prospective CBM
properties. Current gross production from these wells is 2.8 Mmcf (2.4 Mmcf net)
per day. The Company drilled 33 CBM wells in 2002 and plans to drill an
additional 25 CBM wells in 2003.
The Company, through its subsidiary, Ward Lake, currently operates 813
wells in the Michigan Basin producing approximately 35.4 Mmcf (17.9 Mmcf net) of
natural gas per day in Michigan.
The Michigan Basin has geologic and operational similarities to the
Appalachian Basin, geographic proximity to the Company's operations in the
Appalachian Basin and proximity to premium gas markets. Geologically, the
Michigan Basin resembles the Appalachian Basin with shallow blanket formations
and deeper formations with greater reserve potential. Operationally, economies
of scale and cost containment are essential to operating profitability. The
operating environment in the Michigan Basin is also highly fragmented with
substantial acquisition opportunities.
Most of the Company's production in the Michigan Basin is derived from
the shallow (700 to 2,000 feet) blanket Antrim Shale formation. Completion rates
for companies drilling to this formation have exceeded 90%, with production
often lasting as long as 20 years. The Michigan Basin also contains deeper
formations with greater reserve potential. The Company has also established
production from certain of these deeper formations through its drilling
operations. Because the production rate from Antrim Shale wells is relatively
low, cost containment is a crucial aspect of operations. In contrast to the
shallow, highly developed blanket formations in the Appalachian Basin, the
operating environment in the Antrim Shale is more capital intensive because of
the low natural reservoir pressures and the high initial water content of the
formation.
The proximity of the Appalachian and Michigan Basins to large
commercial and industrial natural gas markets has generally resulted in premium
wellhead gas prices compared with the New York Mercantile Exchange's ("NYMEX")
price for gas delivered at the Henry Hub in Louisiana. Monthly spot natural gas
prices in the Company's market areas are typically ten to sixty cents per Mcf
higher than comparable NYMEX prices.
4
BUSINESS STRATEGY
The Company seeks to increase shareholder value by increasing reserves,
production and cash flow through the exploration and development of the
Company's extensive acreage base; further improvement in profit margins through
operational efficiencies; and utilization of the Company's advanced technology
to enhance production and reserves discovered. The key elements of the Company's
strategy are as follows:
- - MAINTAIN A BALANCED DRILLING PROGRAM. The Company's exploration and
development activities focus on a well-balanced portfolio of development
and exploratory drilling in both the highly developed or blanket formations
and the deeper, less developed and potentially more prolific formations.
The Company primarily targets natural gas production in its drilling
activities. The Company believes this portfolio approach, coupled with its
extensive knowledge of its operating areas, allows the Company to optimize
economic returns and minimize much of the geological risk associated with
oil and gas exploration and development. The Company believes that there
are significant exploration and development opportunities in the less
developed or deeper formations in the Appalachian and Michigan Basins and
in the shallow coalbed methane formations in western Pennsylvania. The
Company has identified numerous development and exploratory drilling
locations in the deeper formations of these Basins, such as the Trenton
Black River, and has established a substantial leasehold position overlying
potentially productive coalbed methane formations in western Pennsylvania.
During 2002, the Company spent a higher percentage of its drilling capital
on higher risk exploration projects than it had in the past. In 2003, the
Company plans to spend approximately 63% of its drilling capital
expenditures on highly developed or blanket formations and approximately
37% of its drilling capital expenditures on deeper, or less developed,
potentially more prolific prospects. The deeper wells drilled by the
Company in 2002 and planned for 2003 are higher cost, higher risk with
potential for higher reserves than the deep wells drilled by the Company in
prior years. Funds previously targeted for other deeper formations have
been redeployed to the TBR to take advantage of the significant upside
potential of this play.
- - IMPROVE THE COMPANY'S FINANCIAL POSITION. At December 31, 2002, the Company
had a deficit in shareholders' equity of $44.6 million. The Company may
sell non-strategic assets and use the proceeds, along with a portion of its
available cash flow, to reduce its debt burden and enhance liquidity. The
Company may also attempt to restructure portions of its existing debt to
further reduce the amount of debt outstanding.
- - UTILIZE ADVANCED TECHNOLOGY. The combination of long-lived production and
high drilling completion rates at the shallow depths has resulted in a
highly fragmented, extensively drilled, low technology operating
environment in the Appalachian and Michigan Basins. The Company has applied
more advanced technology, including 3-D seismic, horizontal drilling,
advanced fracturing techniques and production enhancement technologies to
improve drilling completion rates, reserves discovered per well, production
rates, reserve recovery rates and total economics in its operating areas.
- - IMPROVE PROFIT MARGINS. The Company strives to improve its profit margins
on production from existing and acquired properties through advanced
production technologies, operating efficiencies and mechanical
improvements. Through its production field offices, the Company reviews its
properties, especially newly acquired properties, to determine what actions
can be taken to reduce operating costs and/or improve production. The
Company strives to control field level costs through improved operating
practices such as computerized production scheduling and the use of
hand-held computers to gather field data. On acquired properties, further
efficiencies may be realized through improvements in production scheduling
and reductions in oilfield labor. Actions that may be taken to
5
improve production include modifying surface facilities, redesigning
downhole equipment and recompleting existing wells.
- - EVALUATE POTENTIAL ACQUISITIONS. The Company may seek to acquire properties
that complement its operations, provide exploration and development
opportunities and potentially provide superior returns on investment.
OIL AND GAS OPERATIONS AND PRODUCTION
Operations. The Company operates 83% of the wells in which it holds
working interests. It seeks to maximize the value of its properties through
operating efficiencies associated with economies of scale and through operating
cost reductions, advanced production technology, mechanical improvements and/or
the use of deliverability enhancement techniques.
The Company currently maintains production field offices in Ohio,
Pennsylvania and Michigan. Through these offices, the Company reviews its
properties to determine what action can be taken to reduce operating costs
and/or improve production.
The Company has also provided its own oilfield services for more than
30 years in order to assure quality control and operational and administrative
support to its exploration and production operations. Arrow, the Company's
service division, provides the Company and third-party customers with necessary
oilfield services such as well workovers, well completions, brine hauling and
disposal and oil trucking.
The Company currently operates approximately 1,217 miles of natural gas
gathering lines in Ohio, Pennsylvania, New York and Michigan which are connected
directly to various intrastate and interstate natural gas transmission systems.
The interconnections with these pipelines afford the Company potential marketing
access to numerous gas markets.
6
Production, Sales Prices and Costs. The following table sets forth
certain information regarding the Company's net oil and natural gas production,
revenues and expenses for the years indicated. This table includes continuing
and discontinued operations.
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------
1998 1999 2000 2001 2002
----------- ------------ ----------- ----------- -----------
PRODUCTION
Gas (Mmcf) 30,140 26,988 20,037 18,541 17,106
Oil (Mbbl) 768 713 592 646 523
Total production (Mmcfe) 34,750 31,267 23,591 22,415 20,244
AVERAGE PRICE
Gas (per Mcf) $ 2.57 $ 2.50 $ 3.17 $ 4.34 $ 4.84
Oil (per Bbl) 12.61 16.57 27.29 23.04 22.72
Mcfe 2.51 2.54 3.38 4.26 4.67
AVERAGE COSTS (PER MCFE)
Production expense 0.68 0.70 0.89 1.01 1.04
Production taxes 0.09 0.10 0.10 0.11 0.09
Depletion 1.66 0.92 0.77 0.91 0.88
OPERATING MARGIN (PER MCFE) 1.74 1.74 2.39 3.14 3.54
Mmcf - Million cubic feet Mmcfe - Million cubic feet equivalent Bbl - barrel
Mbbl - Thousand barrels Mcf - Thousand cubic feet
Operating margin (per Mcfe) - average price less production expense and production taxes
The following table sets forth certain information regarding the
Company's net oil and natural gas production, revenues and expenses for the
years indicated excluding Peake and discontinued operations. However, it does
not exclude all properties sold. See Note 4 to the Consolidated Financial
Statements:
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------
1998 1999 2000 2001 2002
----------- ------------ ----------- ----------- -----------
PRODUCTION
Gas (Mmcf) 22,667 19,812 17,371 17,164 15,882
Oil (Mbbl) 682 639 573 644 522
Total production (Mmcfe) 26,760 23,647 20,811 21,030 19,012
AVERAGE PRICE
Gas (per Mcf) $ 2.48 $ 2.50 $ 3.14 $ 4.35 $ 4.95
Oil (per Bbl) 12.57 16.51 27.35 23.04 22.72
Mcfe 2.42 2.54 3.38 4.26 4.76
AVERAGE COSTS (PER MCFE)
Production expense 0.68 0.73 0.89 1.00 1.05
Production taxes 0.05 0.08 0.10 0.11 0.09
Depletion 1.75 0.99 0.78 0.91 0.88
OPERATING MARGIN (PER MCFE) 1.69 1.73 2.39 3.15 3.62
Mmcf - Million cubic feet Mmcfe - Million cubic feet equivalent Bbl - barrel
Mbbl - Thousand barrels Mcf - Thousand cubic feet
Operating margin (per Mcfe) - average price less production expense and production taxes
EXPLORATION AND DEVELOPMENT
The Company's activities include development and exploratory drilling
in both the highly developed or blanket formations and the deeper or less
developed formations of the Appalachian and Michigan Basins. The Company's
strategy is to develop a balanced portfolio of drilling prospects that
7
includes lower risk wells with a high probability of success and higher risk
wells with greater economic potential. The Company has an extensive inventory of
acreage on which to conduct its exploration and development activities.
In 2002, the Company drilled 84 gross (64.6 net) wells to highly
developed or shallow blanket formations in its operating area at a direct cost
of approximately $13.3 million, including exploratory dry hole expense, for the
net wells. The Company also drilled 28 gross (14.6 net) wells to less developed
and deeper formations in 2002 at a direct cost of approximately $7.5 million,
including exploratory dry hole expense, for the net wells. This cost excludes
approximately $2.4 million related to 4 gross (2.0 net) wells in progress as of
December 31, 2002, which are still being evaluated. If these wells are
determined to be dry holes, their cost will be charged to exploratory dry hole
expense in 2003. The result of this drilling activity is shown in the table on
page 11.
In 2003, the Company expects to spend approximately $21.5 million,
including exploratory dry hole expense, on development and exploratory drilling
of approximately 107 gross (94.2 net) wells. In 2003, the Company plans to spend
approximately 63% of its drilling capital expenditures on highly developed or
blanket formations and approximately 37% of its drilling capital expenditures on
deeper, or less developed, potentially more prolific prospects.
The Company believes that its diversified portfolio approach to its
drilling activities results in more consistent and predictable economic results
than might be experienced with a less diversified or higher risk drilling
program profile.
Highly Developed or Blanket Formations. In general, the highly
developed or blanket formations found in the Appalachian and Michigan Basins are
widespread in extent and hydrocarbon accumulations. Drilling completion rates of
the Company and others drilling these formations historically have exceeded 90%.
The principal risk of such wells is uneconomic recoverable reserves.
The Company is a pioneer in coalbed methane development and production
in Pennsylvania, presently operating 132 coalbed methane gas wells in Indiana,
Westmoreland and Fayette counties. CBM wells in this area range in depth from
1,200 to 1,500 feet and typically encounter three to six unmined coal seams.
In September 2001, the Company acquired its partner's 40% working
interest in the Blacklick CBM field giving the Company 100% ownership of this
CBM project. With approximately 101,000 CBM acres currently under lease in
Pennsylvania, the Company believes the CBM will contribute significantly to its
drilling portfolio. The Company plans to drill 25 gross (25 net) CBM wells in
2003.
The Antrim Shale formation, the principal shallow blanket formation in
the Michigan Basin, is characterized by high formation water production in the
early years of a well's productive life with water production decreasing over
time. Antrim Shale wells typically produce natural gas at rates of 75 Mcf to 125
Mcf per day for several years, with modest declines thereafter. Gas production
often increases in the early years, as the producing formation becomes less
water saturated. Average well lives are 20 years or more. The Company plans to
drill 34 gross (31.9 net) wells to the Antrim Shale formation in 2003.
In addition to its CBM and Antrim drilling, the Company also plans to
drill 10 gross (10 net) wells to the Medina formation and 15 gross (15 net)
wells to the Clarendon formation in Pennsylvania during 2003.
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Certain typical characteristics of the highly developed or blanket
formations targeted by the Company are described below:
RANGE OF AVERAGE DRILLING RANGE OF AVERAGE GROSS
AND COMPLETION COSTS PER RESERVES PER COMPLETED
RANGE OF WELL DEPTHS WELL WELL
---------------------- -------------------------- ----------------------
(IN FEET) (IN THOUSANDS) (IN MMCFE)
Ohio:
Clinton 3,000 - 5,500 $ 135 - 190 80 - 150
Pennsylvania:
Coalbed Methane 1,200 - 1,500 125 - 150 150 - 250
Clarendon 1,100 - 2,000 50 - 65 30 - 50
Medina 5,000 - 6,200 170 - 210 150 - 300
Michigan:
Antrim 700 - 2,000 170 - 230 350 - 550
Deeper or Less Developed Formations. The Appalachian Basin has
productive and potentially productive sedimentary formations to depths of 30,000
feet or more, but the combination of long-lived production and high drilling
completion rates in the shallow formations has curbed the development of the
deeper formations in the basin. The Company believes it possesses the
technological expertise and the acreage position needed to explore the deeper
formations in a cost effective manner.
The Trenton Black River formations continue to receive significant
attention in the Appalachian Basin. Based on historical information available in
public records, wells completed in the TBR possess significant productive
potential with wells having produced from 0.1 Bcf to 1.0 Bcf of natural gas
during the first 12 months of production. Based on this and other data, the
Company estimates that ultimate reserves could range from 0.5 Bcf to in excess
of 5 Bcf of natural gas per well. With significant discoveries by other
operators in south-central New York and in central West Virginia, the Company
believes the potential exists for numerous opportunities in the Company's
existing areas of operations. While expected geologic conditions and gas shows
were encountered in all tests which the Company has undertaken in the TBR since
1998, economic production has not been established to date.
In 2001, the Company implemented a major leasing and geophysical
program in the TBR that resulted in acquiring over 100,000 acres and more than
100 miles of seismic data.
On June 29, 2001, the Company and Triana Energy, LLC ("Triana"), a West
Virginia oil and gas exploration company, entered into an exploration agreement
and a joint operating agreement ("JOA"). Pursuant to the JOA, Triana will manage
the exploration of the Oriskany and Trenton Black River formations on certain
properties in which the Company owns the leasehold working interest in
Pennsylvania and New York. It is anticipated that the Company's contribution of
its leasehold acreage coupled with the experience and professional skills
contributed by Triana should enhance the Company's drilling program with respect
to these properties and formations. Triana will manage all exploration and
drilling activities performed on the properties covered by this agreement. The
Company will be the operator following the completion of the wells. This
agreement is in effect until June 29, 2006.
9
The Company has also entered into several exploration agreements with
other industry participants to jointly explore and develop the TBR in areas of
New York and Ohio. The Company holds additional TBR acreage in which it owns a
100% working interest.
During 2002, the Company acquired approximately 56,000 gross (43,000
net) leasehold acres with potential in the TBR formations. The Company
subsequently acquired seismic data on multiple TBR locations and drilled 8 gross
(3.6 net) wells to this horizon, at a cost of $5.7 million. Five of these wells
(2.3 net wells) were dry holes and three (1.3 net) wells are still being
evaluated. If these three wells are determined to be dry holes, their cost ($2.3
million) will be charged to exploratory dry hole expense in 2003. Hydrocarbons
were encountered in all wells but economic production has not been established.
The Company currently holds approximately 342,000 gross (241,000 net)
leasehold acres and approximately 500 miles of seismic data in prospective TBR
areas in the Appalachian Basin and intends to continue to lease additional
acreage and acquire additional seismic data.
Exploration and drilling activities in the TBR formations, found at
depths ranging from 5,000 to 12,000 feet, are focused on testing many of the
currently identified prospects and confirming potential future drill sites. In
2003, the Company anticipates spending approximately $6.7 million to drill 14
gross (8.5 net) wells on TBR acreage. In addition, the Company plans to spend
$1.4 million to acquire additional acreage and seismic data in the TBR.
The Company has also tested the Niagaran Carbonate, Onondaga Limestone,
Oriskany Sandstone and Knox formations. In addition to its planned TBR drilling,
the Company plans to drill approximately 9 gross (3.8 net) wells to other deep
formations in 2003.
Certain typical characteristics of the less developed or deeper
formations targeted by the Company are described below:
AVERAGE DRILLING COSTS
------------------------ AVERAGE GROSS
RANGE OF WELL COMPLETED RESERVES PER
FORMATION LOCATION DEPTHS DRY HOLE WELL COMPLETED WELL
- ------------------------ -------------------- ------------------- ---------- -------------- -----------------
(IN FEET) (IN THOUSANDS) (IN MMCFE)
Trenton Black River
Carbonates (1) PA, NY, WV, OH 5,000 - 12,000 $ 625 $ 950 1,000 - 2,500
Knox formations OH, NY 2,500 - 8,000 150 300 300 - 600
Niagaran Carbonate MI 4,500 - 5,500 300 600 900 - 1,500
Onondaga Limestone PA, NY 4,000 - 5,500 150 250 200 - 1,500
Oriskany Sandstone PA, NY 4,500 - 7,000 200 350 300 - 1,000
(1) The average costs for the Trenton Black River drilling are estimated based
on the Company's 2003 planned drilling. These costs vary significantly based on
the depths drilled. The average dry hole cost ranges from approximately $140,000
for a 5,000 foot well to over $1 million for wells drilled to 12,000 feet. The
average completed well cost ranges from approximately $250,000 for a 5,000 foot
well to over $1.5 million for wells drilled to 12,000 feet.
10
Drilling Results. The following table sets forth drilling results with
respect to wells drilled by the Company during the past five years:
HIGHLY DEVELOPED OR BLANKET FORMATIONS (1) DEEPER OR LESS DEVELOPED FORMATIONS (2)
------------------------------------------- ------------------------------------------
1998 1999 2000 2001 2002 1998 1999 2000 2001 2002
-------- ------ -------- -------- -------- ------- ------- ------- ------- --------
Productive:
Gross 189 -- 108 142 83 29(3) 9(4) 17(5) 14(6) 12
Net 167.0 -- 83.6 130.6 63.7 14.2 2.1 7.2 7.4 6.2
Dry:
Gross 3 -- 3 3 1 28 9 21 16 16
Net 2.5 -- 2.6 3.0 0.9 15.5 2.7 10.7 8.0 8.4
Reserves developed-net
(Bcfe) 32.3 -- 15.4 20.6 15.2 3.0 0.5 2.5 2.3 1.6
Approximate cost (in
millions) $ 28.4 $ -- $ 11.5 $ 21.1 $ 13.3 $7.6 $0.8 $5.5 $3.5 $7.5
Wells in progress:
Gross -- -- -- -- -- -- -- -- -- 4
Net -- -- -- -- -- -- -- -- -- 2.0
Cost (in millions) $ -- $ -- $ -- $ -- $ -- $ -- $ -- $ -- $ -- $2.4
(1) Consists of wells drilled to the Berea and Clinton Sandstone formations in
Ohio, the Berea Sandstone, Devonian Brown Shale, Ravencliff Sandstone and
Big Lime Limestone formations in West Virginia, the Clarendon, Upper
Devonian, Coalbed Methane and Medina formations in Pennsylvania, the Medina
Sandstone formation in New York, the New Albany Shale formation in Kentucky
and the Antrim Shale formation in Michigan.
(2) Consists of wells drilled to the Trenton Black River Carbonates and Knox
formations in Ohio, the Niagaran and Dundee Carbonates in Michigan, the
Trenton Black River Carbonates, Oriskany Sandstone and Onondaga Limestone
formations in Pennsylvania, and the Oriskany Sandstone, Onondaga Limestone,
Trenton Black River Carbonates and Knox formations in New York.
(3) Two additional wells which were dry in the Knox formations were subsequently
completed in the shallower Clinton formation.
(4) One additional well which was dry in the Knox formations was subsequently
completed in shallower formations.
(5) Three additional wells which were dry in the Knox formations were
subsequently completed in the shallower Clinton formation.
(6) Two additional wells which were dry in the Knox formations were subsequently
completed in the shallower Clinton formation. One additional well which was
dry in the Trenton Black River formation was subsequently completed in the
shallower Clinton formation.
ACQUISITION OF PRODUCING PROPERTIES
From 1992 through 1998, the Company completed 46 acquisition
transactions adding 235 Bcfe of proved developed reserves for a combined
purchase price allocated to proved developed reserves of approximately $158
million. Despite several attractive opportunities, the Company was unable to
make any significant acquisitions in 1999 because of a lack of available
capital. During 2000, much of the Company's available capital was used to pay
down debt and restart its drilling program. In 2001, the Company completed two
acquisition transactions adding 1.9 Bcfe of proved developed reserves for a
combined purchase price allocated to proved developed reserves of approximately
$1.7 million. The primary transaction in 2001 was the purchase of the remaining
40% working interest in a CBM project giving the Company 100% ownership of the
project.
11
In 2002, the Company completed one acquisition transaction adding 4.2
Bcfe of proved developed reserves for a purchase price allocated to proved
developed reserves of approximately $1.2 million. The Company previously held a
production payment on these properties through December 31, 2002.
In February 2003, the Company purchased reserves in certain wells the
Company operates in Michigan for $3.75 million in cash. These properties were
subject to a prior monetization transaction of the Section 29 tax credits which
the Company entered into in 1996. The Company had the option to purchase these
properties beginning in 2003. The Company previously held a production payment
on these properties including a 75% reversionary interest in certain future
production. The Company purchased those reserve volumes beyond its currently
held production payment along with the 25% reversionary interest not owned. The
estimated volumes acquired were 4.4 Bcf of proved developed producing gas
reserves. For the remainder of 2003, the Company intends to focus on its
drilling operations, and to a lesser extent, on the acquisition of producing
properties.
DISPOSITION OF ASSETS
On December 10, 2002, the Company sold 962 oil and natural gas wells in
New York and Pennsylvania. The sale included substantially all of the Company's
Medina formation wells in New York and a smaller number of Pennsylvania Medina
wells. The properties had approximately 23 Bcfe of total proved reserves. At the
time of the sale, the Company's net production from these wells was
approximately 3.9 Mmcfe per day (4 Mcfe per day per well). The Company disposed
of these properties due to the low production volume per well and high cost
characteristics. The wells sold had proved developed reserves using SEC pricing
parameters of approximately 19.4 Bcfe and proved undeveloped reserves of
approximately 3.6 Bcfe.
The sale resulted in proceeds of approximately $16.2 million. On
December 10, 2002, the Company received $15.5 million in cash with the remaining
amount of approximately $700,000 received in February 2003. The proceeds were
used to pay down the Company's revolving credit facility. As a result of the
sale, the Company disposed of all of its properties producing from the New York
Medina formation. As a result of the disposition of the entire New York Medina
geographical/geological pool, the Company recorded a loss on the sale of $3.2
million ($1.8 million net of tax). According to SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," the disposition of this group of
wells is classified as discontinued operations. The loss on the sale of the New
York Medina wells and the related results of these properties have been
reclassified as discontinued operations for all periods presented.
During 2002, the Company completed the sale of six natural gas
compressors in Michigan to a compression services company. The proceeds of
approximately $2.0 million were used to pay down the Company's revolving credit
facility. The Company also entered into an agreement to leaseback the
compressors from the compression services company, which will provide full
compression services including maintenance and repair on these and other
compressors. Certain compressors will also be relocated to maximize compression
efficiency. A gain on the sale of $168,000 was deferred and will be amortized as
rental expense over the life of the lease.
On August 1, 2002, the Company sold oil and gas properties consisting
of 1,138 wells in Ohio that had approximately 10 Bcfe of reserves. At the time
of the sale, the Company's net production from these wells was approximately 3.1
Mmcfe per day (3 Mcfe per day per well). The Company disposed of these
properties due to the low production volume per well and high operating costs
per well. The proceeds of approximately $8.0 million were used to pay down the
Company's revolving credit facility.
12
On March 17, 2000, the Company sold the stock of Peake, a wholly-owned
subsidiary. The sale included substantially all of the Company's oil and gas
properties in West Virginia and Kentucky. The sale resulted in net proceeds of
approximately $69.2 million, which were used to reduce bank debt. At the time of
the sale, Peake represented approximately 20% of the Company's production and
proved oil and gas reserves.
The Company regularly reviews its oil and gas properties for potential
disposition.
EMPLOYEES
As of February 28, 2003, the Company had 301 full-time employees,
including 142 oil and gas exploration and production employees, 135 oilfield
service employees and 24 general and administrative employees. The Company's
management and technical staff in the categories above included 11 petroleum
engineers, two geologists and two geophysicists.
COMPETITION AND CUSTOMERS
The oil and gas industry is highly competitive. Competition is
particularly intense with respect to the acquisition of producing properties and
undeveloped acreage and the sale of oil and gas production. There is competition
among oil and gas producers as well as with other industries in supplying energy
and fuel to end-users.
The competitors of the Company in oil and gas exploration, development
and production include major integrated oil and gas companies as well as
numerous independent oil and gas companies, individual proprietors, natural gas
pipeline companies and their affiliates. Many of these competitors possess and
employ financial and personnel resources substantially in excess of those
available to the Company. Such competitors may be able to pay more for desirable
prospects or producing properties and to evaluate, bid for and purchase a
greater number of properties or prospects than the financial or personnel
resources of the Company will permit. The ability of the Company to add to its
reserves in the future will depend on the availability of capital, the ability
to exploit its current developed and undeveloped lease holdings and the ability
to select and acquire suitable producing properties and prospects for future
exploration and development.
The only customer which accounted for 10% or more of the Company's
consolidated revenues during each of the years ended December 31, 2002, 2001 and
2000 was FirstEnergy Corp., sales to which amounted to $12.9 million, $21.0
million and $21.6 million, respectively.
REGULATION
Regulation of Production. In all states in which the Company is engaged
in oil and gas exploration and production, its activities are subject to
regulation. Such regulations may extend to requiring drilling permits, spacing
of wells, the prevention of waste and pollution, the conservation of oil and
natural gas and other matters. Such regulations may impose restrictions on the
production of oil and natural gas by reducing the rate of flow from individual
wells below their actual capacity to produce which could adversely affect the
amount or timing of the Company's revenues from such wells. Moreover, future
changes in local, state or federal laws and regulations could adversely affect
the operations and economics of the Company.
Environmental Regulation. 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. These laws and
regulations may require the acquisition of a permit before
13
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 lying within wilderness, wetlands and other protected areas and impose
substantial liabilities for pollution resulting from the Company's operations.
Management believes the Company is in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on the Company.
Regulation of Sales and Transportation. The Federal Energy Regulatory
Commission regulates the transportation and sale for resale of natural gas in
interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas
Policy Act of 1978. In the past, the federal government has regulated the prices
at which oil and natural gas could be sold. Currently, sales by producers of
natural gas and all sales of crude oil and condensate in natural gas liquids can
be made at uncontrolled market prices.
Item 2. PROPERTIES
OIL AND GAS RESERVES
The following table sets forth the Company's proved oil and gas
reserves as of December 31, 2000, 2001 and 2002 determined in accordance with
the rules and regulations of the SEC. These estimates of proved reserves have
been reviewed by Wright & Company, Inc., independent petroleum engineers. Proved
reserves are the estimated quantities of oil and 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.
December 31,
-----------------------------------
2000 2001 2002
---------- --------- ----------
Estimated proved reserves
Gas (Bcf) 373.5 334.2 335.5
Oil (Mbbl) 8,653 5,587 6,574
Bcfe 425.4 367.7 375.0
The lower reserves at December 31, 2001 were primarily due to the lower
gas price at that date compared to the gas prices at December 31, 2000 and 2002.
See Note 16 to the Consolidated Financial Statements for more detailed
information regarding the Company's oil and gas reserves.
The present value of the estimated future net cash flows before income
taxes from the proved reserves of the Company as of December 31, 2002,
determined in accordance with the rules and regulations of the SEC, was $480
million ($333 million after income taxes). Estimated future net cash flows
represent estimated future gross revenues from the production and sale of proved
reserves, net of estimated costs (including production taxes, ad valorem taxes,
operating costs, development costs and additional capital investment). Estimated
future net cash flows were calculated on the basis of prices and costs estimated
to be in effect at December 31, 2002 without escalation, except where changes in
prices were fixed and readily determinable under existing contracts.
The following table sets forth the weighted average prices, including
fixed price contracts, for oil and gas utilized in determining the Company's
proved reserves. The Company does not include its
14
natural gas hedging financial instruments, consisting of natural gas swaps and
collars, in the determination of its oil and gas reserves.
December 31,
----------------------------------------
2000 2001 2002
------------ ------------ -----------
Gas (per Mcf) $ 9.73 $ 2.92 $ 4.99
Oil (per barrel) 23.41 17.85 27.81
At December 31, 2002, as specified by the SEC, the prices for oil and
natural gas used in this calculation were regional cash price quotes on the last
day of the year except for volumes subject to fixed price contracts.
Consequently, these may not reflect the prices actually received or expected to
be received for oil and natural gas due to seasonal price fluctuations and other
varying market conditions. The prices shown above are weighted average prices
for the total reserves.
The Company also calculated an alternative reserve case utilizing an
assumed NYMEX gas price of $4.00 per Mmbtu (million British thermal units) which
equated to a weighted average gas price of $4.28 per Mcf, including adjustments
for regional basis, Btu (British thermal unit) content and fixed price
contracts. The weighted average oil price in the alternative case was $25.25 per
Bbl. The alternative reserve case used all of the same assumptions as the proved
reserve case at year-end, other than pricing. Total proved reserves calculated
at the alternative prices were 371 Bcfe. Estimated future net cash flows from
these reserves had a present value (discounted at 10 percent) before income
taxes of approximately $378 million.
IMPAIRMENT OF OIL AND GAS PROPERTIES AND OTHER ASSETS
As described in Note 1 to the Consolidated Financial Statements, the
Company evaluates long-lived assets for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be recoverable. The
decline in oil and natural gas prices from 1997 to 1998 was significant and
negatively impacted the quantity and value of the Company's oil and gas
reserves. Given the impairment indicator at December 31, 1998, the Company
computed the expected future undiscounted cash flows, employing methods
consistent with those utilized to determine the estimated future net cash flows
from proved reserves discussed above. For those assets in which the sum of the
expected future undiscounted cash flows was less than the carrying amount, an
impairment loss was recognized for the difference between the fair value and the
carrying amount of the asset, with fair value determined based on discounted
cash flow analysis, sale of similar properties or recent offers for specific
assets. As a result of this evaluation, the Company recorded total impairment
charges of $160.7 million (pre-tax) in 1998, consisting of $148.0 million
relating to producing properties and related assets, $5.8 million for unproved
properties and $6.9 million relating to other long-lived assets. The magnitude
of the impairment charge was impacted by the merger with TPG in 1997, in which
the allocation of the purchase price at fair value resulted in a significant
increase in the book value of the Company's assets. No impairment was recorded
in 1999. Impairments of $477,000 and $1.4 million were recorded in 2000 and
2001, respectively. No impairment was recorded in 2002.
PRODUCING WELL DATA
As of December 31, 2002, the Company owned interests in 4,030 gross
(3,056 net) producing oil and gas wells and operated approximately 3,330 wells,
including wells operated for third parties. By operating a high percentage of
its properties, the Company is able to control expenses, capital allocation and
the timing of development activities in the areas in which it operates. In the
fourth quarter of 2002,
15
the Company's net production, excluding wells sold in 2002, was approximately 45
Mmcfe per day consisting of 39 Mmcf of natural gas and 1,000 Bbls of oil per
day.
The following table summarizes by state the Company's productive wells
at December 31, 2002:
December 31, 2002
-----------------------------------------------------------------
Gas Wells Oil Wells Total
------------------- ------------------- -------------------
State Gross Net Gross Net Gross Net
- ------------------ -------- -------- -------- -------- -------- --------
Ohio 953 770 884 811 1,837 1,581
Pennsylvania 563 433 522 521 1,085 954
New York 19 11 -- -- 19 11
Michigan 1,082 506 7 4 1,089 510
-------- -------- -------- -------- -------- --------
2,617 1,720 1,413 1,336 4,030 3,056
======== ======== ======== ======== ======== ========
ACREAGE DATA
The following table summarizes by state the Company's gross and net
developed and undeveloped leasehold acreage at December 31, 2002:
December 31, 2002
-------------------------------------------------------------------------------------
Developed Acreage Undeveloped Acreage Total Acreage
------------------------- ------------------------- -----------------------------
State Gross Net Gross Net Gross Net
- ------------------- ----------- ----------- ----------- ----------- ------------- -------------
Ohio 312,993 282,059 325,344 274,083 638,337 556,142
Pennsylvania 51,970 43,696 293,624 263,627 345,594 307,323
New York 72,300 69,612 158,662 116,124 230,962 185,736
Michigan 21,643 20,344 67,279 56,551 88,922 76,895
Indiana -- -- 8,559 8,506 8,559 8,506
West Virginia -- -- 65,556 53,273 65,556 53,273
-------- -------- -------- -------- ---------- ---------
458,906 415,711 919,024 772,164 1,377,930 1,187,875
======== ======== ======== ======== ========== =========
Item 3. LEGAL PROCEEDINGS
In February 2000, four individuals filed a suit in Chautauqua County,
New York on their own behalf and on the behalf of others similarly situated,
seeking damages for the alleged difference between the amount of lease royalties
actually paid and the amount of royalties that allegedly should have been paid.
Other natural gas producers in New York were served with similar complaints. The
Company believes the complaint is without merit and is defending the complaint
vigorously. Although the outcome is still uncertain, the Company believes the
action will not have a material adverse effect on its financial position,
results of operations or cash flows. The Company no longer owns the wells that
were subject to the suit.
In April 2002, the Company was notified of a claim by an overriding
royalty interest owner in Michigan alleging the underpayment of royalty
resulting from disputes as to the interpretation of the terms of several farmout
agreements. The Company believes there will be no material amount payable above
and beyond the amount accrued as of December 31, 2002 and therefore, the result
will have no material adverse effect on its financial position, results of
operation or cash flows.
16
The Company was audited by the state of West Virginia for the years
1996 through 1998. The state assessed taxes which the Company has contested and
filed a petition for reassessment. In February 2003, the Company was notified by
the State Tax Commissioner of West Virginia that the Company's petition for
reassessment had been denied and taxes due, plus accrued interest, are now
payable. The Company disagrees with the decision and will appeal. The Company
believes there will be no material amount payable above and beyond the amount
accrued as of December 31, 2002 and therefore, the result will have no material
adverse effect on its financial position, results of operations or cash flows.
The Company is involved in several lawsuits arising in the ordinary
course of business. The Company believes that the result of such proceedings,
individually or in the aggregate, will not have a material adverse effect on the
Company's financial position, results of operations or cash flows.
The Company was subject to binding arbitration on an issue regarding
the valuation of shares of common stock put back to the Company in 1999 pursuant
to a former executive officer's employment agreement. In March 2003, the
arbitrator ruled that the Company must repurchase 31,168 shares of common stock
for approximately $337,000 plus interest from the date of the employment
agreement. The Company will pay approximately $516,000 in 2003 based on the
ruling. The Company has reported the stock purchase as treasury stock in 2002
and has also accrued the interest amount through December 31, 2002.
Environmental costs, if any, are expensed or capitalized depending on
their future economic benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic benefits are expensed
as incurred. Expenditures that extend the life of the related property or reduce
or prevent future environmental contamination are capitalized. Liabilities
related to environmental matters are only recorded when an environmental
assessment and/or remediation obligation is probable and the costs can be
reasonably estimated. Such liabilities are undiscounted unless the timing of
cash payments for the liability are fixed or reliably determinable. At December
31, 2002, no significant environmental remediation obligation exists which is
expected to have a material effect on the Company's financial position, results
of operations or cash flows.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
There is no established public trading market for the Company's equity
securities.
The number of record holders of the Company's equity securities at
February 28, 2003 was as follows:
Number of
Title of Class Record Holders
- ---------------------------------------- --------------------
Common Stock 14
DIVIDENDS
No dividends have been paid on the Company's Common Stock.
17
Item 6. SELECTED FINANCIAL DATA
The Selected Financial Data should be read in conjunction with the
Consolidated Financial Statements at Item 15(a).
AS OF OR FOR THE YEARS ENDED DECEMBER 31,
--------------------------------------------------------------------
(IN THOUSANDS) 1998 1999 2000(2) 2001 2002(1)
-------------- ------------ ------------ ------------ ------------
CONTINUING OPERATIONS:
Revenues $ 149,981 $ 130,628 $ 104,902 $ 118,883 $ 113,920
Depreciation, depletion
and amortization 66,307 39,726 26,331 25,979 22,379
Impairment of oil and gas
properties and other assets 160,524 -- 477 1,398 --
(Loss) income from continuing
operations before extraordinary item (130,164) (17,922) 3,425 5,776 3,745
BALANCE SHEET DATA:
Working capital from continuing operations (7,129) (43,893) 2,715 12,727 (6,466)
Oil and gas properties and
gathering systems, net 300,392 267,986 212,714 223,180 220,397
Total assets 418,605 350,695 285,117 305,349 263,845
Long-term liabilities,
less current portion 354,382 303,731 286,858 284,745 251,959
Total shareholders' equity (deficit) (33,014) (51,590) (48,313) (27,279) (44,645)
(1) See Note 4 to the Consolidated Financial Statements for information on
discontinued operations.
(2) In March 2000, the Company sold Peake. See Note 4 to the Consolidated
Financial Statements.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
On March 27, 1997, the Company entered into a merger agreement with TPG
which resulted in all of the Company's common stock being acquired by TPG and
certain other investors on June 27, 1997 in a transaction accounted for as a
purchase.
The Company's principal business is producing oil and natural gas;
exploring for and developing oil and gas reserves; acquiring and enhancing the
economic performance of producing oil and gas properties; and marketing and
gathering natural gas for delivery to intrastate and interstate gas transmission
pipelines. The Company currently operates in Ohio, Pennsylvania, New York,
Michigan, Indiana and West Virginia. The Company provides oilfield services to
its own operations and to third parties. Oilfield services provided to the
Company's own operations are provided at cost and all intercompany revenues and
expenses are eliminated in consolidation.
CRITICAL ACCOUNTING POLICIES
The Company prepares its consolidated financial statements in
accordance with accounting principles generally accepted in the United States
("GAAP") and SEC guidance. See the "Notes to Consolidated Financial Statements"
included in "Item 8. Financial Statements and Supplementary Data" for a
comprehensive discussion of the Company's significant accounting policies. GAAP
requires information in financial statements about the accounting principles and
methods used and the risks and uncertainties inherent in significant estimates
including choices between acceptable methods. Following is a discussion of the
Company's most critical accounting policies:
18
SUCCESSFUL EFFORTS METHOD OF ACCOUNTING
The accounting for and disclosure of oil and gas producing activities
requires the Company's management to choose between GAAP alternatives and to
make judgments about estimates of future uncertainties.
The Company utilizes the "successful efforts" method of accounting for
oil and gas producing activities as opposed to the alternate acceptable "full
cost" method. Under the successful efforts method, property acquisition and
development costs and certain productive exploration costs are capitalized while
non-productive exploration costs, which include certain geological and
geophysical costs, exploratory dry hole costs and costs of carrying and
retaining unproved properties, are expensed as incurred.
The major difference between the successful efforts method of
accounting and the full cost method is under the full cost method of accounting,
such exploration costs and expenses are capitalized as assets, pooled with the
costs of successful wells and charged against the net income (loss) of future
periods as a component of depletion expense. During 2002, 2001 and 2000, the
Company recognized exploration expense of $16.3 million, $8.3 million and $8.5
million, respectively, under the successful efforts method.
OIL AND GAS RESERVES
The Company's proved developed and proved undeveloped reserves are all
located within the Appalachian and Michigan Basins in the United States. The
Company cautions that there are many uncertainties inherent in estimating proved
reserve quantities and in projecting future production rates and the timing of
development expenditures. In addition, estimates of new discoveries are more
imprecise than those of properties with a production history. Accordingly, these
estimates are expected to change as future information becomes available.
Material revisions of reserve estimates may occur in the future, development and
production of the oil and gas reserves may not occur in the periods assumed and
actual prices realized and actual costs incurred may vary significantly from
assumptions used. Proved reserves represent estimated quantities of natural gas
and oil that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered through
wells and equipment in place and under operating methods being utilized at the
time the estimates were made. The accuracy of a reserve estimate is a function
of:
-- the quality and quantity of available data;
-- the interpretation of that data;
-- the accuracy of various mandated economic assumptions; and
-- the judgment of the persons preparing the estimate.
The Company's proved reserve information included in this Report is
based on estimates it prepared. Estimates prepared by others may be higher or
lower than the Company's estimates. The Company's estimates of proved reserves
have been reviewed by independent petroleum engineers.
CAPITALIZATION, DEPRECIATION, DEPLETION AND IMPAIRMENT OF LONG-LIVED ASSETS
See the "Successful Efforts Method of Accounting" discussion above.
Capitalized costs related to proved properties are depleted using the
unit-of-production method. Depreciation, depletion and amortization of proved
oil and gas properties is calculated on the basis of estimated recoverable
reserve quantities. These estimates can change based on economic or other
factors. No gains or losses are recognized upon the disposition of oil and gas
properties except in extraordinary transactions. Sales proceeds are credited to
the carrying value of the properties. Maintenance and repairs are expensed, and
expenditures which enhance the value of properties are capitalized.
19
Unproved oil and gas properties are stated at cost and consist of
undeveloped leases. These costs are assessed periodically to determine whether
their value has been impaired, and if impairment is indicated, the costs are
charged to expense. Impairments recorded in 2001 and 2000 were $179,000 and
$477,000, respectively, which reduced the book value of unproved oil and gas
properties to their estimated fair value. No impairment was recorded in 2002.
Gas gathering systems are stated at cost. Depreciation expense is
computed using the straight-line method over 15 years.
Property and equipment are stated at cost. Depreciation of non-oil and
gas properties is computed using the straight-line method over the useful lives
of the assets ranging from 3 to 15 years for machinery and equipment and 30 to
40 years for buildings. When assets other than oil and gas properties are
retired or otherwise disposed of, the cost and related accumulated depreciation
are removed from the accounts, and any resulting gain or loss is reflected in
income for the period. The cost of maintenance and repairs is expensed as
incurred, and significant renewals and betterments are capitalized.
Long-lived assets are reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount may not be
recoverable. If the sum of the expected future undiscounted cash flows is less
than the carrying amount of the asset, a loss is recognized for the difference
between the fair value and the carrying amount of the asset. In performing the
review for long-lived asset recoverability during 2001, the Company recorded
$1.2 million of impairments which reduced the book value of producing properties
to their estimated fair value. Fair value was based on management's outlook of
future oil and natural gas prices and estimated future cash flows to be
generated by the assets, discounted at a market rate of interest. No impairment
was recorded in 2002 or 2000.
DERIVATIVES AND HEDGING
On January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. As a result of the
adoption of SFAS 133, the Company recognizes all derivative financial
instruments as either assets or liabilities at fair value. Derivative
instruments that are not hedges must be adjusted to fair value through net
income (loss). Under the provisions of SFAS 133, changes in the fair value of
derivative instruments that are fair value hedges are offset against changes in
the fair value of the hedged assets, liabilities, or firm commitments, through
net income (loss). Changes in the fair value of derivative instruments that are
cash flow hedges are recognized in other comprehensive income (loss) until such
time as the hedged items are recognized in net income (loss). Ineffective
portions of a derivative instrument's change in fair value are immediately
recognized in net income (loss). Deferred gains and losses on terminated
commodity hedges will be recognized as increases or decreases to oil and gas
revenues during the same periods in which the underlying forecasted transactions
are recognized in net income (loss).
The relationship between the hedging instruments and the hedged items
must be highly effective in achieving the offset of changes in fair values or
cash flows attributable to the hedged risk both at the inception of the contract
and on an ongoing basis. The Company measures effectiveness on changes in the
hedge's intrinsic value. The Company considers these hedges to be highly
effective and expects there will be no ineffectiveness to be recognized in net
income (loss) since the critical terms of the hedging instruments and the hedged
forecasted transactions are the same. Ongoing assessments of hedge effectiveness
will include verifying and documenting that the critical terms of the hedge and
forecasted transaction do not change. The Company measures effectiveness on at
least a quarterly basis.
The Company's financial results and cash flows can be significantly
impacted as commodity prices fluctuate widely in response to changing market
conditions. To manage its exposure to natural gas
20
or oil price volatility, the Company has entered into NYMEX based commodity
derivative contracts, currently natural gas swaps and collars, and has
designated the contracts for the special hedge accounting treatment permitted
under SFAS 133. Application of hedge accounting resulted in a $19.5 million
increase in the shareholders' deficit from December 31, 2001 to the 2002
year-end, with a $4.5 million accumulated comprehensive loss recorded at
December 31, 2002. Had the Company not designated the derivative contracts as
hedges, the change in fair value of the contracts would have been reflected
directly in the statement of operations.
Prior to January 1, 2001, under the deferral method, gains and losses
from derivative instruments that qualified as hedges were deferred until the
underlying hedged asset, liability or transaction monetized, matured or was
otherwise recognized under generally accepted accounting principles. When
recognized in net income (loss), hedge gains and losses were included as an
adjustment to gas revenue or interest expense.
REVENUE RECOGNITION
Oil and gas production revenue is recognized as production and delivery
take place. Oil and gas marketing revenues are recognized when title passes.
Oilfield service revenues are recognized when the goods or services have been
provided.
NEW ACCOUNTING PRONOUNCEMENTS
On January 1, 2002, the Company adopted SFAS 142, "Goodwill and Other
Intangible Assets," which was issued in June 2001 by the FASB, and discontinued
amortization of goodwill. Under SFAS 142, goodwill and indefinite lived
intangible assets are no longer amortized but are reviewed for impairment
annually or if certain impairment indicators arise. Separately identifiable
intangible assets that are not deemed to have an indefinite life will continue
to be amortized over their useful lives (but with no maximum life).
At December 31, 2001, the Company had $2.7 million of unamortized
goodwill which was subject to the transition provisions of SFAS 142.
Amortization expense related to goodwill amounted to $130,000 and $132,000 for
the years ended December 31, 2001 and 2000, respectively. The Company assessed
the impact of SFAS 142 and has determined that adoption of SFAS 142 did not have
a material effect on the Company's financial position, results of operations or
cash flows, including any transitional impairment losses. The Company performed
its required transitional impairment test upon adoption of SFAS 142. Due to the
Company's fourth quarter disposition activity, the Company performed its annual
impairment test as of December 31, 2002. However, the Company plans to perform
its annual impairment test on a recurring basis as of October 1, starting in
fiscal 2003.
In June 2001, the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 143 addresses obligations associated with the
retirement of tangible, long-lived assets and the associated asset retirement
costs. This Statement amends SFAS 19, "Financial Accounting and Reporting by Oil
and Gas Producing Companies", and is effective for the Company's financial
statements beginning January 1, 2003. This Statement will require the Company to
recognize a liability for the fair value of its plugging and abandoning
liability (excluding salvage value) with the associated costs included as part
of the Company's oil and gas properties balance. Due to the significant number
of producing oil and gas properties operated by the Company, and the number of
documents that must be reviewed and estimates that must be made to assess the
effects of SFAS 143, it has not yet been determined whether adoption of SFAS 143
will have a material effect on the Company's financial position, results of
operations or cash flows.
In August 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which establishes a single
accounting model to be used for long-lived assets to be
21
disposed of. The new rules supersede SFAS 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Although
retaining many of the fundamental recognition and measurement provisions of SFAS
121, the new rules significantly changed the criteria that have to be met to
classify an asset as held-for-sale. This distinction is important because assets
to be disposed of are stated at the lower of their fair values or carrying
amounts and depreciation is no longer recognized. The new rules also supersede
the provisions of Accounting Principles Board Opinion No. (APB) 30, "Reporting
Results of Operations - Reporting the Effects of Disposal of a Segment of
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," with regard to reporting the effects of a disposal of a segment
of a business and require the expected future operating losses from discontinued
operations to be displayed in discontinued operations in the periods in which
the losses are incurred rather than as of the measurement date as previously
required by APB 30. In addition, more dispositions may qualify for discontinued
operations treatment in the income statement. SFAS 144 was effective as of
January 1, 2002. In applying the provisions of SFAS 144, the Company defined a
"component of an entity" as a geographical/geological pool used for depletion
purposes. As such, the disposition of all of the wells in the New York Medina
formation was classified as a discontinued operation. Well dispositions in Ohio
and Pennsylvania did not result in the liquidation of a pool, so the proceeds
from the sale of those wells reduced oil and gas properties, with no gain or
loss recognized. Results of operations relating to the Ohio and Pennsylvania
wells prior to their disposition are included in continuing operations.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from
Extinguishment of Debt," SFAS 44, "Accounting for Intangible Assets of Motor
Carriers" and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund
Requirements" and amends SFAS No. 13, "Accounting for Leases". Statement 145
also makes technical corrections to other existing pronouncements. SFAS 4
required gains and losses from extinguishment of debt to be classified as an
extraordinary item, net of the related income tax effect. As a result of the
rescission of SFAS 4, the criteria for extraordinary items in APB 30 now will be
used to classify those gains and losses. SFAS 145 is effective for the Company's
financial statements beginning January 1, 2003. The adoption of SFAS 145 is not
expected to have a material effect on the Company's financial position, results
of operations or cash flows.
In July 2002, the FASB issued SFAS 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS 146 will be effective for the
Company for disposal activities initiated after December 31, 2002. The adoption
of this standard is not expected to have a material effect on the Company's
financial position, results of operations or cash flows.
In November 2002, the FASB issued FASB Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others". FIN 45's disclosure requirements
are effective for the Company's interim and annual financial statements for
periods ending after December 15, 2002. The initial recognition and measurement
provisions are applicable on a prospective basis to guarantees issued or
modified after December 31, 2002. FIN 45 requires certain guarantees to be
recorded at fair value, which is different from current practice, which is
generally to record a liability only when a loss is probable and reasonably
estimable. FIN 45 also requires a guarantor to make significant new disclosures,
even when the likelihood of making any payments under the guarantee is remote.
Adoption of FIN 45 did not have any effect on the Company's financial statement
disclosures for the year ended December 31, 2002, and the Company does not
expect FIN 45 to have a material impact on its financial position, results of
operations or cash flows in the future.
22
RESULTS OF OPERATIONS
The following table sets forth financial data for the periods
indicated. Dollars are stated in thousands and percentages are stated as a
percentage of total revenues.
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
2002 2001 2000
------------------- ------------------- ------------------
REVENUES
Oil and gas sales $ 90,462 79.4% $ 89,491 75.3% $ 73,813 70.4%
Gas gathering, marketing, and oilfield service 21,624 19.0 27,348 23.0 27,847 26.5
Other 1,834 1.6 2,044 1.7 3,242 3.1
------------------ ------------------ ------------------
113,920 100.0 118,883 100.0 104,902 100.0
EXPENSES
Production expense 19,936 17.5 20,952 17.6 19,243 18.3
Production taxes 1,789 1.6 2,298 1.9 2,341 2.2
Gas gathering, marketing, and oilfield service 17,996 15.8 22,760 19.1 24,742 23.6
Exploration expense 16,256 14.3 8,335 7.0 8,524 8.1
General and administrative expense 4,557 4.0 4,395 3.7 4,617 4.4
Franchise, property and other taxes 91 0.1 238 0.2 379 0.4
Depreciation, depletion and amortization 22,379 19.6 25,979 21.9 26,331 25.1
Impairment of oil and gas properties
and other assets -- -- 1,398 1.2 477 0.5
Severance and other nonrecurring expense 953 0.8 1,954 1.7 241 0.2
------------------ ------------------ ------------------
83,957 73.7 88,309 74.3 86,895 82.8
------------------ ------------------ ------------------
OPERATING INCOME 29,963 26.3 30,574 25.7 18,007 17.2
OTHER (INCOME) EXPENSE
Loss (gain) on sale of businesses and other income 154 0.1 -- -- (15,064) (14.4)
Interest expense 23,608 20.7 25,753 21.7 27,892 26.6
------------------ ------------------ ------------------
INCOME FROM CONTINUING OPERATIONS BEFORE
INCOME TAXES AND EXTRAORDINARY ITEM 6,201 5.5 4,821 4.0 5,179 5.0
Provision (benefit) for income taxes 2,456 2.2 (955) (0.8) 1,754 1.7
------------------ ------------------ ------------------
INCOME FROM CONTINUING OPERATIONS BEFORE
EXTRAORDINARY ITEM 3,745 3.3 5,776 4.8 3,425 3.3
(LOSS) INCOME FROM DISCONTINUED
OPERATIONS, NET OF TAX (1,280) (1.1) 691 0.6 900 0.9
------------------ ------------------ ------------------
INCOME BEFORE EXTRAORDINARY ITEM 2,465 2.2 6,467 5.4 4,325 4.2
Extraordinary item - early extinguishment
of debt, net of tax benefit -- -- -- -- (1,364) (1.3)
------------------ ------------------ ------------------
NET INCOME $ 2,465 2.2% $ 6,467 5.4% $ 2,961 2.9%
================== ================== ==================
23
The following Management Discussion and Analysis is based on the
results of operations from continuing operations, unless otherwise noted.
Accordingly, the discontinued operations have been excluded. See Note 4 to the
Consolidated Financial Statements.
2002 COMPARED TO 2001
Operating income decreased $611,000 from $30.6 million in 2001 to $30.0
million in 2002. The operating income decreased due to higher exploration
expense and lower margins from gas gathering, marketing and oilfield services in
2002. This decrease was partially offset by higher oil and gas revenues; lower
production expenses; lower depreciation, depletion and amortization; lower
impairment expense; and lower severance expenses.
The operating margin from oil and gas sales (oil and gas sales revenues
less production expense and production taxes) on a per unit basis increased 15%
from $3.15 per Mcfe in 2001 to $3.62 per Mcfe in 2002.
Income from continuing operations before income taxes and extraordinary
items increased $1.4 million from $4.8 million in 2001 to $6.2 million in 2002.
This increase is due primarily to a decrease in interest expense in 2002
partially offset by the decrease in operating income discussed above.
Net income decreased $4.0 million from $6.5 million in 2001 to $2.5
million in 2002. The decrease in net income is primarily due to the changes in
operating income discussed above, a decrease in interest expense of $2.2
million, an increase in income taxes of $3.5 million and the increased loss from
discontinued operations of $2.0 million.
Total revenues decreased $5.0 million (4%) in 2002 compared to 2001 due
to a $5.7 million decrease in gas gathering, marketing and oilfield service
revenues as a result of a decrease in gas marketing activity and the termination
of a gas marketing contract. This was partially offset by higher gas sales
revenues.
Gas volumes sold decreased 1.3 Bcf (7%) from 17.2 Bcf in 2001 to 15.9
Bcf in 2002 resulting in a decrease in gas sales revenues of approximately $5.6
million. Oil volumes sold decreased approximately 122,000 Bbls (19%) from
644,000 Bbls in 2001 to 522,000 Bbls in 2002 resulting in a decrease in oil
sales revenues of approximately $2.8 million. The oil and gas volume decreases
were due to the sale of 202 wells in Ohio in the first quarter of 2002, 1,138
wells in Ohio in the third quarter of 2002 and 135 wells in Pennsylvania in the
fourth quarter of 2002 and the natural production decline of the wells partially
offset by production from wells drilled in 2001 and 2002. The production from
certain wells drilled in 2002 was less than expected due to unanticipated delays
in installing gathering lines and surface facilities.
The average price realized for the Company's natural gas increased
$0.60 per Mcf to $4.95 per Mcf in 2002 compared to 2001 which increased gas
sales revenues in 2002 by approximately $9.5 million. As a result of the
Company's hedging activities, gas sales revenues were increased by $21.6 million
($1.36 per Mcf) in 2002 and $4.5 million ($0.26 per Mcf) in 2001. The average
price paid for the Company's oil decreased from $23.04 per barrel in 2001 to
$22.72 per barrel in 2002 which decreased oil sales revenues by approximately
$170,000.
The operating margin from gas gathering, marketing and oilfield
services decreased $1.0 million from a margin of $4.6 million in 2001 to a
margin of $3.6 million in 2002 primarily due to the decreased gas marketing
revenue discussed above and lower gas gathering revenues as a result of
decreased gas volumes sold in 2002.
24
Other revenues include income from prior section 29 tax credit
monetization transactions which amounted to $1.3 million in 2002 and $1.4
million in 2001. These income amounts ended upon the expiration of the
non-conventional fuel source tax credit as of December 31, 2002. The Company
does not expect any income in future periods from these prior monetization
transactions.
Production expense decreased $1.1 million (5%) from $21.0 million in
2001 to $19.9 million in 2002. The average production cost increased from $1.00
per Mcfe in 2001 to $1.05 per Mcfe in 2002. The per unit increase was primarily
due to certain fixed costs spread over fewer volumes in 2002. Production taxes
decreased $509,000 from $2.3 million in 2001 to $1.8 million in 2002 primarily
due to the wells sold during 2002. Average per unit production taxes decreased
14% from $0.11 per Mcfe in 2001 to $0.09 per Mcfe in 2002 primarily due to a 12%
decrease in the selling price of natural gas in 2002 (excluding the effects of
hedging).
Exploration expense increased $8.0 million from $8.3 million in 2001 to
$16.3 million in 2002 due to a $3.4 million increase in exploratory dry holes,
increase in land leasing costs of $614,000, increase in delay rentals of $1.1
million and an increase in seismic costs of $1.5 million all of which are
primarily due to our increased exploration activities in the TBR play along with
an increase in expired or dropped leases of $1.3 million.
General and administrative expense increased $162,000 (4%) from $4.4
million in 2001 to $4.6 million in 2002 due to increases in health care costs
and other employment related expenses.
Franchise, property and other taxes decreased $147,000 from $238,000 in
2001 to $91,000 in 2002. The Company recorded a benefit of $173,000 in 2002 as a
result of the conclusion of a state franchise tax examination.
Depreciation, depletion and amortization decreased by $3.6 million from
$26.0 million in 2001 to $22.4 million in 2002. This decrease was primarily due
to a $570,000 reduction in amortization of loan costs from the extension of the
Revolver's final maturity date, a $173,000 reduction in amortization of
non-compete covenants which expired in 2001, a $323,000 reduction in the
amortization of nonconventional fuel source tax credits in 2002 and a decrease
in depletion expense. Depletion expense decreased $2.5 million (13%) from $19.2
million in 2001 to $16.7 million in 2002. Depletion per Mcfe decreased from
$0.91 per Mcfe in 2001 to $0.88 per Mcfe in 2002. These decreases were primarily
the result of a lower amortization rate per Mcfe due to higher reserves
resulting from higher oil and gas prices at year-end 2002.
Impairment of oil and gas properties and other assets decreased $1.4
million due to no impairment in 2002.
The Company recorded severance and other nonrecurring charges of $1.0
million in 2002 and $2.0 million in 2001 which were primarily related to
employment reductions. In 2002, a total of 28 positions were eliminated when the
Company combined its Pennsylvania/New York District with its Ohio District to
form a new "Appalachian District." These actions were necessary to capitalize on
operational and administrative efficiencies and bring the Company's employment
level in line with current and anticipated future staffing. The Company expects
to reduce its future expenses by approximately $1.7 million annually beginning
in the fourth quarter of 2002 as a result of the combined district and staff
reductions.
Interest expense decreased $2.2 million (8%) from $25.8 million in 2001
to $23.6 million in 2002. This decrease was due to a decrease in average
outstanding borrowings and lower blended interest rates.
25
Income tax expense increased $3.5 million from a benefit of $1.0
million in 2001 to income tax expense of $2.5 million in 2002. The increase in
expense is due to an increase in income from continuing operations and income
tax benefits of $2.7 million recorded in 2001. During 2001, the Company
concluded an IRS income tax examination of the years 1994 through 1997 and
favorably settled other tax issues. A federal income tax benefit of $2.0 million
was recorded as a result. Also during 2001, a federal income tax benefit was
recorded for approximately $700,000 along with a corresponding reduction in the
valuation allowance as a result of certain net operating loss carryforwards
which the Company now believes it can fully utilize.
Discontinued operations relating to the New York Medina wells sold
resulted in a net loss of $1.3 million in 2002 compared to net income of
$691,000 in 2001. This is primarily attributable to the $3.2 million ($1.8
million net of tax benefit) loss recorded on the sale in 2002.
2001 COMPARED TO 2000
Operating income increased $12.6 million (70%) from $18.0 million in
2000 to $30.6 million in 2001. This increase was primarily a result of a $15.5
million (28%) increase in operating margins partially offset by a $1.2 million
decrease in other revenue, a $1.7 million increase in severance and other
nonrecurring expense and a $921,000 increase in impairment of oil and gas
properties and other assets.
The increase in operating margins was primarily due to a $14.0 million
increase in the oil and gas operating margin (oil and gas sales revenues less
production expense and production taxes) primarily as a result of an increase in
the average price realized for the Company's natural gas of approximately $21.1
million ($1.23 per Mcf) and an increase in the volumes of oil sold. These
increases were partially offset by a decrease in the average price realized for
the Company's oil and by a decrease in gas volumes sold as discussed below. The
net increase in operating margins from changes in prices and volumes was
partially offset by an increase in production expense. The operating margin from
oil and gas sales on a per unit basis increased 33% from $2.37 per Mcfe in 2000
to $3.15 per Mcfe in 2001. The $1.2 million decrease in other revenue was
primarily due to a reduction in income from the monetization of nonconventional
fuel source tax credits as a result of the Peake sale and proceeds received in
the second quarter of 2000 from the settlement of a lawsuit.
Net income increased $3.5 million from $3.0 million in 2000 to $6.5
million in 2001. Gain on sale of subsidiary and other income in 2000 was $15.1
million as discussed below. Other significant changes in 2001 compared to 2000
were the $12.6 million increase in operating income discussed above, a $2.1
million decrease in interest expense, a $2.7 million decrease in provision for
income taxes, a $921,000 increase in impairment of oil and gas properties and
other assets and a $1.4 million (net of tax benefit) extraordinary loss from the
early extinguishment of debt in 2000.
Total revenues increased $14.0 million (13%) in 2001 compared to 2000
primarily as a result of a $1.23 per Mcf increase in the average price realized
for the Company's natural gas and an increase in the volumes of oil sold
partially offset by a $4.25 per Bbl decrease in the average price paid for the
Company's oil, a decrease in gas volumes sold and the decrease in other income
discussed above.
Gas volumes sold decreased 1.3 Bcf (7%) from 18.5 Bcf in 2000 to 17.2
Bcf in 2001 resulting in a decrease in gas sales revenues of approximately $4.2
million. The gas volume decrease was due to the sale of Peake in the first
quarter of 2000 and the natural production decline of the wells partially offset
by production from wells drilled in 2000 and 2001. Oil volumes sold increased
approximately 54,000 Bbls (9%) from 590,000 Bbls in 2000 to 644,000 Bbls in 2001
resulting in an increase in oil sales revenues of approximately $1.5 million.
26
The average price realized for the Company's natural gas increased
$1.23 per Mcf to $4.35 per Mcf in 2001 compared to 2000 which increased gas
sales revenues in 2001 by approximately $21.1 million. As a result of the
Company's hedging activities, gas sales revenues were increased by $4.5 million
($0.26 per Mcf) in 2001 and were reduced by $9.3 million ($0.50 per Mcf) in
2000. The average price paid for the Company's oil decreased from $27.29 per
barrel in 2000 to $23.04 per barrel in 2001 which decreased oil sales revenues
by approximately $2.7 million.
Production expense increased $1.8 million (9%) from $19.2 million in
2000 to $21.0 million in 2001. The average production cost increased from $0.87
per Mcfe in 2000 to $1.00 per Mcf in 2001. The per unit increase was primarily
due to the sale of Peake, increased compensation related expenses, additional
costs incurred in 2001 to minimize production declines in order to take
advantage of higher gas prices and general cost increases due to current market
conditions. Production taxes were $2.3 million in 2000 and 2001. Average per
unit production taxes were $0.11 per Mcfe in 2001 and 2000.
Exploration expense decreased $189,000 (2%) from $8.5 million in 2000
to $8.3 million in 2001 primarily due to a $1.1 million decrease in exploratory
dry hole expenses in 2001 compared to 2000 partially offset by $967,000 of costs
associated with increased 2001 leasing activity in exploratory areas.
General and administrative expense decreased $222,000 (5%) from $4.6
million in 2000 to $4.4 million in 2001 due to decreases in employment and
compensation related expenses.
Franchise, property and other taxes decreased $141,000 from $379,000 in
2000 to $238,000 in 2001 primarily due to an $83,000 decrease in franchise tax
and a $79,000 decrease in personal property tax from the sale of Peake in 2000,
state scheduled reduction in taxable values and lower tax rates.
Depreciation, depletion and amortization decreased by $352,000 from
$26.3 million in 2000 to $26.0 million in 2001. This decrease was primarily due
to a $930,000 reduction in amortization of loan costs from the extension of the
Revolver's final maturity date, a $680,000 reduction in amortization of
non-compete covenants due to expiration of the covenants in 2001 and a $660,000
reduction in the amortization of nonconventional fuel source tax credits in 2001
offset by an increase in depletion expense. Depletion expense increased $2.1
million (12%) from $17.1 million in 2000 to $19.2 million in 2001. Depletion per
Mcfe increased from $0.77 per Mcfe in 2000 to $0.91 per Mcfe in 2001. These
increases were primarily the result of a higher amortization rate per Mcfe due
to lower reserves resulting from lower oil and gas prices at year-end 2001.
Impairment of oil and gas properties and other assets increased
$921,000 from $477,000 in 2000 to $1.4 million in 2001.
The Company recorded a net nonrecurring charge of $2.0 million in 2001
which includes a charge of $2.3 million primarily related to the early
retirement of certain senior management members of the Company and other
severance charges incurred which included a non-cash charge of approximately
$200,000 due to the acceleration of certain related stock options. In 2001, the
Company recognized approximately $300,000 in other nonrecurring gains.
Gain on sale of subsidiaries and other income in 2000 was $15.1 million
primarily due to the $13.7 million gain on the sale of Peake and the $1.3
million gain on terminated interest rate swaps in 2000.
Interest expense decreased $2.1 million (8%) from $27.9 million in 2000
to $25.8 million in 2001. This decrease was due to a decrease in average
outstanding borrowings and lower blended interest rates. The Company's interest
expense was reduced by $141,000 in 2000 due to interest rate swaps.
27
During 2001, the Company concluded an IRS income tax examination of the
years 1994 through 1997 and favorably settled other tax issues. A federal income
tax benefit of $2.0 million was recorded as a result. Also during 2001, a
federal income tax benefit was recorded for approximately $700,000 along with a
corresponding reduction in the valuation allowance as a result of certain net
operating loss carryforwards which the Company now believes it can fully
utilize.
Income from discontinued operations declined slightly in 2001 to
$691,000 from $900,000 in the prior year due to a decrease in gas volumes sold.
LIQUIDITY AND CAPITAL RESOURCES
The Company's liquidity and capital resources are closely related to
and dependent on the current prices paid for its oil and natural gas.
The Company's current ratio at December 31, 2002 was 0.81 to 1. During
2002, working capital from continuing operations decreased $19.2 million from
$12.7 million at December 31, 2001 to a deficit of $6.5 million at December 31,
2002. The decrease was primarily due to a decrease in the fair value of
derivatives in 2002, which decreased working capital by $25.5 million, net of a
related decrease in current deferred taxes of $9.7 million and a $3.3 million
increase in accrued expenses. The Company's operating activities provided cash
flows of $50.9 million during 2002.
During 2002, amendments to the Company's $100 million revolving credit
facility extended the Revolver's final maturity date to December 31, 2005, from
April 22, 2004, increased the letter of credit sub-limit from $30 million to
$40 million and permitted the Company to enter into the transactions to sell
oil and gas properties consisting of 1,138 wells in Ohio and 962 wells in New
York and Pennsylvania.
The Revolver, as amended, is subject to certain financial covenants.
These include a quarterly senior debt interest coverage ratio of 3.2 to 1
extended through September 30, 2005; and a senior debt leverage ratio of 2.7 to
1 extended through September 30, 2005. The amendment extended the early
termination fee, equal to .125% of the Revolver, through December 31, 2004.
There is no termination fee after December 31, 2004. The Company is required to
hedge, through financial instruments or fixed price contracts, at least 20% but
not more than 80% of its estimated hydrocarbon production, on a Mcfe basis, for
the succeeding 12 months on a rolling 12-month basis. Based on the Company's
hedges currently in place and its expected production levels, the Company is in
compliance with this hedging requirement through May 2005.
The Revolver bears interest at the prime rate plus two percentage
points, payable monthly. At December 31, 2002, the interest rate was 6.25%. At
December 31, 2002, the Company had $18.4 million of outstanding letters of
credit. At December 31, 2002, the outstanding balance under the credit agreement
was $26.8 million with $54.8 million of borrowing capacity available for general
corporate purposes. As of February 28, 2003, there was $28.3 million outstanding
under the Revolver, letters of credit commitments of $40.0 million and $31.7
million available for general corporate purposes.
The Revolver is secured by security interests and mortgages against
substantially all of the Company's assets and is subject to periodic borrowing
base determinations. The borrowing base is the lesser of $100 million or the sum
of (i) 65% of the value of the Company's proved developed producing reserves
subject to a mortgage; (ii) 45% of the value of the Company's proved developed
non-producing reserves subject to a mortgage; and (iii) 40% of the value of the
Company's proved undeveloped reserves subject to a mortgage. The price forecast
used for calculation of the future net income from proved reserves is the
three-year NYMEX strip for oil and natural gas as of the date of the reserve
report. Prices beyond three years are held constant. Prices are adjusted for
basis differential, fixed price contracts and
28
financial hedges in place. The weighted average price at December 31, 2002, was
$4.14 per Mcfe. The present value (using a 10% discount rate) of the Company's
future net income at December 31, 2002, using the borrowing base price forecast
was $358 million. The present value under the borrowing base formula above, was
approximately $210 million for all proved reserves of the Company and $152
million for properties secured by a mortgage.
The Revolver is subject to certain financial covenants. These include a
senior debt interest coverage ratio of 3.2 to 1 and a senior debt leverage ratio
2.7 to 1. EBITDA, as defined in the Revolver, and consolidated interest expense
on senior debt in these ratios are calculated quarterly based on the financial
results of the previous four quarters. In addition, the Company is required to
maintain a current ratio (including available borrowing capacity in current
assets, excluding current debt and accrued interest from current liabilities and
excluding any effects from the application of SFAS 133 to other current assets
or current liabilities) of at least 1.0 to 1 and maintain liquidity of at least
$5 million (cash and cash equivalents including available borrowing capacity).
As of December 31, 2002, the Company's current ratio including the above
adjustments was 3.48 to 1. The Company had satisfied all financial covenants as
of December 31, 2002.
The Company issued $225 million of 9 7/8% Senior Subordinated Notes on
June 27, 1997. The notes mature June 15, 2007. Interest is payable semiannually
on June 15 and December 15 of each year. The notes are general unsecured
obligations of the Company and are subordinated in right of payment to senior
debt. The notes are subject to redemption at the option of the Company at
specific redemption prices.
June 15, 2002................................. 104.938%
June 15, 2003................................. 103.292%
June 15, 2004................................. 101.646%
June 15, 2005 and thereafter.................. 100.000%
The notes were issued pursuant to an indenture which contains certain
covenants that limit the ability of the Company and its subsidiaries to incur
additional indebtedness and issue stock, pay dividends, make distributions, make
investments, make certain other restricted payments, enter into certain
transactions with affiliates, dispose of certain assets, incur liens securing
indebtedness of any kind other than permitted liens and engage in mergers and
consolidations.
From time to time the Company may enter into interest rate swaps to
hedge the interest rate exposure associated with the credit facility, whereby a
portion of the Company's floating rate exposure is exchanged for a fixed
interest rate. The Company's interest expense was reduced by $141,000 in 2000
due to interest rate swaps. At December 31, 2000, the Company had no open
interest rate swap arrangements. There were no interest rate swaps in 2002 or
2001.
During 2002, the Company invested $20.8 million, including exploratory
dry hole expense, to drill 96 development wells and 16 exploratory wells. Of
these wells, 91 development wells and 4 exploratory wells were completed as
producers in the target formation, for a completion rate of 95% and 25%,
respectively (an overall completion rate of 85%). In addition, $1.2 million was
invested in proved developed reserve acquisitions and $2.4 million was spent on
4 wells in progress as of December 31, 2002, which are still being evaluated.
The Company currently expects to spend approximately $25.8 million
during 2003 on its drilling activities, including exploratory dry hole expense,
and other capital expenditures. The Company intends to finance its planned
capital expenditures through its available cash flow, available revolving credit
line and, to a lesser extent, the sale of non-strategic assets. At December 31,
2002, the Company had
29
approximately $54.8 million available under the Revolver. At February 28, 2003,
the Company had approximately $31.7 million available under the Revolver. The
level of the Company's future cash flow will depend on a number of factors
including the demand for and price levels of oil and gas, the scope and success
of its drilling activities and its ability to acquire additional producing
properties.
The Company attempted to sell a portion of its interest in certain TBR
acreage in 2002 but was unable to obtain an acceptable offer.
The Company has various commitments primarily related to leases for
office space, vehicles, natural gas compressors and computer equipment. The
Company expects to fund these commitments with cash generated from operations.
The following table summarizes the Company's contractual obligations at December
31, 2002.
PAYMENTS DUE BY PERIOD
-------------------------------------------------------------------------
CONTRACTUAL OBLIGATIONS AT LESS THAN 1 1 - 3 4 - 5 AFTER 5
DECEMBER 31, 2002 TOTAL YEAR YEARS YEARS YEARS
- ----------------------------------- ---------- ----------- ---------- ----------- ----------
(IN THOUSANDS)
Long term debt $ 252,050 $ 182 $ 26,775 $ 225,013 $ 80
Capital lease obligations 204 133 71 -- --
Operating leases 11,593 3,407 4,842 3,344 --
--------- ------- -------- --------- -----
Total contractual cash obligations $ 263,847 $ 3,722 $ 31,688 $ 228,357 $ 80
========= ======= ======== ========= ====
In addition to the items above, the Company has an employment agreement
with its Chief Executive Officer, a retirement agreement, a severance plan and a
change of control plan. See "Executive Compensation - Employment and Severance
Agreements" in Item 11 of this Report. The Company has entered into joint
operating agreements, area of mutual interest agreements and joint venture
agreements with other companies. These agreements may include drilling
commitments or other obligations in the normal course of business.
The following table summarizes the Company's commercial commitments at
December 31, 2002.
AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
---------------------------------------------------------------------
TOTAL
COMMERCIAL COMMITMENTS AT AMOUNTS LESS THAN 1 1 - 3 4 - 5 OVER 5
DECEMBER 31, 2002 COMMITTED YEAR YEARS YEARS YEARS
- -------------------------- --------- ------------ --------- --------- -----------
(IN THOUSANDS)
Standby Letters of Credit $ 18,400 $ 18,400 $ -- $ -- $ --
-------- -------- ------- -------- --------
Total Commercial Commitments $ 18,400 $ 18,400 $ -- $ -- $ --
======== ======== ======= ======== ========
In the normal course of business, the Company has performance
obligations which are supported by surety bonds or letters of credit. These
obligations are primarily site restoration and dismantlement, royalty payments
and exploration programs where governmental organizations require such support.
The Company also has letters of credit with its hedging counterparty.
The Company has certain other commitments and uncertainties related to
its normal operations, including any obligation to plug wells.
30
NATURAL GAS HEDGE POSITION MONETIZATION AND RESTRUCTURING
On January 17 and 18, 2002, the Company monetized 9,350 Bbtu (billion
British thermal units) of its 2002 natural gas hedge position at a weighted
average NYMEX price of $2.53 per Mmbtu and 3,840 Bbtu of its 2003 natural gas
hedge position at a NYMEX price of $3.01 per Mmbtu. The Company received net
proceeds of $22.7 million, a portion of which was recognized as an increase to
natural gas revenues during 2002, with the balance to be recognized in 2003
during the same periods in which the underlying forecasted transactions are
recognized in net income (loss).
In January 2002, the Company entered into a collar for 9,350 Bbtu of
its natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a
floor price of $2.25 per Mmbtu. The Company also sold a floor at $1.75 per Mmbtu
on this volume of gas. This aggregate structure had the effect of: 1) setting a
maximum price of $4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per
Mmbtu; 3) locking in a price of $2.25 per Mmbtu if prices are between $1.75 and
$2.25 per Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the price if
the price is $1.75 or less. All prices are based on monthly NYMEX settle. The
Company paid $1.0 million for the options in 2002.
The Company used the net proceeds of $21.7 million from the two
transactions above to pay down on its credit facility.
The following table summarizes, as of December 31, 2002, the Company's
deferred gains on natural gas hedges terminated in 2002. Cash has been received
and the deferred gains recorded in accumulated other comprehensive income. The
deferred gains have been or will be recognized as increases to gas revenues
during the same periods in which the underlying forecasted transactions are
recognized in net income (loss).
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
------- ------- ------- ------- -------
(IN THOUSANDS)
2002 $ 4,521 $ 5,620 $ 5,188 $ 4,560 $ 19,889
2003 723 865 771 585 2,944
To manage its exposure to natural gas or oil price volatility, the
Company may partially hedge its physical gas or oil sales prices by selling
futures contracts on the NYMEX or by selling NYMEX based commodity derivative
contracts which are placed with major financial institutions that the Company
believes are minimal credit risks. The contracts may take the form of futures
contracts, swaps, collars or options.
In March 2003, the Company entered into a costless collar for 4,320
Bbtu of its natural gas production in 2004 with a ceiling price of $5.80 per
Mmbtu and a floor price of $4.00 per Mmbtu. The Company also sold a floor at
$3.00 per Mmbtu on this volume of gas. This aggregate structure has the effect
of: 1) setting a maximum price of $5.80 per Mmbtu; 2) floating at prices from
$4.00 to $5.80 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are
between $3.00 and $4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu
above the price if the price is $3.00 or less. All prices are based on monthly
NYMEX settle.
31
The Company's financial results and cash flows can be significantly
impacted as commodity prices fluctuate widely in response to changing market
conditions. Accordingly, the Company may modify its fixed price contract
and financial hedging positions by entering into new transactions or
terminating existing contracts. The following tables reflect the natural gas
volumes and the weighted average prices under financial hedges (including
settled hedges) and fixed price contracts at March 19, 2003:
NATURAL GAS SWAPS NATURAL GAS COLLARS FIXED PRICE CONTRACTS
------------------------------------ ----------------------------------------------- -------------------------
ESTIMATED NYMEX PRICE ESTIMATED ESTIMATED
NYMEX PRICE WELLHEAD PRICE PER MMBTU WELLHEAD PRICE ESTIMATED WELLHEAD PRICE
QUARTER ENDING BBTU PER MMBTU PER MCF BBTU FLOOR/CAP(1) PER MCF (1) MMCF PER MCF
- ------------------ -------- --------- -------------- -------- ---------------- ---------------- ---------- -------------
March 31, 2003 1,800 $ 3.92 $ 4.17 1,290 $ 3.40 - 5.23 $ 3.65 - 5.48 250 $ 3.78
June 30, 2003 1,800 3.92 4.07 1,290 3.40 - 5.23 3.55 - 5.38 120 3.42
September 30, 2003 1,800 3.92 4.07 1,290 3.40 - 5.23 3.55 - 5.38 70 2.85
December 31, 2003 1,800 3.92 4.14 1,290 3.40 - 5.23 3.62 - 5.45 60 2.56
-------- --------- --------- -------- ---------------- ---------------- ------ --------
7,200 $ 3.92 $ 4.12 5,160 $ 3.40 - 5.23 $ 3.59 - 5.42 500 $ 3.42
======== ========= ========= ======== ================ ================ ====== ========
March 31, 2004 2,040 $ 3.84 $ 4.09 1,080 $ 4.00 - 5.80 $ 4.25 - 6.05 55 $ 2.60
June 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 55 2.60
September 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 55 2.60
December 31, 2004 2,040 3.84 4.06 1,080 4.00 - 5.80 4.22 - 6.02 55 2.60
-------- --------- --------- -------- ---------------- ---------------- ------ --------
8,160 $ 3.84 $ 4.03 4,320 $ 4.00 - 5.80 $ 4.19 - 5.99 220 $ 2.60
======== ========= ========= ======== ================ ================ ====== ========
March 31, 2005 1,500 $ 3.84 $ 4.09 50 $ 2.60
June 30, 2005 1,500 3.73 3.88 50 2.60
September 30, 2005 1,500 3.73 3.88 50 2.60
December 31, 2005 1,500 3.73 3.95 50 2.60
-------- --------- --------- ------ --------
6,000 $ 3.76 $ 3.95 200 $ 2.60
======== ========= ========= -===== ========
MCF - THOUSAND CUBIC FEET MMBTU - MILLION BRITISH THERMAL UNITS
MMCF - MILLION CUBIC FEET BBTU - BILLION BRITISH THERMAL UNITS
(1) The NYMEX price per Mmbtu floor/cap and the estimated wellhead price per Mcf
for the natural gas collars in 2004 assume the monthly NYMEX settles at
$3.00 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.00
per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus
$1.00 and the estimated wellhead price per Mcf will be the NYMEX settle
plus $1.15 to $1.25.
INFLATION AND CHANGES IN PRICES
During 2000, the price paid for the Company's crude oil fluctuated
between a low of $20.75 per barrel and a high of $33.25 per barrel, with an
average price of $27.29 per barrel. During 2001, the price paid for the
Company's crude oil fluctuated between a low of $13.50 per barrel and a high of
$28.50 per barrel, with an average price of $23.04 per barrel. During 2002, the
price paid for the Company's crude oil increased from $16.25 per barrel at the
beginning of the year to $27.50 per barrel at year-end, with an average price of
$22.72 per barrel. The average price of the Company's natural gas increased from
$3.12 per Mcf in 2000 to $4.35 per Mcf in 2001, then increased to $4.95 per Mcf
in 2002. These prices reflect average prices for oil and gas sales of the
Company's continuing operations. The natural gas prices include the effect of
the Company's hedging activity.
The price of oil and natural gas has a significant impact on the
Company's results of operations. Oil and natural gas prices fluctuate based on
market conditions and, accordingly, cannot be predicted. Costs to drill,
complete and service wells can fluctuate based on demand for these services
which is generally influenced by high or low commodity prices. The Company's
costs and expenses may be subject to inflationary pressures if oil and gas
prices are favorable.
32
A large portion of the Company's natural gas is sold subject to market
sensitive contracts. Natural gas price risk is mitigated (hedged) by the
utilization of over-the-counter NYMEX swaps, options or collars. Natural gas
price hedging decisions are made in the context of the Company's strategic
objectives, taking into account the changing fundamentals of the natural gas
marketplace.
FORWARD-LOOKING INFORMATION
The forward-looking statements regarding future operating and financial
performance contained in this report involve risks and uncertainties that
include, but are not limited to, the Company's availability of capital,
production and costs of operation, the market demand for, and prices of oil and
natural gas, results of the Company's future drilling, the uncertainties of
reserve estimates, environmental risks, availability of financing and other
factors detailed in the Company's filings with the SEC. Actual results may
differ materially from forward-looking statements made in this report.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Among other risks, the Company is exposed to interest rate and
commodity price risks.
The interest rate risk relates to existing debt under the Company's
revolving credit facility as well as any new debt financing needed to fund
capital requirements. The Company may manage its interest rate risk through the
use of interest rate swaps to hedge the interest rate exposure associated with
the credit agreement, whereby a portion of the Company's floating rate exposure
is exchanged for a fixed interest rate. A portion of the Company's long-term
debt consists of senior subordinated notes where the interest component is
fixed. The Company had no derivative financial instruments for managing interest
rate risks in place as of December 31, 2002 and 2001. If market interest rates
for short-term borrowings increased 1%, the increase in the Company's interest
expense would be approximately $268,000. This sensitivity analysis is based on
the Company's financial structure at December 31, 2002.
The commodity price risk relates to natural gas and crude oil produced,
held in storage and marketed by the Company. The Company's financial results can
be significantly impacted as commodity prices fluctuate widely in response to
changing market forces. From time to time the Company may enter into a
combination of futures contracts, commodity derivatives and fixed-price physical
contracts to manage its exposure to commodity price volatility. The fixed-price
physical contracts generally have terms of a year or more. The Company employs a
policy of hedging gas production sold under NYMEX based contracts by selling
NYMEX based commodity derivative contracts which are placed with major financial
institutions that the Company believes are minimal credit risks. The contracts
may take the form of futures contracts, swaps or options. If NYMEX gas prices
decreased $0.25 per Mcf, the Company's gas sales revenues would decrease by $1.9
million, after considering the effects of the hedging contracts in place at
December 31, 2002. The Company had no hedges or fixed price contracts on its oil
production during 2002. If the price of crude oil decreased $2.00 per Bbl, the
Company's oil sales revenues would decrease by $1.0 million. This sensitivity
analysis is based on the Company's 2002 oil and gas sales volumes and assumes
the NYMEX gas price would be within the collars in 2003 listed in the table on
page 32.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Index to Consolidated Financial Statements and Schedules on page
F-1 sets forth the financial statements included in this Annual Report on Form
10-K and their location herein. Schedules have been omitted as not required or
not applicable because the information required to be presented is included in
the financial statements and related notes.
33
The financial statements have been prepared by management in conformity
with accounting principles generally accepted in the United States. Management
is responsible for the fairness and reliability of the financial statements and
other financial data included in this report. In the preparation of the
financial statements, it is necessary to make informed estimates and judgments
based on currently available information on the effects of certain events and
transactions.
The Company maintains accounting and other controls which management
believes provide reasonable assurance that financial records are reliable,
assets are safeguarded and that transactions are properly recorded. However,
limitations exist in any system of internal control based upon the recognition
that the cost of the system should not exceed benefits derived.
The Company's independent auditors, Ernst & Young LLP ("E&Y"), are
engaged to audit the financial statements and to express an opinion thereon.
Their audit is conducted in accordance with auditing standards generally
accepted in the United States to enable them to report whether the financial
statements present fairly, in all material respects, the financial position and
results of operations in accordance with accounting principles generally
accepted in the United States.
The aggregate fees for professional services rendered by E&Y for the
audit of the Company's financial statements for the year ended December 31,
2002, and the reviews of the financial information included in the Company's
Form 10-Q for the year were $151,700. E&Y did not provide the Company any
financial information systems design and implementation services or any other
prohibited services during 2002. The aggregate fees for other services rendered
by E&Y in 2002, related primarily to tax compliance, tax advice and tax
planning services, were $56,200.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
34
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Executive officers and directors of the Company as of March 5, 2003
were as follows:
NAME AGE POSITION
- ---- --- --------
John L. Schwager 54 President, Chief Executive Officer and Director
Richard R. Hoffman 52 Senior Vice President Exploration and Production
Robert W. Peshek 48 Vice President Finance and Chief Financial Officer
David M. Becker 41 Vice President and General Manager, Michigan Exploration
and Production District
Duane D. Clark 47 Vice President Legal Affairs/Gas Marketing
John G. Corp 43 Vice President and General Manager, Arrow Oilfield Service
Company
Patricia A. Harcourt 39 Vice President Administration
Barry K. Lay 46 Vice President and General Manager, Appalachian Exploration
and Production District
Frederick J. Stair 43 Vice President and Corporate Controller
Lawrence W. Kellner 44 Director
Robert S. Maust 65 Director
William S. Price, III 46 Director
Gareth Roberts 50 Director
Jeffrey C. Smith 41 Director
All executive officers of the Company serve at the pleasure of its
Board of Directors. None of the executive officers of the Company is related to
any other executive officer or director. The Board of Directors consists of six
members each of whom is elected annually to serve one-year terms. The business
experience of each executive officer and director is summarized below.
JOHN L. SCHWAGER has been Chief Executive Officer of the Company since
June of 1999. Mr. Schwager was elected to the Board of Directors in August of
1999 and was appointed to the additional position of President upon the
departure of the former President in September 1999. He has over 30 years of
diversified experience in the oil and gas industry. Prior to joining the
Company, he spent two years as President of AnnaCarol Enterprises, Inc., an
energy consulting firm specializing in financial and engineering advisory
services to exploration and production sector companies. From 1984 to 1997, he
was employed by Alamco, Inc., an Appalachian Basin exploration and production
company, serving as
35
President and Chief Executive Officer from 1987 to 1997; Executive Vice
President from May 1987 to October 1987; and, Senior Vice President - Operations
from 1984 to 1987. He also served as Chairman of the Board of TGX Corporation
and led TGX out of bankruptcy in 1992. From 1980 to 1984, Mr. Schwager was
employed as the Vice President of Production for Callon Petroleum Company in
Natchez, Mississippi. From 1970 to 1980, he worked for Shell Oil Company in New
Orleans in both engineering and supervisory positions. He last worked at Shell
as a Division Drilling Superintendent in the Offshore Division.
Mr. Schwager graduated from the University of Missouri at Rolla in 1970
with a Bachelor of Science Degree in Petroleum Engineering. He is a past
president and director of the Independent Oil and Gas Association of West
Virginia and is currently a member of the Ohio Oil and Gas Association. He also
was the cofounder of the Oil and Gas Political Action Committee of West
Virginia, serving as co-chairman for many years.
RICHARD R. HOFFMAN joined the Company as Senior Vice President of
Exploration and Production in March of 2001. Mr. Hoffman has worked in the oil
and gas industry for 30 years and has extensive operational experience in the
Appalachian Basin. From 1998 to 2000, he served as Manager of Production for
Dominion Appalachian Development Inc., a subsidiary of Dominion Resources, Inc.,
specializing in natural gas exploration and production. From 1982 to 1997, he
was Executive Vice President and Chief Operating Officer of Alamco, Inc., and
served on its Board of Directors from 1988 to 1997. Mr. Hoffman served as
Superintendent Production and Drilling/Field Engineer for Cabot Oil and Gas
Corporation from 1980 to 1982, and from 1977 to 1980 he was employed by Flint
Oil and Gas, Inc., as a Field Engineer. From 1973 to 1977, he held the title of
Assistant Production Superintendent/Engineer with The Wiser Oil Company.
Mr. Hoffman graduated from West Virginia University with a Bachelor of
Science degree in Geology. He is affiliated with numerous oil and gas
associations including the Ohio Oil and Gas Association, the West Virginia Oil
and Natural Gas Association and the Independent Oil and Gas Association of West
Virginia where he served as a Director from 1995 to 1997. He is also a member of
the Society of Petroleum Engineers.
ROBERT W. PESHEK has served as Vice President of Finance for the
Company since 1997 and in 1999 was appointed Chief Financial Officer.
Previously, he served as Corporate Controller and Tax Manager from 1994 to 1997.
Prior to joining the Company, Mr. Peshek served as a Senior Manager of the Tax
Department at Ernst & Young LLP from 1981 to 1994. He is a Certified Public
Accountant with extensive experience in taxation, finance, accounting and
auditing. Mr. Peshek holds a Bachelor of Business Administration degree in
Accounting from Kent State University where he graduated with honors. His
professional affiliations include the American Institute of Certified Public
Accountants and the Ohio Society of Certified Public Accountants. Mr. Peshek is
a member of the Ohio Oil and Gas Association.
DAVID M. BECKER was appointed Vice President of the Company in May
2000, and has been President and Chief Operating Officer of Ward Lake Drilling,
Inc., a wholly-owned subsidiary of the Company, and General Manager of the
Michigan Exploration and Production District since 1995. Mr. Becker joined the
Company as a result of the acquisition of Ward Lake in February of 1995. He
worked for Ward Lake Energy, Inc. from 1988 to 1995, serving most recently as
President and COO. Previously, he served as Facility Engineer for Shell Oil
Company in New Orleans, Louisiana from 1984 to 1988. He has 21 years of
experience in the oil and gas industry. Mr. Becker received his Bachelor of
Science degree in Mechanical Engineering from Michigan Technical University. His
professional affiliations include the Michigan Oil and Gas Association and the
American Petroleum Institute.
36
DUANE D. CLARK has been Vice President of Legal Affairs/Gas Marketing
for the Company since April 2001. Previously, he served as Vice President of Gas
Marketing. He joined the Company in 1995 as a Gas Marketing Analyst. Prior to
joining the Company, Mr. Clark held various management positions with Quaker
State Corporation from 1978 to 1995. He has 24 years of experience in the oil
and gas industry. Mr. Clark received his Bachelor of Arts degree in Mathematics
and Economics from Ohio Wesleyan University. His professional affiliations
include the Ohio Oil and Gas Association and the Pennsylvania Oil and Gas
Association.
JOHN G. CORP was appointed Vice President of the Company in May 2000,
and has been the General Manager of Arrow Oilfield Service Company, the
Company's oilfield service division, since November 1999. Prior to that he
served as General Manager of the Company's Southern Ohio Exploration and
Production District from 1987 to 1999. Mr. Corp joined the Company as a
Petroleum Engineer. Previously he worked for Park-Ohio Energy as
Drilling/Production Engineer from 1979 to 1986. Mr. Corp has 24 years of
experience in the oil and gas industry. He attended Marietta College where he
received a Bachelor of Science degree in Petroleum Engineering. He is a member
of the Society of Petroleum Engineers, the Ohio Oil and Gas Association and a
member of the Technical Advisory Committee for the Ohio Department of Natural
Resources.
PATRICIA A. HARCOURT was appointed Vice President of Administration of
the Company in January 2003. Previously she served as Director of Administration
from 2001 to 2003. She joined the Company in 1988 as Investor Relations
Coordinator. Prior to joining the company, Ms. Harcourt was employed by Austin
Powder Company as Employee Relations Administrator. She received her Bachelor of
Arts degree in Communications from Bowling Green State University. She has 15
years of experience in the oil and gas industry and is a member of the Ohio Oil
and Gas Association. Ms. Harcourt is also a member of the national chapter and
the Cleveland/Akron chapter of the National Investor Relations Institute.
BARRY K. LAY was appointed Vice President of the Company in January
2003, and has served as General Manager of the Company's Appalachian Exploration
and Production District since October 2002. He joined the Company in March of
2002 as General Manager of the Pennsylvania/New York Exploration and Production
District. Prior to joining the Company, Mr. Lay served in various management
capacities with Waco Oil and Gas Company and most recently held the title of
Vice President of Engineering. From 1979 to 1986, he was employed as a Petroleum
Engineer and Land Manager for Key Oil Company. Mr. Lay has 25 years of
experience in the oil and gas industry. He graduated from West Virginia
University with a Bachelor of Science degree in Petroleum Engineering. He is
affiliated with numerous oil and gas regulatory boards including the West
Virginia Oil and Gas Conservation Commission, West Virginia Coal Bed Methane
Review Board and the West Virginia Shallow Gas Well Review Board. He is a
registered Professional Engineer and a licensed Land Surveyor in the State of
West Virginia.
FREDERICK J. STAIR was appointed Vice President of the Company in
January 2003 and has been the Corporate Controller since 1997. Prior to that
date he served as Controller of the Exploration and Production Division from
1991 to 1997. Mr. Stair joined the Company in 1981 and has 22 years of
accounting experience in the oil and gas industry. He graduated from the
University of Akron where he received a Bachelor of Science degree in
Accounting. Mr. Stair is a member of Ohio Petroleum Accountants Society.
LAWRENCE W. KELLNER has been a director since 1997. He has been
President of Continental Airlines, Inc. since May 2001. He was Executive Vice
President and Chief Financial Officer of Continental Airlines, Inc. from
November 1996 to May 2001. Mr. Kellner graduated magna cum laude with a Bachelor
of Science, Business Administration degree from the University of South
Carolina. Mr. Kellner is also a director of Continental Airlines, Inc. and
Mariott International, Inc.
37
ROBERT S. MAUST has been a director since February 2001. He is the
Louis F. Tanner Distinguished Professor of Public Accounting at West Virginia
University where he has been the Director of the Division of Accounting since
1987. He has been a professor at the University since 1963 and has received
numerous teaching and professional honors during his 40-year career. He has
published several papers and has contributed to various books and manuals on
accounting and business. Mr. Maust is a Certified Public Accountant and has
served as an officer of several state, regional and national professional
organizations. He received his Bachelor and Master degrees from West Virginia
University and Certificate of Ph.D. Candidacy from the University of Michigan.
From 1987 to 1997, he served on the Board of Directors of Alamco, Inc., an
Appalachian Basin-based firm engaged in the acquisition, exploration,
development and production of domestic gas and oil.
WILLIAM S. PRICE, III, who became a director upon TPG's investment in
1997, was a founding partner of Texas Pacific Group in 1992. Prior to forming
Texas Pacific, Mr. Price was Vice President of Strategic Planning and Business
Development for G.E. Capital, reporting to the Chairman. In this capacity, Mr.
Price was responsible for acquiring new business units and determining the
business and acquisition strategies for existing businesses. From 1985 to 1991,
Mr. Price was employed by the management consulting firm of Bain & Company,
attaining officer status and acting as co-head of the Financial Services
Practice. Prior to 1985, Mr. Price was employed as an associate specializing in
corporate securities transactions with the legal firm of Gibson, Dunn &
Crutcher. Mr. Price is a member of the California Bar and graduated with honors
in 1981 from the Boalt Hall School of Law at the University of California,
Berkeley. He is a 1978, Phi Beta Kappa graduate of Stanford University. Mr.
Price serves on the Board of Directors of Continental Airlines, Inc., Del Monte
Foods Company, Denbury Resources, Inc., Gemplus International, S.A., and several
private companies.
GARETH ROBERTS has been a director since 1997. He has been President,
Chief Executive Officer and a director of Denbury Resources, Inc. ("Denbury")
since 1992. Mr. Roberts founded Denbury Management, Inc., the former operating
subsidiary of Denbury in April 1990. Mr. Roberts has more than 28 years of
experience in the exploration and development of oil and gas properties with
Texaco, Inc., Murphy Oil Corporation and Coho Resources, Inc. His expertise is
particularly focused in the Gulf Coast region where he specializes in the
acquisition and development of old fields with low productivity. Mr. Roberts
holds honors and masters degrees from St. Edmund Hall, Oxford University, where
he has been elected to an Honorary Fellowship. Mr. Roberts also serves as
chairman of the board of directors of Genesis Energy, L.P.
JEFFREY C. SMITH has been a director since February 2001. He joined the
Texas Pacific Group in 2000 in the capacity of Portfolio Operations Manager. Mr.
Smith has 11 years of experience in management consulting, serving most recently
as a Strategy Consultant for the management consulting firm of Bain & Company
from 1993 to 1999. He was employed by the consulting firms of The L/E/K
Partnership and McKinsey & Co., from 1991 to 1993. From 1987 to 1990, he was
employed by Exxon USA as a Senior Engineer and from 1985 to 1986, he conducted
Academic Research at the Research and Development Division of Conoco, Inc. He
received his Bachelor of Science and Master of Science degrees in Petroleum
Engineering from the University of Texas. Mr. Smith received his Master of
Business Administration degree from the Wharton School of Business.
38
Item 11. EXECUTIVE COMPENSATION
The following table shows the annual and long-term compensation for
services in all capacities to the Company during the fiscal years ended December
31, 2002, 2001 and 2000 of the Company's Chief Executive Officer and its other
four most highly compensated executive officers.
SUMMARY COMPENSATION TABLE
LONG-TERM
COMPENSATION
ANNUAL COMPENSATION AWARDS
------------------------------------------------- --------------
NO. OF SHARES
OTHER ANNUAL UNDERLYING ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION OPTIONS/SARS COMPENSATION(1)
- -----------------------------------------------------------------------------------------------------------------------------
John L. Schwager 2002 $ 325,000 $573,750(3) $ -- -- $10,500
President and 2001 317,692 292,277 -- 100,000 8,500
Chief Executive Officer 2000 308,654 157,500 -- 66,692 8,500
Richard R. Hoffman (4) 2002 198,000 39,600 -- -- 5,000
Senior Vice President of 2001 145,385 83,769 -- 82,500 43,742(2)
Exploration and Production
Robert W. Peshek 2002 168,308 58,910 -- -- 9,187
Vice President of Finance and 2001 164,915 90,703 -- 17,500 8,500
Chief Financial Officer 2000 144,721 40,851 -- 27,500 8,500
David M. Becker 2002 154,707 23,200 -- -- 9,187
Vice President of 2001 139,644 41,893 -- -- 7,831
Michigan Operations 2000 128,180 33,181 -- 10,000 6,809
Duane D. Clark 2002 103,310 36,160 -- -- 7,953
Vice President of Legal 2001 101,371 55,754 -- -- 6,328
Affairs and Gas Marketing 2000 91,217 25,197 -- -- 4,561
(1) Represents contributions of cash and common stock to the Company's 401(k)
Profit Sharing Plan for the account of the named executive officer.
(2) Includes moving expenses of $41,373.
(3) This consists of an annual performance bonus of $243,750 and an annual
retention bonus of $330,000 paid to Mr. Schwager on June 30, 2002. For
financial statement purposes the Company has accrued an additional bonus of
$165,000 for the period July 1, 2002 through December 31, 2002.
(4) Mr. Hoffman joined the Company in March 2001.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION/SAR VALUES
NUMBER OF SHARES VALUE OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY
SHARES OPTIONS/SARs AT FY-END OPTIONS/SARs AT FY-END
ACQUIRED ON VALUE --------------------------------- -------------------------------
NAME EXERCISE REALIZED EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---------------------- ----------- -------- ----------- ------------- ----------- -------------
John L. Schwager 65, 337 $134,812 19,316 119,873 $ 26,960 $79,144
Richard R. Hoffman -- -- 20,625 61,875 -- --
Robert W. Peshek -- -- 54,219 32,031 102,387 38,551
David M. Becker -- -- 18,125 6,875 37,232 14,019
Duane D. Clark -- -- 23,125 6,875 47,882 14,019
39
COMPENSATION OF DIRECTORS
The outside directors of the Company are compensated $7,500 per quarter
for their services. Directors employed by the Company or by TPG are not
compensated for their services.
EMPLOYMENT AND SEVERANCE AGREEMENTS
Effective July 1, 2001, John Schwager's employment agreement with the
Company was amended and restated (the "Agreement"). The term of the Agreement is
for three years, subject to extension by mutual agreement.
Under the Agreement, Mr. Schwager is entitled to base compensation of
$325,000 per annum beginning July 1, 2001 with an increase of $25,000 beginning
on January 1, 2003. The Agreement provides for an incentive based bonus, at the
discretion of the Board of Directors, of up to 100% of base compensation. There
is no minimum incentive based bonus established in the Agreement. The Agreement
also provides for an annual retention bonus of $330,000 each year during the
term of the Agreement. The annual retention bonus is accelerated and payable in
the event of change in control which is defined as any occurrence which would
cause TPG's fully diluted equity ownership to drop below 35%. The Agreement
further provides for a special retention bonus of $1,000,000, should a change of
control occur during or within six months after the expiration of the Agreement,
unless Mr. Schwager is employed as the chief executive officer of the surviving
company.
Either Mr. Schwager or the Company may terminate the Agreement at any
time, with or without cause. If Mr. Schwager terminates his employment or is
removed for cause, he will not be entitled to receive any compensation or
severance pay except for the base compensation, benefits, bonuses and expense
reimbursements that have accrued up to and including the final day of his
employment with the Company. If the Company terminates Mr. Schwager's employment
without cause or if he resigns for good reason (as defined in the Agreement),
Mr. Schwager will be entitled to receive monthly payments of 150% of his base
salary plus the remaining annual retention bonus payments and continued health
care benefits at the Company's expense for two years. In the event of a change
of control, all of the aforementioned payments become due and payable at the
closing. With the exception of the cost of health care benefits, the amounts
payable to Mr. Schwager as outlined above cannot exceed $1,990,000. Mr. Schwager
is also entitled to receive an additional payment plus any associated interest
and penalties (the "gross up") sufficient to cover any tax imposed by Section
4999 of the Internal Revenue Code on payments made under the Agreement.
On February 7, 2001, Mr. Schwager was granted an option to purchase
25,000 shares of the common stock of the Company at $3.59 per share which were
repriced on December 5, 2001 at $2.14 per share. He was also granted an option
to purchase 75,000 shares of the common stock of the Company on December 5, 2001
at $2.14 per share. One fourth of the option shares shall become exercisable on
the last day of each calendar quarter commencing June 30, 2003, provided that he
is then an employee or director of the Company.
On December 21, 2001, the Company and Leo A. Schrider entered into a
Letter of Agreement for Mr. Schrider's transition into retirement. During the
transition period from January 2, 2002 through December 31, 2003, Mr. Schrider
will work as a part-time employee of the Company, performing such duties as may
be assigned. During the transition period, Mr. Schrider will be entitled to
receive the full base salary per year that he was receiving as of December 31,
2001.
Under the Company's 1999 Severance Pay Plan, all employees whose
employment is terminated by the Company without "cause" (as defined therein) are
eligible to receive severance benefits ranging from four weeks to twenty-four
months, depending on their years of service and position with the
40
Company. Under the Plan, Messrs. Becker, Clark, Hoffman and Peshek would be
eligible to receive severance pay ranging from twelve months to twenty-four
months.
The Company has a 1999 Change in Control Protection Plan for Key
Employees providing severance benefits for such employees if, within six months
prior to a change in control or within two years thereafter, their employment is
terminated without "cause" (as defined therein) or if they resign in response to
a reduction in duties, responsibilities, position, compensation or medical
benefits or a change in the location of their place of work as defined in the
agreement. Such benefits range from twelve months to twenty-four months,
depending on their position with the Company. Under the Plan, Messrs. Becker,
Clark, Hoffman and Peshek would be eligible to receive severance pay of
twenty-four months.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
The Compensation and Organization Committee consisted of two outside
directors, William S. Price, III and Gareth Roberts. No executive officer of the
Company was a director or member of a compensation committee of any entity of
which a member of the Company's Board of Directors was or is an executive
member.
41
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The following table sets forth certain information as of February 28,
2003 regarding the beneficial ownership of the Company's common stock by each
person who beneficially owns more than five percent of the Company's outstanding
common stock, each director, the chief executive officer and the four other most
highly compensated executive officers and by all directors and executive
officers of the Company, as a group:
FIVE PERCENT SHAREHOLDERS NUMBER OF SHARES PERCENTAGE OF SHARES
- --------------------------------------------------------------- ---------------- --------------------
TPG Advisors II, Inc.
201 Main Street, Suite 2420
Fort Worth, Texas 76102 9,353,038 (1) 88.1%
State Treasurer of the State of Michigan, Custodian of the
Public School Employees' Retirement System, State Employees
Retirement System, Michigan State Police Retirement System
and Michigan Judges Retirement System
430 West Allegan
Lansing, MI 48922 554,376 5.2%
OFFICERS AND DIRECTORS
- ---------------------------------------------------------------
William S. Price, III 9,353,038 (1) 88.1%
John L. Schwager 182,841 (2) 1.7%
Lawrence W. Kellner -0- -0-
Gareth Roberts -0- -0-
Robert S. Maust -0- -0-
Jeffrey C. Smith -0- -0-
Richard R. Hoffman 25,781 (2) *
Robert W. Peshek 74,219 (2) *
David M. Becker 25,000 (2) *
Duane D. Clark 25,000 (2) *
All directors and executive
officers (14) as a group 9,723,950 91.6%
* Less than 1%
(1) Neither TPG Advisors II, Inc. nor Mr. Price is the record owner of any
shares of the Company's common stock. Mr. Price is, however, a director,
executive officer and shareholder of TPG Advisors II, Inc., which is the
general partner of TPG GenPar II, L.P., which in turn is the general partner
of each of TPG Partners II, L.P., TPG Investors II, L.P. and TPG Parallel
II, L.P. which are the direct beneficial owners of 7,976,645, 832,047 and
544,346 shares of common stock, respectively.
(2) Consists of shares subject to stock options exercisable within 60 days by
Mr. Schwager as to 13,067 shares, Mr. Hoffman as to 25,781 shares, Mr.
Peshek as to 60,469 shares, Mr. Becker as to 20,000 shares and Mr. Clark as
to 25,000 shares.
42
EQUITY COMPENSATION PLAN INFORMATION:
NUMBER OF SECURITIES
REMAINING AVAILABLE
NUMBER OF SECURITIES WEIGHTED- FOR FUTURE ISSUANCE
TO BE ISSUED AVERAGE UNDER EQUITY
UPON EXERCISE OF EXERCISE PRICE OF COMPENSATION PLANS
OUTSTANDING OPTIONS OUTSTANDING OPTIONS (EXCLUDING SECURITIES
PLAN CATEGORY WARRANTS AND RIGHTS WARRANTS AND RIGHTS REFLECTED IN COLUMN (a))
- ---------------------------------- -------------------- ------------------- -----------------------
(a) (b) (c)
Equity compensation plans approved
by security holders - $ - -
Equity compensation plans not
approved by security holders 684,456 $ 1.09 810,113
The Company has a 1997 non-qualified stock option plan under which it
is authorized to issue up to 1,824,195 shares of common stock to officers and
employees. The exercise price of options may not be less than the fair market
value of a share of common stock on the date of grant. Options expire on the
tenth anniversary of the grant date unless cessation of employment causes
earlier termination. As of December 31, 2002, options to purchase 684,456 shares
were outstanding under the plan. These options, except for the 100,000 options
described below, become exercisable at a rate of one fourth of the shares one
year from the date of grant and an additional one twelfth of the remaining
shares on every three-month anniversary thereafter. The remaining 100,000
options become exercisable at a rate of one fourth of the shares on the last day
of each quarter commencing June 30, 2003.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In connection with the merger with TPG in 1997, the Company entered
into a Transaction Advisory Agreement with TPG Partners II, L.P. pursuant to
which TPG Partners II, L.P. received a cash financial advisory fee of $5.0
million upon the closing of the merger as compensation for its services as
financial advisor in connection with the merger. TPG Partners II, L.P. also will
be entitled to receive (but, at its discretion, may waive) fees of up to 1.5% of
the "transaction value" for each subsequent transaction (a tender offer,
acquisition, sale, merger, exchange offer, recapitalization, restructuring or
other similar transaction) in which the Company is involved. The term
"transaction value" means the total value of any subsequent transaction,
including, without limitation, the aggregate amount of the funds required to
complete the subsequent transaction (excluding any fees payable pursuant to the
Transaction Advisory Agreement and fees, if any, paid to any other person or
entity for financial advisory, investment banking, brokerage or any other
similar services rendered in connection with such transaction) including the
amount of any indebtedness, preferred stock or similar items assumed (or
remaining outstanding). The Transaction Advisory Agreement shall continue until
the earlier of (i) 10 years from the execution date or (ii) the date on which
TPG Partners II, L.P. and its affiliates cease to own, beneficially, directly or
indirectly, at least 25% of the voting power of the securities of the Company.
TPG has advised the Company that it has waived its fees under this
agreement for acquisition and sale transactions in all prior years. TPG will be
paid a transaction fee pursuant to this agreement for the $16.2 million sale of
the properties in New York and Pennsylvania. The fee, which was accrued in 2002,
is approximately $230,000 and will be paid in 2003. TPG waived the fee on all
other acquisition and sale transactions in 2002.
43
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 Company's Chief Executive Officer and
Chief Financial 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 upon the evaluation, the Chief Executive Officer and Chief
Financial Officer concluded that the Company's disclosure controls and
procedures were effective as of December 31, 2002. There have been no
significant changes in the Company's internal controls or in other factors that
could significantly affect internal controls subsequent to December 31, 2002.
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Documents filed as a part of this report:
1. Financial Statements
The financial statements listed in the accompanying Index to
Consolidated Financial Statements and Schedules are filed as part of this Annual
Report on Form 10-K.
2. Financial Statement Schedules
No financial statement schedules are required to be filed as part of
this Annual Report on Form 10-K.
3. Exhibits
NO. DESCRIPTION
- --- -----------
2.1 Agreement and Plan of Merger dated as of March 27, 1997 by and among TPG Partners II, BB Merger Corp. and Belden &
Blake Corporation--incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-4
(Registration No. 333-33407).
3.1 Amended and Restated Articles of Incorporation of Belden & Blake Corporation (fka Belden & Blake Energy
Corporation)--incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4
(Registration No. 333-33407).
3.2 Code of Regulations of Belden & Blake Corporation--incorporated by reference to Exhibit 3.2 to the Company's
Registration Statement on Form S-4 (Registration No. 333-33407).
4.1 Indenture dated as of June 27, 1997 between the Company, the Subsidiary Guarantors and LaSalle National Bank, as
trustee, relating to the Notes--incorporated by reference to Exhibit 4.1 to the Company's Registration Statement
on Form S-4 (Registration No. 333-33407).
44
NO. DESCRIPTION
- --- -----------
4.2 Registration Rights Agreement dated as of June 27, 1997 between the Company, the Guarantors and Chase Securities,
Inc.--incorporated by reference to Exhibit 4.2 to the Company's Registration Statement on Form S-4 (Registration
No. 333-33407).
4.3 Form of 9 7/8% Senior Subordinated Notes due 2007, Original Notes (included in Exhibit 4.1)--incorporated by
reference to Exhibit 4.3 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407).
4.4 Form of 9 7/8% Senior Subordinated Notes due 2007, Exchange Notes (included in Exhibit 4.1)--incorporated by
reference to Exhibit 4.4 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407).
10.1(a) Peake Energy, Inc. Stock Purchase Agreement between the Company and North Coast Energy, Inc. --incorporated by
reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000.
10.1(b) Credit Agreement dated as of August 23, 2000 by and among the Company, Ableco Finance LLC and Foothill Capital
Corporation. --incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2000.
10.1(c) Amendment to the Credit Agreement dated as of June 29, 2001 by and among the Company, Ableco Finance LLC and
Foothill Capital Corporation.--incorporated by reference to Exhibit 10.1(c) to the Company's Annual Report on Form
10-K for the year ended December 31, 2001.
10.1(d) Amendment to the Credit Agreement dated as of July 25, 2002 by and among the Company, Ableco Finance LLC and
Foothill Capital Corporation.--incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form
10-Q for the quarter ended June 30, 2002.
10.1(e)* Amendment to the Credit Agreement and Waiver dated as of December 5, 2002 by and among the Company, Ableco Finance
LLC and Foothill Capital Corporation.
10.2 Transaction Advisory Agreement dated as of June 27, 1997 by and between the Company and TPG Partners II,
L.P.--incorporated by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-4 (Registration
No. 333-33407).
10.3 Retirement and noncompetition agreement dated May 26, 1999 by and between the Company and Ronald L.
Clements--incorporated by reference to Exhibit 10.3(b) to the Company's Annual Report on Form 10-K for the year
ended December 31, 1999.
10.5 Belden & Blake Corporation 1997 Non-Qualified Stock Option Plan--incorporated by reference to Exhibit 10.5 to the
Company's Registration Statement on Form S-4 (Registration No. 333-33407).
10.7 Change in Control Severance Pay Plan for Key Employees of the Company dated August 12, 1999--incorporated by
reference to Exhibit 10.7 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999.
45
NO. DESCRIPTION
- --- -----------
10.7(a)* Amendment No. 1 of the Belden & Blake Corporation 1999 Change in Control Protection Plan for Key Employees dated
as of February 26, 2002.
10.7(b)* Amendment No. 2 of the Belden & Blake Corporation 1999 Change in Control Protection Plan for Key Employees dated
as of October 23, 2002.
10.8 Severance Pay Plan for Employees of Belden & Blake Corporation dated August 12, 1999--incorporated by reference to
Exhibit 10.8 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999.
10.8(a)* Amendment-1 to the Belden & Blake Corporation 1999 Severance Pay Plan dated as of May 29, 2000.
10.8(b)* Amendment-2 to the Belden & Blake Corporation 1999 Severance Pay Plan dated as of September 12, 2002.
10.10 Employment Agreement dated June 1, 1999 and amended November 1, 1999 by and between the Company and John L.
Schwager--incorporated by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the year
ended December 31, 1999.
10.11 Amended and Restated Employment Agreement dated July 1, 2001 by and between the Company and John L. Schwager.
Incorporated by reference to Exhibit 10.11 to the Company's Annual Report on Form 10-K for the year ended
December 31, 2001.
10.12 Letter of Agreement dated December 21, 2001 by and between the Company and Leo A. Schrider. Incorporated by
reference to Exhibit 10.12 to the Company's Annual Report on Form 10-K for the year ended
December 31, 2001.
21* Subsidiaries of the Registrant.
23* Consent of Independent Auditors.
99.1* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
99.2* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002.
*Filed herewith
(b) Reports on Form 8-K
On October 24, 2002, the Company filed a Current Report on Form 8-K
dated October 10, 2002, reporting under Item 5 the Company's formation of a new
Appalachian District and staff reductions.
On November 26, 2002, the Company filed a Current Report on Form 8-K
dated November 22, 2002 reporting under Item 9 the Company's operational outlook
for 2002 and the Company's natural gas hedging position.
On December 23, 2002, the Company filed a Current Report on Form 8-K
dated December 5, 2002 reporting under Item 5 the Company's New
York/Pennsylvania Medina formations well sale and the Third Amendment to the
Amended and Restated Credit Agreement dated as of July 25, 2002 by and among the
Company, Ableco Finance LLC and Foothill Capital Corporation.
46
(c) Exhibits required by Item 601 of Regulation S-K
Exhibits required to be filed by the Company pursuant to Item 601 of
Regulation S-K are contained in the Exhibits listed under Item 15(a)3.
(d) Financial Statement Schedules required by Regulation S-X
The items listed in the accompanying index to financial statements are
filed as part of this Annual Report on Form 10-K.
47
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.
BELDEN & BLAKE CORPORATION
March 24, 2003 By: /s/ John L. Schwager
- -------------------------------- ---------------------------
Date John L. Schwager, Director, President
and Chief Executive Officer
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 L. Schwager Director, President March 24, 2003
- ------------------------ and Chief Executive Officer --------------
John L. Schwager (Principal Executive Officer) Date
/s/ Robert W. Peshek Vice President Finance and March 24, 2003
- ------------------------ Chief Financial Officer --------------
Robert W. Peshek (Principal Financial and Date
Accounting Officer)
/s/ Lawrence W. Kellner Director March 24, 2003
- ------------------------ --------------
Lawrence W. Kellner Date
/s/ Robert S. Maust Director March 24, 2003
- ------------------------ --------------
Robert S. Maust Date
/s/ William S. Price, III Director March 24, 2003
- ------------------------- --------------
William S. Price, III Date
/s/ Gareth Roberts Director March 24, 2003
- ------------------------ --------------
Gareth Roberts Date
/s/ Jeffrey C. Smith Director March 24, 2003
- ------------------------ --------------
Jeffrey C. Smith Date
48
CERTIFICATIONS
- -------------------------------------------------------------------------------
I, John L. Schwager, certify that:
1. I have reviewed this annual report on Form 10-K of Belden & Blake
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 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 performing the equivalent
functions):
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 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 24, 2003 /s/ John L. Schwager
-------------------------- -------------------------------------
John L. Schwager, Director, President
and Chief Executive Officer
49
CERTIFICATIONS
- -------------------------------------------------------------------------------
I, Robert W. Peshek, certify that:
1. I have reviewed this annual report on Form 10-K of Belden & Blake
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 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 performing the equivalent
functions):
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 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 24, 2003 /s/ Robert W. Peshek
---------------------- ----------------------------------
Robert W. Peshek, Vice President
and Chief Financial Officer
50
BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES
ITEM 15(a) (1) AND (2)
CONSOLIDATED FINANCIAL STATEMENTS Page
Report of Independent Auditors................................ F-2
Consolidated Balance Sheets as of December 31, 2002 and 2001.. F-3
Consolidated Statements of Operations:
Years ended December 31, 2002, 2001 and 2000................ F-4
Consolidated Statements of Shareholders' Equity (Deficit):
Years ended December 31, 2002, 2001 and 2000................ F-5
Consolidated Statements of Cash Flows:
Years ended December 31, 2002, 2001 and 2000................ F-6
Notes to Consolidated Financial Statements.................... F-7
All financial statement schedules have been omitted since the required
information is not present in amounts sufficient to require submission of the
schedule or because the information required is included in the financial
statements.
F-1
REPORT OF INDEPENDENT AUDITORS
To the Shareholders and Board of Directors
Belden & Blake Corporation
We have audited the accompanying consolidated balance sheets of Belden & Blake
Corporation ("Company") as of December 31, 2002 and 2001, and the related
consolidated statements of operations, shareholders' equity (deficit) and cash
flows for each of the three years in the period ended December 31, 2002. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. 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 financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Belden & Blake
Corporation at December 31, 2002 and 2001 and the consolidated results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2002, in conformity with accounting principles generally accepted
in the United States.
ERNST & YOUNG LLP
Cleveland, Ohio
March 18, 2003
F-2
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31,
-----------------------------------
2002 2001
---------------- -----------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 1,722 $ 1,935
Accounts receivable, net 14,652 13,335
Inventories 848 1,695
Deferred income taxes 4,200 --
Other current assets 1,341 1,094
Fair value of derivatives -- 19,965
Assets of discontinued operations 1,066 17,623
---------------- -----------------
TOTAL CURRENT ASSETS 23,829 55,647
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 438,240 423,554
Gas gathering systems 14,482 14,062
Land, buildings, machinery and equipment 22,748 23,167
---------------- -----------------
475,470 460,783
Less accumulated depreciation, depletion and amortization 243,596 225,793
---------------- -----------------
PROPERTY AND EQUIPMENT, NET 231,874 234,990
FAIR VALUE OF DERIVATIVES 3 3,748
OTHER ASSETS 8,139 10,964
---------------- -----------------
$263,845 $305,349
================ =================
LIABILITIES AND SHAREHOLDERS' DEFICIT
CURRENT LIABILITIES
Accounts payable $ 5,661 $ 5,253
Accrued expenses 17,767 14,418
Current portion of long-term liabilities 315 156
Fair value of derivatives 5,486 --
Deferred income taxes -- 5,470
Liabilities of discontinued operations 335 4,604
---------------- -----------------
TOTAL CURRENT LIABILITIES 29,564 29,901
LONG-TERM LIABILITIES
Bank and other long-term debt 26,868 59,415
Senior subordinated notes 225,000 225,000
Other 91 330
---------------- -----------------
251,959 284,745
FAIR VALUE OF DERIVATIVES 4,371 --
DEFERRED INCOME TAXES 22,596 17,982
SHAREHOLDERS' DEFICIT
Common stock without par value; $.10 stated value per share; authorized
58,000,000 shares; issued 10,490,440 and 10,425,103 shares
(which includes 194,890 and 135,369 treasury shares, respectively) 1,030 1,029
Paid in capital 107,118 107,402
Deficit (148,332) (150,797)
Accumulated other comprehensive (loss) income (4,461) 15,087
---------------- -----------------
TOTAL SHAREHOLDERS' DEFICIT (44,645) (27,279)
---------------- -----------------
$ 263,845 $ 305,349
================ =================
See accompanying notes.
F-3
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
------------------------------------------------
2002 2001 2000
------------- ------------- -------------
REVENUES
Oil and gas sales $ 90,462 $ 89,491 $ 73,813
Gas gathering, marketing, and oilfield service 21,624 27,348 27,847
Other 1,834 2,044 3,242
------------- ------------- -------------
113,920 118,883 104,902
EXPENSES
Production expense 19,936 20,952 19,243
Production taxes 1,789 2,298 2,341
Gas gathering, marketing, and oilfield service 17,996 22,760 24,742
Exploration expense 16,256 8,335 8,524
General and administrative expense 4,557 4,395 4,617
Franchise, property and other taxes 91 238 379
Depreciation, depletion and amortization 22,379 25,979 26,331
Impairment of oil and gas properties and other assets -- 1,398 477
Severance and other nonrecurring expense 953 1,954 241
------------- ------------- -------------
83,957 88,309 86,895
------------- ------------- -------------
OPERATING INCOME 29,963 30,574 18,007
OTHER (INCOME) EXPENSE
Loss (gain) on sale of businesses and other income 154 -- (15,064)
Interest expense 23,608 25,753 27,892
------------- ------------- -------------
23,762 25,753 12,828
------------- ------------- -------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
AND EXTRAORDINARY ITEM 6,201 4,821 5,179
Provision (benefit) for income taxes 2,456 (955) 1,754
------------- ------------- -------------
INCOME FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEM 3,745 5,776 3,425
(Loss) income from discontinued operations, net of tax (1,280) 691 900
------------- ------------- -------------
INCOME BEFORE EXTRAORDINARY ITEM 2,465 6,467 4,325
Extraordinary item - early extinguishment of debt,
net of tax benefit -- -- (1,364)
------------- ------------- -------------
NET INCOME $ 2,465 $ 6,467 $ 2,961
============= ============= =============
See accompanying notes.
F-4
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
(IN THOUSANDS)
ACCUMULATED
OTHER TOTAL
COMMON COMMON PAID IN COMPREHENSIVE EQUITY
SHARES STOCK CAPITAL DEFICIT INCOME (DEFICIT)
---------- ---------- ----------- ------------ ------------- ------------
JANUARY 1, 2000 10,260 $ 1,026 $ 107,609 $ (160,225) $ -- $ (51,590)
Net income 2,961 2,961
Stock options exercised 97 10 (9) 1
Stock-based compensation 336 336
Treasury stock (54) (6) (15) (21)
- ------------------------------------------ ---------- ---------- ----------- ------------ ------------- ------------
DECEMBER 31, 2000 10,303 1,030 107,921 (157,264) -- (48,313)
Comprehensive income:
Net income 6,467 6,467
Other comprehensive income, net of tax:
Cumulative effect of accounting change (6,691) (6,691)
Change in derivative fair value 24,667 24,667
Reclassification adjustment for
derivative (gain) loss reclassified
into oil and gas sales (2,889) (2,889)
------------
Total comprehensive income 21,554
------------
Stock options exercised 68 7 (1) 6
Stock-based compensation 275 275
Repurchase of stock options (772) (772)
Tax benefit of repurchase of stock options
and stock options exercised 260 260
Treasury stock (81) (8) (281) (289)
- ------------------------------------------ ---------- ---------- ----------- ------------ ------------- ------------
DECEMBER 31, 2001 10,290 1,029 107,402 (150,797) 15,087 (27,279)
Comprehensive income:
Net income 2,465 2,465
Other comprehensive income, net of tax:
Change in derivative fair value (5,518) (5,518)
Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales (14,030) (14,030)
------------
Total comprehensive income (17,083)
------------
Stock options exercised 65 7 (2) 5
Stock-based compensation 82 82
Repurchase of stock options (29) (29)
Tax benefit of repurchase of stock options
and stock options exercised 57 57
Treasury stock (59) (6) (392) (398)
- ------------------------------------------ ---------- ---------- ----------- ------------ ------------- ------------
DECEMBER 31, 2002 10,296 $ 1,030 $ 107,118 $ (148,332) $ (4,461) $ (44,645)
========================================== ========== ========== =========== ============ ============= ============
See accompanying notes.
F-5
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001 2000
------------- ------------- ------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Income from continuing operations $ 3,745 $ 5,776 $ 2,061
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Net loss on early extinguishment of debt -- -- 1,364
Depreciation, depletion and amortization 22,379 25,979 26,331
Impairment of oil and gas properties and other assets -- 1,398 477
Loss (gain) on sale of businesses 154 -- (13,794)
Loss on disposal of property and equipment 198 92 500
Net monetization of derivatives 22,185 -- --
Amortization of derivatives and other noncash hedging activities (19,241) -- --
Exploration expense 16,256 8,335 8,524
Deferred income taxes 2,468 (1,069) 1,463
Stock-based compensation 82 275 169
Change in operating assets and liabilities, net of
effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets (1,420) 8,521 162
Inventories 453 571 (674)
Accounts payable and accrued expenses 3,646 (5,008) (102)
------------- ------------- ------------
NET CASH PROVIDED BY CONTINUING OPERATIONS 50,905 44,870 26,481
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of businesses, net of cash acquired (2,773) (489) 381
Disposition of businesses, net of cash 12,390 897 69,031
Proceeds from property and equipment disposals 1,927 768 246
Exploration expense (16,256) (8,335) (8,524)
Additions to property and equipment (26,215) (35,730) (18,624)
Increase in other assets (1,541) (81) (83)
------------- ------------- ------------
NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES (32,468) (42,970) 42,427
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving line of credit and term loan 151,158 181,645 123,096
Repayment of long-term debt and other obligations (184,003) (184,071) (190,814)
Debt issue costs (152) (210) (5,537)
Proceeds from stock options exercised 5 6 --
Repurchase of stock options (29) (772) --
Purchase of treasury stock (398) (289) (21)
------------- ------------- ------------
NET CASH USED IN FINANCING ACTIVITIES (33,419) (3,691) (73,276)
------------- ------------- ------------
NET DECREASE IN CASH AND CASH EQUIVALENTS
FROM CONTINUING OPERATIONS (14,982) (1,791) (4,368)
NET INCREASE IN CASH AND CASH EQUIVALENTS
FROM DISCONTINUED OPERATIONS 14,769 1,928 1,630
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,935 1,798 4,536
------------- ------------- ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,722 $ 1,935 $ 1,798
============= ============= ============
See accompanying notes.
F-6
BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
BUSINESS
Belden & Blake Corporation (the "Company") is a privately held company
owned by TPG Partners II L.P. ("TPG") and certain other investors. The Company
operates in the oil and gas industry. The Company's principal business is the
production, development, acquisition and marketing and gathering of oil and gas
reserves. Sales of oil are ultimately made to refineries. Sales of natural gas
are ultimately made to gas utilities and industrial consumers in Ohio, Michigan,
Pennsylvania and New York. The price of oil and natural gas has a significant
impact on the Company's working capital and results of operations.
PRINCIPLES OF CONSOLIDATION AND FINANCIAL PRESENTATION
The accompanying consolidated financial statements include the
financial statements of the Company and its subsidiaries. All significant
intercompany accounts and transactions have been eliminated in consolidation.
Certain reclassifications have been made to conform to the presentation in 2002.
USE OF ESTIMATES IN THE FINANCIAL STATEMENTS
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts. Significant estimates used in the
preparation of the Company's financial statements which could be subject to
significant revision in the near term include estimated oil and gas reserves.
Although actual results could differ from these estimates, significant
adjustments to these estimates historically have not been required.
CASH EQUIVALENTS
For purposes of the statements of cash flows, cash equivalents are
defined as all highly liquid investments purchased with an initial maturity of
three months or less.
CONCENTRATIONS OF CREDIT RISK
Credit limits, ongoing credit evaluation and account monitoring
procedures are utilized to minimize the risk of loss. Collateral is generally
not required. Expected losses are provided for currently and actual losses have
been within management's expectations.
INVENTORIES
Inventories of material, pipe and supplies are valued at average cost.
Crude oil and natural gas inventories are stated at the lower of average cost or
market.
PROPERTY AND EQUIPMENT
The Company utilizes the "successful efforts" method of accounting for
its oil and gas properties. Under this method, property acquisition and
development costs and certain productive exploration costs are capitalized while
non-productive exploration costs, which include certain geological and
geophysical costs, exploratory dry holes and costs of carrying and retaining
unproved properties, are expensed as incurred. Capitalized costs related to
proved properties are depleted using the unit-of-production method.
Depreciation, depletion and amortization of proved oil and gas properties is
calculated on the basis of estimated recoverable reserve quantities. These
estimates can change based on economic or other factors. No gains or losses are
recognized upon the disposition of oil and gas properties except in
extraordinary transactions such as the complete disposition of a
geographical/geological pool. Sales proceeds are
F-7
credited to the carrying value of the properties. Maintenance and repairs are
expensed, and expenditures which enhance the value of properties are
capitalized.
Unproved oil and gas properties are stated at cost and consist of
undeveloped leases. These costs are assessed periodically to determine whether
their value has been impaired, and if impairment is indicated, the costs are
charged to expense. Impairments recorded in 2001 and 2000 were $179,000 and
$477,000, respectively, which reduced the book value of unproved oil and gas
properties to their estimated fair value. No impairment was recorded in 2002.
Gas gathering systems are stated at cost. Depreciation expense is
computed using the straight-line method over 15 years.
Property and equipment are stated at cost. Depreciation of non-oil and
gas properties is computed using the straight-line method over the useful lives
of the assets ranging from 3 to 15 years for machinery and equipment and 30 to
40 years for buildings. When assets other than oil and gas properties are
retired or otherwise disposed of, the cost and related accumulated depreciation
are removed from the accounts, and any resulting gain or loss is reflected in
income for the period. The cost of maintenance and repairs is expensed as
incurred, and significant renewals and betterments are capitalized.
Long-lived assets are reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amount may not be
recoverable. If the sum of the expected future undiscounted cash flows is less
than the carrying amount of the asset, a loss is recognized for the difference
between the fair value and the carrying amount of the asset. In performing the
review for long-lived asset recoverability during 2001, the Company recorded
$1.2 million of impairments which reduced the book value of producing properties
to their estimated fair value. Fair value was based on estimated future cash
flows to be generated by the assets, discounted at a market rate of interest. No
impairment was recorded in 2002 or 2000.
INTANGIBLE ASSETS
On January 1, 2002, the Company adopted Statement of Financial
Accounting Standards No. (SFAS) 142, "Goodwill and Other Intangible Assets"
which was issued in June 2001 by the Financial Accounting Standards Board
(FASB). Under SFAS 142, goodwill and indefinite lived intangible assets are no
longer amortized but are reviewed for impairment annually or if certain
impairment indicators arise. Separately identifiable intangible assets that are
not deemed to have an indefinite life will continue to be amortized over their
useful lives (but with no maximum life).
At December 31, 2001, the Company had $2.7 million of unamortized
goodwill, representing the costs in excess of the net assets of acquired
businesses, which was subject to the transition provisions of SFAS 142.
Amortization expense related to goodwill amounted to $130,000 and $132,000 for
the years ended December 31, 2001 and 2000, respectively. The Company assessed
the impact of SFAS 142 and has determined that adoption of SFAS 142 did not have
a material effect on the Company's financial position, results of operations or
cash flows, including any transitional impairment losses. The Company performed
its required transitional impairment test upon adoption of SFAS 142. Due to the
Company's fourth quarter disposition activity, the Company performed its annual
impairment test as of December 31, 2002. However, the Company plans to perform
its annual impairment test on a recurring basis as of October 1, starting in
fiscal 2003.
Intangible assets totaling $7.7 million at December 31, 2002, include
$4.9 million of deferred debt issuance costs and $2.3 million of unamortized
goodwill. Deferred debt issuance costs are being amortized over their respective
terms. At December 31, 2002, the amortization of deferred debt issuance costs in
the next five years is as follows: $1.2 million in each of the next three years
(2003,
F-8
2004, and 2005), $0.8 million in 2006 and $0.5 million in 2007. During the
fourth quarter of 2002, the Company allocated $667,000 of goodwill to disposal
transactions.
REVENUE RECOGNITION
Oil and gas production revenue is recognized as production and delivery
take place. Oil and gas marketing revenues are recognized when title passes.
Oilfield service revenues are recognized when the goods or services have been
provided.
INCOME TAXES
The Company uses the liability method of accounting for income taxes.
Deferred income taxes are provided for temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and
the amounts used for income tax purposes. Deferred income taxes also are
recognized for operating losses that are available to offset future taxable
income and tax credits that are available to offset future federal income taxes.
STOCK-BASED COMPENSATION
On December 31, 2002, the FASB issued SFAS 148, "Accounting for Stock
Based Compensation-Transition and Disclosure." SFAS 148 amends SFAS 123,
"Accounting for Stock Based Compensation" by providing alternative methods of
transition to SFAS 123's fair value method of accounting for stock-based
compensation. SFAS 148 also amends many of the disclosure requirements of SFAS
123. The Company measures expense associated with stock-based compensation under
the provisions of Accounting Principles Board Opinion No. (APB) 25, "Accounting
for Stock Issued to Employees" and its related interpretations. Under APB 25, no
compensation expense is required to be recognized by the Company upon the
issuance of stock options to key employees as the exercise price of the option
is equal to the market price of the underlying common stock at the date of
grant.
The fair value of the Company's stock options was estimated at the date
of grant using a Black-Scholes option pricing model with the following
weighted-average assumptions for 2002, 2001 and 2000, respectively: risk-free
interest rates of 4.1%, 5.0% and 6.4%; volatility factor of the expected market
price of the Company's common stock of near zero; dividend yield of zero; and a
weighted-average expected life of the option of seven years.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its stock options.
For purposes of the pro forma disclosures required by SFAS 123, the
estimated fair value of the options is amortized to expense over the options'
vesting period. The changes in net income or loss as if the Company had applied
the fair value provisions of SFAS 123 for the years ended December 31, 2002,
2001 and 2000 were not material.
In March 2000, the FASB issued FASB Interpretation No. (FIN)
44, "Accounting for Certain Transactions involving Stock Compensation, an
interpretation of APB 25." The Interpretation, which was adopted prospectively
as of July 1, 2000, requires that stock options that have been modified to
reduce the exercise price be accounted for as variable. Prior to the adoption of
the Interpretation, the Company accounted for these repriced stock options as
fixed. The effect of adopting the Interpretation
F-9
was to increase compensation expense by $298,000 in the second half of the year
ended December 31, 2000.
The Company repriced 318,892 stock options (298,392 outstanding prior
to July 1, 2000) in October 1999, and reduced the exercise price to $0.01 per
share. Under the Interpretation, the options are accounted for as variable from
July 1, 2000 until the options are exercised, forfeited or expire unexercised.
The Company repriced 227,500 stock options in December 2001, which had been
granted in 2001 at $3.59 per share and reduced the exercise price to $2.14 per
share.
The definition of a public company under FIN 44 is less restrictive
than previous practice. Specifically, a company with publicly-traded debt, but
not publicly-traded equity securities, would not be considered public. Prior to
July 1, 2000, Belden & Blake Corporation common stock held in the 401(k) plan
was subject to variable plan accounting.
The changes in share value and the vesting of shares are reported as
adjustments to compensation expense. The change in share value in 2002, 2001 and
2000 resulted in an increase in compensation expense of $82,000, $275,000 and
$336,000, respectively.
DERIVATIVES AND HEDGING
On January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities" which was issued in June, 1998 by
the FASB, as amended by SFAS 137, "Accounting for Derivative Instruments and
Hedging Activities - Deferral of Effective Date of SFAS 133" and SFAS 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities"
issued in June 1999 and June 2000, respectively. SFAS 133, as amended, was
applied as the cumulative effect of an accounting change effective January 1,
2001.
As a result of the adoption of SFAS 133, the Company recognizes all
derivative financial instruments as either assets or liabilities at fair value.
Derivative instruments that are not hedges must be adjusted to fair value
through net income (loss). Under the provisions of SFAS 133, changes in the fair
value of derivative instruments that are fair value hedges are offset against
changes in the fair value of the hedged assets, liabilities, or firm
commitments, through net income (loss). Changes in the fair value of derivative
instruments that are cash flow hedges are recognized in other comprehensive
income (loss) until such time as the hedged items are recognized in net income
(loss). Ineffective portions of a derivative instrument's change in fair value
are immediately recognized in net income (loss). Deferred gains and losses on
terminated commodity hedges will be recognized as increases or decreases to oil
and gas revenues during the same periods in which the underlying forecasted
transactions are recognized in net income (loss). See Note 5.
The relationship between the hedging instruments and the hedged items
must be highly effective in achieving the offset of changes in fair values or
cash flows attributable to the hedged risk, both at the inception of the
contract and on an ongoing basis. The Company measures effectiveness on changes
in the hedge's intrinsic value. The Company considers these hedges to be highly
effective and expects there will be no ineffectiveness to be recognized in net
income (loss) since the critical terms of the hedging instruments and the hedged
forecasted transactions are the same. Ongoing assessments of hedge effectiveness
will include verifying and documenting that the critical terms of the hedge and
forecasted transaction do not change. The Company measures effectiveness at
least on a quarterly basis.
The adoption of SFAS 133 resulted in a January 1, 2001, transition
adjustment to increase other current liabilities by $10.5 million, increase
current deferred income taxes by $3.8 million and increase shareholders' deficit
by $6.7 million to record the fair value of open cash flow hedges and the
related
F-10
income tax effect. The increase in shareholders' deficit is reflected as a
cumulative effect of accounting change in accumulated other comprehensive income
(loss).
Prior to January 1, 2001, under the deferral method, gains and losses
from derivative instruments that qualified as hedges were deferred until the
underlying hedged asset, liability or transaction monetized, matured or was
otherwise recognized under generally accepted accounting principles. When
recognized in net income (loss), hedge gains and losses were included as an
adjustment to gas revenue or interest expense.
(2) NEW ACCOUNTING PRONOUNCEMENTS
On January 1, 2002, the Company adopted SFAS 142, "Goodwill and Other
Intangible Assets," which was issued in June 2001 by the FASB, and discontinued
amortization of goodwill. Under SFAS 142, goodwill and indefinite lived
intangible assets are no longer amortized but are reviewed for impairment
annually or if certain impairment indicators arise. Separately identifiable
intangible assets that are not deemed to have an indefinite life will continue
to be amortized over their useful lives (but with no maximum life).
At December 31, 2001, the Company had $2.7 million of unamortized
goodwill, representing the costs in excess of the net assets of acquired
businesses, which was subject to the transition provisions of SFAS 142.
Amortization expense related to goodwill amounted to $130,000 and $132,000 for
the years ended December 31, 2001 and 2000, respectively. The Company assessed
the impact of SFAS 142 and has determined that adoption of SFAS 142 did not have
a material effect on the Company's financial position, results of operations or
cash flows, including any transitional impairment losses. The Company performed
its required transitional impairment test upon adoption of SFAS 142. Due to the
Company's fourth quarter disposition activity, the Company performed its annual
impairment test as of December 31, 2002. However, the Company plans to perform
its annual impairment test on a recurring basis as of October 1, starting in
fiscal 2003.
In June 2001, the FASB issued SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 143 addresses obligations associated with the
retirement of tangible, long-lived assets and the associated asset retirement
costs. This statement amends SFAS 19, "Financial Accounting and Reporting by Oil
and Gas Producing Companies", and is effective for the Company's financial
statements beginning January 1, 2003. This statement would require the Company
to recognize a liability for the fair value of its plugging and abandoning
liability (excluding salvage value) with the associated costs included as part
of the Company's oil and gas properties balance. Due to the significant number
of producing oil and gas properties operated by the Company, and the number of
documents that must be reviewed and estimates that must be made to assess the
effects of SFAS 143, it has not yet been determined whether adoption of SFAS 143
will have a material effect on the Company's financial position, results of
operations or cash flows.
In August 2001, the FASB issued SFAS 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets," which establishes a single
accounting model to be used for long-lived assets to be disposed of. The new
rules supersede SFAS 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of." Although retaining many of the
fundamental recognition and measurement provisions of SFAS 121, the new rules
significantly change the criteria that would have to be met to classify an asset
as held-for-sale. This distinction is important because assets to be disposed of
are stated at the lower of their fair values or carrying amounts and
depreciation is no longer recognized. The new rules also supersede the
provisions of APB 30, "Reporting Results of Operations - Reporting the Effects
of Disposal of a Segment of Business," with regard to reporting the effects of a
disposal of a segment of a business and require the expected future operating
losses from discontinued operations to be displayed in discontinued operations
in the periods in
F-11
which the losses are incurred rather than as of the measurement date as
previously required by APB 30. In addition, more dispositions may qualify for
discontinued operations treatment in the income statement. SFAS 144 was
effective as of January 1, 2002. In applying the provisions of SFAS 144, the
Company defined a "component of an entity" as a geographical/geological pool
used for depletion purposes. As such, the disposition of all of the wells in the
New York Medina formation was classified as a discontinued operation. Well
dispositions in Ohio and Pennsylvania did not result in the liquidation of a
pool, so the proceeds from the sale of those wells reduced oil and gas
properties, with no gain or loss recognized. Results of operations relating to
the Ohio and Pennsylvania wells prior to their disposition are included in
continuing operations.
In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from
Extinguishment of Debt," SFAS 44, "Accounting for Intangible Assets of Motor
Carriers" and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund
Requirements" and amends SFAS No. 13, "Accounting for Leases." Statement 145
also makes technical corrections to other existing pronouncements. SFAS 4
required gains and losses from extinguishment of debt to be classified as an
extraordinary item, net of the related income tax effect. As a result of the
rescission of SFAS 4, the criteria for extraordinary items in 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," now will be used to classify those gains and losses.
SFAS 145 is effective for the Company's financial statements beginning January
1, 2003. The adoption of SFAS 145 is not expected to have a material effect on
the Company's financial position, results of operations or cash flows.
In June 2002, the FASB issued SFAS 146, "Accounting for Costs
Associated with Exit or Disposal Activities." SFAS 146 will be effective for the
Company for disposal activities initiated after December 31, 2002. The adoption
of this standard is not expected to have a material effect on the Company's
financial position, results of operations or cash flows.
In November 2002, the FASB issued FIN 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others". FIN 45's disclosure requirements are effective for the
Company's interim and annual financial statements for periods ending after
December 15, 2002. The initial recognition and measurement provisions are
applicable in a prospective basis to guarantees issued or modified after
December 31, 2002. FIN 45 requires certain guarantees to be recorded at fair
value, which is different from current practice, which is generally to record a
liability only when a loss is probable and reasonably estimable. FIN 45 also
requires a guarantor to make significant new disclosures, even when the
likelihood of making any payments under the guarantee is remote. Adoption of FIN
45 did not have any effect on the Company's financial statement disclosures for
the year ended December 31, 2002, and the Company does not expect FIN 45 to have
a material impact on its financial position, results of operations or cash flows
in the future.
(3) ACQUISITIONS
On July 11, 2002, the Company acquired net reserves totaling 4.2 Bcfe
(billion cubic feet of natural gas equivalent) for a cash payment of $1.2
million. The Company previously held a production payment on these properties
through December 31, 2002.
During the second quarter of 2002, the Company acquired the assets of
a drilling consulting and frac tank rental business for $1.6 million.
(4) DISPOSITIONS AND DISCONTINUED OPERATIONS
On December 10, 2002, the Company sold 962 oil and natural gas wells in
New York and Pennsylvania. The sale included substantially all of the Company's
Medina formation wells in New York and a smaller number of Pennsylvania Medina
wells. The properties had approximately 23 Bcfe of total
F-12
proved reserves. At the time of the sale, the Company's net production from
these wells was approximately 3.9 Mmcfe (million cubic feet of natural gas
equivalent) per day (4 Mcfe (thousand cubic feet of natural gas equivalent) per
day per well). The Company disposed of these properties due to the low
production volume per well and high cost characteristics. The wells sold had
proved developed reserves using Securities and Exchange Commission ("SEC")
pricing parameters of approximately 19.4 Bcfe and proved undeveloped reserves of
approximately 3.6 Bcfe.
The sale resulted in proceeds of approximately $16.2 million. On
December 10, 2002, the Company received $15.5 million in cash with the remaining
amount of approximately $700,000 received in February 2003. The proceeds were
used to pay down the Company's revolving credit facility. As a result of the
sale, the Company disposed of all of its properties producing from the New York
Medina formation. As a result of the disposition of the entire New York Medina
geographical/geological pool, the Company recorded a loss on sale of $3.2
million ($1.8 million net of tax). According to SFAS 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets," the disposition of this group
of wells is classified as discontinued operations. The loss on the sale of the
New York Medina wells and the related results of these properties have been
reclassified as discontinued operations for all periods presented.
This transaction was completed during December 2002. In accordance with
SFAS 144, the Company was required to reclassify the assets, liabilities and
results of its operations in the New York Medina as discontinued operations for
all accounting periods presented. Although both revenues and expenses for prior
periods were reclassified, there was no impact upon previously reported net
earnings.
The Company allocates interest expense to operating areas based on the
proportionate share of net assets of the area to the Company's consolidated net
assets. The amounts of interest expense allocated to the New York Medina
geographical/geological pool and included in income (loss) from discontinued
operations for the years ended December 31, 2002, 2001 and 2000, were $1.5
million, $1.7 million and $1.6 million, respectively.
Revenues and (loss) income from discontinued operations are as follows:
YEAR ENDED DECEMBER 31,
------------------------------------------------
2002 2001 2000
-------------- -------------- --------------
Revenue from discontinued operations $ 9,245 $ 12,646 $ 12,949
Income from operations of discontinued business $ 960 $ 1,155 $ 1,514
Provision for income taxes 408 464 614
-------------- -------------- --------------
552 691 900
Loss on sale of discontinued business (3,188)
Income tax benefit (1,356)
--------------
(1,832)
-------------- -------------- --------------
(Loss) income from discontinued operations, net of tax $ (1,280) $ 691 $ 900
============== ============== ==============
F-13
Assets and liabilities of the discontinued operations are as follows:
DECEMBER 31,
-------------------------------
2002 2001
-------------- --------------
Assets
Current assets $ - $ 825
Net property and equipment 1,066 16,798
-------------- --------------
Total assets $ 1,066 $ 17,623
============== ==============
Liabilities
Current liabilities $ 335 $ 47
Noncurrent deferred tax liability - 4,557
-------------- --------------
Total liabilities $ 335 $ 4,604
-------------- --------------
Net assets of discontinued operations $ 731 $ 13,019
============== ==============
A transaction fee of approximately $230,000 will be paid in 2003 to
TPG in connection with the sale. The fee is payable to TPG pursuant to a
Transaction Advisory Agreement entered into in 1997 between the Company and TPG.
During 2002, the Company completed the sale of six natural gas
compressors in Michigan to a compression services company. The proceeds of
approximately $2.0 million were used to pay down the Company's revolving credit
facility. The Company also entered into an agreement to leaseback the
compressors from the compression services company, which will provide full
compression services including maintenance and repair on these and other
compressors. Certain compressors will also be relocated to maximize compression
efficiency. A gain on the sale of $168,000 was deferred and will be amortized as
rental expense over the life of the lease.
On August 1, 2002, the Company sold oil and gas properties consisting
of 1,138 wells in Ohio that had approximately 10 Bcfe of proved reserves. At the
time of the sale, the Company's net production from these wells was
approximately 3.1 Mmcfe per day (3 Mcfe per day per well). The Company disposed
of these properties due to the low production volume per well and high operating
costs per well. The proceeds of approximately $8.0 million were used to pay down
the Company's revolving credit facility.
On March 17, 2000, the Company sold the stock of Peake Energy, Inc.
("Peake"), a wholly owned subsidiary, to North Coast Energy, Inc., an
independent oil and gas company. The sale included substantially all of the
Company's oil and gas properties in West Virginia and Kentucky. The sale
resulted in net proceeds of approximately $69.2 million. The Company recorded a
$13.7 million gain on the sale in 2000.
At December 31, 1999, using SEC pricing parameters, Peake had proved
developed reserves of approximately 66.5 Bcfe and proved undeveloped reserves of
approximately 3.7 Bcfe. At the time of the sale, Peake's reserves represented
20.2% of the Company's total proved reserves. The unaudited pro forma results of
operations of the Company for the year ended December 31, 2000 are as follows:
revenues of $113.8 million. The pro forma effects on net income were not
material. The unaudited pro forma information presented above assumes the
disposition occurred prior to the period presented and does not purport to be
indicative of the results that actually would have been obtained and is not
intended to be a projection of future results or trends.
(5) DERIVATIVES AND HEDGING
On January 1, 2001, the Company adopted SFAS 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended. As a result of the
adoption of SFAS 133, the Company recognizes all derivative financial
instruments as either assets or liabilities at fair value. Derivative
instruments that
F-14
are not hedges must be adjusted to fair value through net income (loss). Under
the provisions of SFAS 133, changes in the fair value of derivative instruments
that are fair value hedges are offset against changes in the fair value of the
hedged assets, liabilities, or firm commitments, through net income (loss).
Changes in the fair value of derivative instruments that are cash flow hedges
are recognized in other comprehensive income (loss) until such time as the
hedged items are recognized in net income (loss). The hedging relationship
between the hedging instruments and hedged item must be highly effective in
achieving the offset of changes in fair values or cash flows attributable to the
hedged risk both at the inception of the contract and on an ongoing basis. The
Company measures effectiveness at least on a quarterly basis. Ineffective
portions of a derivative instrument's change in fair value are immediately
recognized in net income (loss). If there is a discontinuance of a cash flow
hedge because it is probable that the original forecasted transaction will not
occur, deferred gains or losses are recognized in earnings immediately.
From time to time the Company may enter into a combination of futures
contracts, commodity derivatives and fixed-price physical contracts to manage
its exposure to natural gas or oil price volatility. The Company employs a
policy of hedging gas production sold under New York Mercantile Exchange
("NYMEX") based contracts by selling NYMEX based commodity derivative contracts
which are placed with major financial institutions that the Company believes are
minimal credit risks. The contracts may take the form of futures contracts,
swaps, collars or options. At December 31, 2002, the Company's derivative
contracts consisted of natural gas swaps and natural gas costless collars. All
of these NYMEX based derivative contracts were designated as cash flow hedges.
Adoption of SFAS 133 on January 1, 2001 resulted in recording a $10.5
million ($6.7 million net of tax) net liability related to the decline in fair
value of the Company's derivative financial instruments with a corresponding
reduction in shareholders' equity to other comprehensive loss. The net liability
consisted of $11.8 million in current fair value of derivative liabilities and
$1.3 million in current fair value of derivative assets. The fair value of
derivative assets and liabilities represents the difference between hedged
prices and market prices on hedged volumes of natural gas as of December 31,
2002. During 2002, a net gain on contract settlements of $22.1 million ($14.0
million after tax) was reclassified from accumulated other comprehensive income
to earnings and the fair value of open hedges decreased by $8.6 million ($5.5
million after tax). At December 31, 2002, the estimated net losses in
accumulated other comprehensive income that are expected to be reclassified into
earnings within the next 12 months are approximately $2.5 million. The Company
has partially hedged its exposure to the variability in future cash flows
through December 2005.
On January 17 and 18, 2002, the Company monetized 9,350 Bbtu (billion
British thermal units) of its 2002 natural gas hedge position at a weighted
average NYMEX price of $2.53 per Mmbtu (million British thermal units) and 3,840
Bbtu of its 2003 natural gas hedge position at a NYMEX price of $3.01 per Mmbtu.
The Company received net proceeds of $22.7 million that are recognized as
increases to natural gas sales revenues during the same periods in which the
underlying forecasted transactions are recognized in net income (loss).
In January 2002, the Company entered into a collar for 9,350 Bbtu of
its natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a
floor price of $2.25 per Mmbtu which qualified and was designated as a cash flow
hedge under SFAS 133. The Company also sold a floor at $1.75 per Mmbtu on this
volume of gas which was designated as a non-qualifying cash flow hedge under
SFAS 133. The changes in fair value of the $1.75 floor will be initially
reported in expense in the consolidated statements of operations as derivative
fair value (gain) loss and will ultimately be reversed within the same line item
and included in oil and gas sales over the respective contract terms.
F-15
This aggregate structure has the effect of: 1) setting a maximum price
of $4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per Mmbtu; 3)
locking in a price of $2.25 per Mmbtu if prices are between $1.75 and $2.25 per
Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the price if the price
is $1.75 or less. All prices are based on monthly NYMEX settle. The Company paid
$1.0 million for the options. The Company used the net proceeds of $21.7 million
from the two transactions above to pay down on its credit facility.
The following table summarizes, as of December 31, 2002, the Company's
net deferred gains on terminated natural gas hedges. Cash has been received and
the deferred gains recorded in accumulated other comprehensive income. The
deferred gains have been or will be recognized as increases to gas sales
revenues during the periods in which the underlying forecasted transactions are
recognized in net income (loss).
FIRST QUARTER SECOND QUARTER THIRD QUARTER FOURTH QUARTER TOTAL
------------- -------------- ------------- -------------- -----
(IN THOUSANDS)
2002 $ 4,521 $ 5,620 $ 5,188 $ 4,560 $ 19,889
2003 723 865 771 585 2,944
To manage its exposure to natural gas or oil price volatility, the
Company may partially hedge its physical gas or oil sales prices by selling
futures contracts on the NYMEX or by selling NYMEX based commodity derivative
contracts which are placed with major financial institutions that the Company
believes are minimal credit risks. The contracts may take the form of futures
contracts, swaps, collars or options.
The Company's financial results and cash flows can be significantly
impacted as commodity prices fluctuate widely in response to changing market
conditions. Accordingly, the Company may modify its fixed price contract and
financial hedging positions by entering into new transactions or terminating
existing contracts.
F-16
The following tables reflect the natural gas volumes and the weighted
average prices under financial hedges (including settled hedges) at December 31,
2002:
NATURAL GAS SWAPS NATURAL GAS COLLARS
--------------------------------------- ---------------------------------------------
ESTIMATED NYMEX PRICE ESTIMATED
NYMEX PRICE WELLHEAD PRICE PER MMBTU WELLHEAD PRICE
QUARTER ENDING BBTU PER MMBTU PER MCF BBTU FLOOR/CAP PER MCF
- --------------------- -------- ----------- -------------- ---------- --------------- ----------------
March 31, 2003 1,800 $ 3.92 $ 4.17 1,290 $ 3.40 - 5.23 $ 3.65 - 5.48
June 30, 2003 1,800 3.92 4.07 1,290 3.40 - 5.23 3.55 - 5.38
September 30, 2003 1,800 3.92 4.07 1,290 3.40 - 5.23 3.55 - 5.38
December 31, 2003 1,800 3.92 4.14 1,290 3.40 - 5.23 3.62 - 5.45
-------- ----------- ------------ -------- ---------------- ---------------
7,200 $ 3.92 $ 4.12 5,160 $ 3.40 - 5.23 $ 3.59 - 5.42
======== =========== ============ ======== ================ ===============
March 31, 2004 2,040 $ 3.84 $ 4.09
June 30, 2004 2,040 3.84 3.99
September 30, 2004 2,040 3.84 3.99
December 31, 2004 2,040 3.84 4.06
-------- ----------- ------------
8,160 $ 3.84 $ 4.03
======== =========== ============
March 31, 2005 1,500 $ 3.84 $ 4.09
June 30, 2005 1,500 3.73 3.88
September 30, 2005 1,500 3.73 3.88
December 31, 2005 1,500 3.73 3.95
-------- ----------- ------------
6,000 $ 3.76 $ 3.95
======== =========== ============
BBTU - BILLION BRITISH THERMAL UNITS
MMBTU - MILLION BRITISH THERMAL UNITS
MCF - THOUSAND CUBIC FEET
(6) SEVERANCE AND OTHER NONRECURRING EXPENSE
On October 10, 2002, the Company combined its Pennsylvania/New York
District with its Ohio District to form a new "Appalachian District". A total of
28 positions were eliminated in the Ohio and Pennsylvania/New York Districts and
in the corporate office. These actions were necessary to capitalize on
operational and administrative efficiencies and bring the Company's employment
level in line with current and anticipated future staffing. The Company recorded
a nonrecurring charge of approximately $700,000 in the fourth quarter of 2002
related to severance and other costs associated with these actions.
Effective April 1, 2001, certain senior management members of the
Company accepted early retirements. These retirements resulted in a cash charge
of approximately $760,000 and an additional non-cash charge of approximately
$100,000 related to the acceleration of certain stock options.
The Company recorded a net nonrecurring charge of $2.0 million in 2001
which includes a charge of $2.3 million primarily related to these retirement
agreements and other retirement and severance charges incurred which included
non-cash charges totaling approximately $200,000 due to the acceleration of
certain related stock options. In 2001, the Company recognized approximately
$300,000 in other nonrecurring gains.
The Company expensed approximately $241,000 in 2000 for costs primarily
associated with investment banking fees, an abandoned acquisition effort and the
abandonment of a proposed public offering of a royalty trust.
F-17
(7) DETAILS OF BALANCE SHEETS
DECEMBER 31,
----------------------------------
2002 2001
--------------- ---------------
(IN THOUSANDS)
ACCOUNTS RECEIVABLE
Accounts receivable $ 7,610 $ 6,701
Allowance for doubtful accounts (1,588) (1,684)
Oil and gas production receivable 8,417 7,789
Current portion of notes receivable 213 529
--------------- ---------------
$ 14,652 $ 13,335
=============== ===============
INVENTORIES
Oil $ 665 $ 1,352
Natural gas 18 27
Material, pipe and supplies 165 316
--------------- ---------------
$ 848 $ 1,695
=============== ===============
PROPERTY AND EQUIPMENT, GROSS
OIL AND GAS PROPERTIES
Producing properties $ 406,336 $ 395,814
Non-producing properties 14,291 12,066
Other 17,613 15,674
--------------- ---------------
$ 438,240 $ 423,554
=============== ===============
LAND, BUILDINGS, MACHINERY AND EQUIPMENT
Land, buildings and improvements $ 5,168 $ 5,144
Machinery and equipment 17,580 18,023
--------------- ---------------
$ 22,748 $ 23,167
=============== ===============
ACCRUED EXPENSES
Accrued expenses $ 5,870 $ 4,830
Accrued drilling and completion costs 3,480 827
Accrued income taxes 85 93
Ad valorem and other taxes 1,619 1,903
Compensation and related benefits 2,222 2,748
Undistributed production revenue 4,491 4,017
--------------- ---------------
$ 17,767 $ 14,418
=============== ===============
F-18
(8) LONG-TERM DEBT
Long-term debt consists of the following (in thousands):
DECEMBER 31,
----------------------------------
2002 2001
--------------- --------------
Revolving line of credit $ 26,764 $ 59,292
Senior subordinated notes 225,000 225,000
Other 286 142
--------------- --------------
252,050 284,434
Less current portion 182 19
--------------- --------------
Long-term debt $ 251,868 $ 284,415
=============== ==============
On June 27, 1997, the Company completed a private placement (pursuant
to Rule 144A) of $225 million of 9 7/8% Senior Subordinated Notes, Series A,
which mature on June 15, 2007 ("the Notes"). The Notes were issued under an
indenture which requires interest to be paid semiannually on June 15 and
December 15 of each year, commencing December 15, 1997. The Notes are
subordinate to the senior revolving credit agreement. In September 1997, the
Company completed a registration statement on Form S-4 providing for an exchange
offer under which each Series A Senior Subordinated Note would be exchanged for
a Series B Senior Subordinated Note. The terms of the Series B Notes are the
same in all respects as the Series A Notes except that the Series B Notes have
been registered under the Securities Act of 1933 and therefore will not be
subject to certain restrictions on transfer.
The Notes are redeemable in whole or in part at the option of the
Company, at any time on or after the dates below, at the redemption prices set
forth plus, in each case, accrued and unpaid interest, if any, thereon.
June 15, 2002.................................. 104.938%
June 15, 2003.................................. 103.292%
June 15, 2004.................................. 101.646%
June 15, 2005 and thereafter................... 100.000%
The indenture under which the subordinated notes were issued contains
certain covenants that limit the ability of the Company and its subsidiaries to
incur additional indebtedness and issue stock, pay dividends, make
distributions, make investments, make certain other restricted payments, enter
into certain transactions with affiliates, dispose of certain assets, incur
liens securing indebtedness of any kind other than permitted liens, and engage
in mergers and consolidations.
On August 23, 2000, the Company obtained a new $125 million credit
facility ("the Facility") comprised of a $100 million revolving credit facility
("the Revolver") and a $25 million term loan (the "Term Loan"). The Facility
allowed for up to $40 million ($25 million under the Term Loan and $15 million
under the Revolver) to be used to purchase the Company's outstanding 9 7/8%
senior subordinated notes due 2007. No amounts were drawn under the Term Loan.
The Term Loan commitment terminated on December 26, 2000 and the Company wrote
off approximately $740,000 of unamortized deferred loan costs in 2000 due to the
modification of borrowing capacity. Up to $40 million in letters of credit may
be issued pursuant to the conditions of the Revolver.
Initial proceeds from the Revolver of approximately $66 million in 2000
were used to pay outstanding loans and interest due under the Company's former
credit facility of approximately $46
F-19
million; repay a term loan of $14 million to Chase Manhattan Bank; pay fees and
expenses associated with the new credit facility of approximately $4 million;
and to close out certain natural gas hedging transactions with Chase Manhattan
Bank. Due to the payment of the outstanding loans under the former credit
facility the Company took a charge of $2.1 million ($1.4 million net of tax
benefit) in 2000 representing the unamortized deferred loan costs pertaining to
the former credit facility. The charge was recorded as an extraordinary item.
During 2002, amendments to the Company's $100 million revolving credit
facility extended the Revolver's final maturity date to December 31, 2005, from
April 22, 2004, increased the letter of credit sub-limit from $30 million to
$40 million and permitted the Company to enter into the transactions to sell
oil and gas properties consisting of 1,138 wells in Ohio and 962 wells in New
York and Pennsylvania.
The Revolver, as amended, is subject to certain financial covenants.
These include a quarterly senior debt interest coverage ratio of 3.2 to 1
extended through September 30, 2005; and a senior debt leverage ratio of 2.7 to
1 extended through September 30, 2005. The amendment extended the early
termination fee, equal to .125% of the Revolver, through December 31, 2004.
There is no termination fee after December 31, 2004. The Company is required to
hedge, through financial instruments or fixed price contracts, at least 20% but
not more than 80% of its estimated hydrocarbon production, on a Mcfe basis, for
the succeeding 12 months on a rolling 12-month basis. Based on the Company's
hedges currently in place and its expected production levels, the Company is in
compliance with this hedging requirement through May 2005.
The Revolver bears interest at the prime rate plus two percentage
points, payable monthly. At December 31, 2002, the interest rate was 6.25%. At
December 31, 2002, the Company had $18.4 million of outstanding letters of
credit. At December 31, 2002, the outstanding balance under the credit agreement
was $26.8 million with $54.8 million of borrowing capacity available for general
corporate purposes.
The Revolver is secured by security interests and mortgages against
substantially all of the Company's assets and is subject to periodic borrowing
base determinations. The borrowing base is the lesser of $100 million or the sum
of (i) 65% of the value of the Company's proved developed producing reserves
subject to a mortgage; (ii) 45% of the value of the Company's proved developed
non-producing reserves subject to a mortgage; and (iii) 40% of the value of the
Company's proved undeveloped reserves subject to a mortgage. The price forecast
used for calculation of the future net income from proved reserves is the
three-year NYMEX strip for oil and natural gas as of the date of the reserve
report. Prices beyond three years are held constant. Prices are adjusted for
basis differential, fixed price contracts and financial hedges in place. The
weighted average price at December 31, 2002, was $4.14 per Mcfe. The present
value (using a 10% discount rate) of the Company's future net income at December
31, 2002, using the borrowing base price forecast was $358 million. The present
value under the borrowing base formula above, was approximately $210 million for
all proved reserves of the Company and $152 million for properties secured by a
mortgage.
The Revolver is subject to certain financial covenants. These include a
senior debt interest coverage ratio of 3.2 to 1 and a senior debt leverage ratio
of 2.7 to 1. EBITDA, as defined in the Revolver, and consolidated interest
expense on senior debt in these ratios are calculated quarterly based on the
financial results of the previous four quarters. In addition, the Company is
required to maintain a current ratio (including available borrowing capacity in
current assets, excluding current debt and accrued interest from current
liabilities and excluding any effects from the application of SFAS 133 to other
current assets or current liabilities) of at least 1.0 to 1 and maintain
liquidity of at least $5 million (cash and cash equivalents including available
borrowing capacity). As of December 31, 2002, the Company's
F-20
current ratio including the above adjustments was 3.48 to 1. The Company had
satisfied all financial covenants as of December 31, 2002.
From time to time the Company may enter into interest rate swaps to
hedge the interest rate exposure associated with the credit facility, whereby a
portion of the Company's floating rate exposure is exchanged for a fixed
interest rate. On March 21, 2000, the Company terminated several interest rate
swaps covering $80 million of swaps which resulted in a gain of $1.3 million.
The remaining swap arrangements covering $40 million of debt expired in October
2000.
At December 31, 2002, the aggregate long-term debt maturing in the next
five years is as follows: $182,000 (2003); $5,000 (2004); $26,770,000 (2005);
$6,000 (2006) and $225,087,000 (2007 and thereafter).
(9) LEASES
The Company leases certain computer equipment, vehicles, natural gas
compressors and office space under noncancelable agreements with lease periods
of one to five years. Rent expense amounted to $2.8 million, $2.9 million and
$2.7 million for the years ended December 31, 2002, 2001 and 2000, respectively.
The Company also leases certain computer equipment accounted for as
capital leases. Property and equipment includes $747,000 and $647,000 of
computer equipment under capital leases at December 31, 2002 and 2001,
respectively. Accumulated depreciation for such equipment includes approximately
$523,000 and $289,000 at December 31, 2002 and 2001, respectively.
Future minimum commitments under leasing arrangements at December 31,
2002 were as follows:
YEAR ENDING DECEMBER 31, 2002 OPERATING LEASES CAPITAL LEASES
- ------------------------------------------------- ---------------- --------------
(IN THOUSANDS)
2003 $ 3,407 $ 134
2004 2,611 72
2005 2,231 --
2006 1,945 --
2007 and thereafter 1,399 --
-------------- --------------
Total minimum rental payments $ 11,593 206
==============
Less amount representing interest 2
--------------
Present value of net minimum rental payments 204
Less current portion 133
--------------
Long-term capitalized lease obligations $ 71
==============
(10) STOCK OPTION PLANS
In connection with the TPG merger, certain executives of the Company
agreed not to exercise or surrender certain stock options granted under the
Company's 1991 stock option plan. On June 27, 1997, these options were exchanged
for 165,083 in new stock options. As of December 31, 2002, none of these options
were outstanding. No additional options may be granted under the 1991 plan.
F-21
The Company has a 1997 non-qualified stock option plan under which it
is authorized to issue up to 1,824,195 shares of common stock to officers and
employees. The exercise price of options may not be less than the fair market
value of a share of common stock on the date of grant. Options expire on the
tenth anniversary of the grant date unless cessation of employment causes
earlier termination. As of December 31, 2002, options to purchase 684,456 shares
were outstanding under the plan. These options, except for the 100,000 options
described below, become exercisable at a rate of one fourth of the shares one
year from the date of grant and an additional one twelfth of the remaining
shares on every three-month anniversary thereafter. The remaining 100,000
options become exercisable at a rate of one fourth of the shares on the last day
of each quarter commencing June 30, 2003.
During 2002 and 2001, certain employees that retired or were previously
terminated elected to put their vested stock options back to the Company. As a
result, the Company paid approximately $30,000 and $772,000 to purchase and
cancel 13,814 and 219,644 options during 2002 and 2001, respectively.
Stock option activity consisted of the following:
WEIGHTED
AVERAGE
NUMBER OF EXERCISE
SHARES PRICE
------------- ------------
BALANCE AT DECEMBER 31, 1999 756,298 $ 0.53
Granted 274,692 0.22
Forfeitures (65,000) 5.83
Exercised (96,798) 0.01
-------------
BALANCE AT DECEMBER 31, 2000 869,192 0.09
Granted 358,500 3.14
Forfeitures (158,594) 0.56
Exercised or put (287,492) 0.08
Reissued and repriced (227,500) 3.59
Reissued and repriced 227,500 2.14
-------------
BALANCE AT DECEMBER 31, 2001 781,606 0.97
Granted 35,000 2.14
Forfeitures (52,999) 1.58
Exercised or put (79,151) 0.07
-------------
BALANCE AT DECEMBER 31, 2002 684,456 1.09
=============
OPTIONS EXERCISABLE AT DECEMBER 31, 2002 310,879 $ 0.41
=============
The weighted average fair value of options granted during 2002, 2001
and 2000 was $0.52, $0.79 and $0.07, respectively. The exercise price for the
options outstanding as of December 31, 2002 ranged from $0.01 to $2.14 per
share. At December 31, 2002, the weighted average remaining contractual life of
the outstanding options is 7.4 years.
F-22
(11) TAXES
The provision (benefit) for income taxes on income from continuing
operations before extraordinary item includes the following (in thousands):
YEAR ENDED DECEMBER 31,
--------------------------------------------------
2002 2001 2000
--------------- --------------- ---------------
CURRENT
Federal $ (190) $ 114 $ 290
State 76 -- 1
--------------- --------------- ---------------
(114) 114 291
DEFERRED
Federal 2,140 (1,004) 1,543
State 430 (65) (80)
--------------- --------------- ---------------
2,570 (1,069) 1,463
--------------- --------------- ---------------
TOTAL $ 2,456 $ (955) $ 1,754
=============== =============== ===============
The effective tax rate for income from continuing operations before
extraordinary item differs from the U.S. federal statutory tax rate as follows:
YEAR ENDED DECEMBER 31,
-------------------------------------------
2002 2001 2000
------------ ------------- ------------
Statutory federal income tax rate 35.0 % 35.0 % 35.0 %
Increases (reductions) in taxes resulting from:
State income taxes, net of federal tax benefit 5.3 -- 2.3
Settlement of IRS exam and other tax issues -- (40.9) --
Change in valuation allowance -- (14.5) (1.6)
Other, net (0.7) 0.6 (1.8)
------------ ------------- ------------
Effective income tax rate for the period 39.6 % (19.8)% 33.9 %
============ ============= ============
During 2001, the Company concluded an IRS income tax examination of the
years 1994 through 1997 and favorably settled other tax issues. A federal income
tax benefit of $2.0 million was recorded as a result. Also during 2001, a
federal income tax benefit was recorded for approximately $700,000 along with a
corresponding reduction in the valuation allowance as a result of certain net
operating loss carryforwards which the Company now believes it can fully
utilize.
F-23
Significant components of deferred income tax liabilities and assets
are as follows (in thousands):
DECEMBER 31, DECEMBER 31,
2002 2001
--------------- ---------------
Deferred income tax liabilities:
Property and equipment, net $ 46,698 $ 40,529
Fair value of derivatives -- 8,627
Other, net -- 1,608
--------------- ---------------
Total deferred income tax liabilities 46,698 50,764
Deferred income tax assets:
Accrued expenses 2,666 1,338
Fair value of derivatives 2,449 --
Net operating loss carryforwards 22,900 25,401
Tax credit carryforwards 913 1,103
Other, net 514 610
Valuation allowance (1,140) (1,140)
--------------- ---------------
Total deferred income tax assets 28,302 27,312
--------------- ---------------
Net deferred income tax liability $ 18,396 $ 23,452
=============== ===============
Current liability $ -- $ 5,470
Long-term liability 22,596 17,982
Current asset (4,200) --
--------------- ---------------
Net deferred income tax liability $ 18,396 $ 23,452
=============== ===============
SFAS No. 109 requires a valuation allowance to be recorded when it is
more likely than not that some or all of the deferred tax assets will not be
realized. The valuation allowance at December 31, 2002 relates principally to
certain net operating loss carryforwards which management estimates will expire
before they can be utilized.
At December 31, 2002, the Company had approximately $56 million of net
operating loss carryforwards available for federal income tax reporting
purposes. These net operating loss carryforwards, if unused, will expire in
2012, 2018 and 2019. The Company has alternative minimum tax credit
carryforwards of approximately $900,000 which have no expiration date. The
Company has approximately $1.0 million of statutory depletion carryforwards,
which have no expiration date.
(12) PROFIT SHARING AND RETIREMENT PLANS
The Company has a non-qualified profit sharing arrangement under which
the Company contributes discretionary amounts determined by the compensation
committee of its Board of Directors based on attainment of performance targets.
Amounts are allocated to substantially all employees based on relative
compensation. The Company expensed $1.1 million, $1.4 million and $1.6 million
for the years ended December 31, 2002, 2001 and 2000, respectively, for
contributions to the profit sharing plan and discretionary bonuses. All amounts
were paid in cash.
As of December 31, 2002, the Company has a qualified defined
contribution plan (a 401(k) plan) covering substantially all of the employees of
the Company. Eligible employees may make voluntary
F-24
contributions which the Company matches $1.00 for every $1.00 contributed up to
4% of an employee's annual compensation and a $0.50 match for every $1.00
contributed up to the next 2% of compensation. Retirement plan expense amounted
to $557,000, $550,000 and $650,000 for the years ended December 31, 2002, 2001
and 2000, respectively.
Prior to January 1, 2002, the Company matched $0.50 for every $1.00
contributed up to 6% of an employee's annual compensation on voluntary
contributions and an amount equal to 2% of participants' compensation was
contributed by the Company to the plan each year. Effective January 1, 2002, the
previous contribution made by the Company in the amount equal to 2% of
participants' compensation each year was eliminated.
(13) COMMITMENTS AND CONTINGENCIES
In April 2002, the Company was notified of a claim by an overriding
royalty interest owner in Michigan alleging the underpayment of royalty
resulting from disputes as to the interpretation of the terms of several farmout
agreements. The Company believes there will be no material amount payable above
and beyond the amount accrued as of December 31, 2002 and therefore, the result
will have no material adverse effect on its financial position, results of
operation or cash flows.
The Company was audited by the state of West Virginia for the years
1996 through 1998. The state assessed taxes which the Company has contested and
filed a petition for reassessment. In February 2003, the Company was notified by
the State Tax Commissioner of West Virginia that the Company's petition for
reassessment had been denied and taxes due, plus accrued interest, are now
payable. The Company disagrees with the decision and will appeal. The Company
believes there will be no material amount payable above and beyond the amount
accrued as of December 31, 2002 and therefore, the result will have no material
adverse effect on its financial position, results of operations or cash flows.
In February 2000, four individuals filed a suit in Chautauqua County,
New York on their own behalf and on the behalf of others similarly situated,
seeking damages for the alleged difference between the amount of lease royalties
actually paid and the amount of royalties that allegedly should have been paid.
Other natural gas producers in New York were served with similar complaints. The
Company believes the complaint is without merit and is defending the complaint
vigorously. Although the outcome is still uncertain, the Company believes the
action will not have a material adverse effect on its financial position,
results of operations or cash flows. The Company no longer owns the wells that
were subject to the suit.
The Company was subject to binding arbitration on an issue regarding
the valuation of shares of common stock put back to the Company in 1999 pursuant
to a former executive officer's employment agreement. In March 2003, the
arbitrator ruled that the Company must repurchase 31,168 shares of common stock
for approximately $337,000 plus interest from the date of the employment
agreement. The Company will pay approximately $516,000 in 2003 based on the
ruling. The Company has reported the stock purchase as treasury stock in 2002
and has also accrued the interest amount through December 31, 2002.
The Company is involved in several lawsuits arising in the ordinary
course of business. The Company believes that the result of such proceedings,
individually or in the aggregate, will not have a material adverse effect on the
Company's financial position, results of operations or cash flows.
Environmental costs, if any, are expensed or capitalized depending on
their future economic benefit. Expenditures that relate to an existing condition
caused by past operations and that have no future economic benefits are expensed
as incurred. Expenditures that extend the life of the related property or reduce
or prevent future environmental contamination are capitalized. Liabilities
related to environmental matters are only recorded when an environmental
assessment and/or remediation
F-25
obligation is probable and the costs can be reasonably estimated. Such
liabilities are undiscounted unless the timing of cash payments for the
liability are fixed or reliably determinable. At December 31, 2002, no
significant environmental remediation obligation exists which is expected to
have a material effect on the Company's financial position, results of
operations or cash flows.
(14) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
YEAR ENDED DECEMBER 31,
---------------------------------------
(IN THOUSANDS) 2002 2001 2000
----------- ----------- -----------
CASH PAID DURING THE PERIOD FOR:
Interest $ 23,750 $ 27,737 $ 30,634
Income taxes, net of refunds (221) 359 1
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Acquisition of assets in exchange for long-term liabilities 281 443 239
(15) FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of the financial instruments disclosed herein is not
representative of the amount that could be realized or settled, nor does the
fair value amount consider the tax consequences, if any, of realization or
settlement. The amounts in the financial statements for cash equivalents,
accounts receivable and notes receivable approximate fair value due to the short
maturities of these instruments. The recorded amounts of outstanding bank and
other long-term debt approximate fair value because interest rates are based on
LIBOR or the prime rate or due to the short maturities. The $225 million in
senior subordinated notes had an approximate fair value of $196 million at
December 31, 2002 based on quoted market prices.
From time to time the Company may enter into a combination of futures
contracts, commodity derivatives and fixed-price physical contracts to manage
its exposure to natural gas or oil price volatility. The Company employs a
policy of hedging gas production sold under NYMEX based contracts by selling
NYMEX based commodity derivative contracts which are placed with major financial
institutions that the Company believes are minimal credit risks. The contracts
may take the form of futures contracts, swaps, collars or options. At December
31, 2002, the Company's derivative contracts consisted of natural gas swaps and
natural gas costless collars. All of these NYMEX based derivative contracts are
designated as cash flow hedges. The Company incurred a pre-tax gain on its
hedging activities of $21.6 million in 2002, $4.5 million in 2001 and a pre-tax
loss on its hedging activities of $9.3 million in 2000. At December 31, 2002,
the fair value of futures contracts covering 2003 through 2005 natural gas
production represented an unrealized loss of $9.9 million.
F-26
(16) SUPPLEMENTARY INFORMATION ON OIL AND GAS ACTIVITIES
The following disclosures of costs incurred related to oil and gas
activities are presented in accordance with SFAS 69 and include both continuing
and discontinued operations.
YEAR ENDED DECEMBER 31,
--------------------------------------------
(IN THOUSANDS) 2002 2001 2000
------------- ------------- ------------
Acquisition costs:
Proved properties $ 1,724 $ 2,399 $ 220
Unproved properties 5,364 5,574 2,093
Developmental costs 16,222 23,409 13,849
Exploratory costs 16,282 8,346 8,528
PROVED OIL AND GAS RESERVES (UNAUDITED)
The Company's proved developed and proved undeveloped reserves are all
located within the United States. The Company cautions that there are many
uncertainties inherent in estimating proved reserve quantities and in projecting
future production rates and the timing of development expenditures. In addition,
estimates of new discoveries are more imprecise than those of properties with a
production history. Accordingly, these estimates are expected to change as
future information becomes available. Material revisions of reserve estimates
may occur in the future, development and production of the oil and gas reserves
may not occur in the periods assumed, and actual prices realized and actual
costs incurred may vary significantly from those used. Proved reserves represent
estimated quantities of natural gas, crude oil and condensate that geological
and engineering data demonstrate, with reasonable certainty, to be recoverable
in future years from known reservoirs under economic and operating conditions
existing at the time the estimates were made. Proved developed reserves are
proved reserves expected to be recovered through wells and equipment in place
and under operating methods being utilized at the time the estimates were made.
The estimates of proved reserves as of December 31, 2002, 2001 and 2000 have
been reviewed by Wright & Company, Inc., independent petroleum engineers.
F-27
The following table sets forth changes in estimated proved and proved
developed reserves for the periods indicated:
OIL GAS
(MBBL) (1) (MMCF) (2) MMCFE (3)
-------------- --------------- ---------------
DECEMBER 31, 1999 6,699 306,691 346,885
Extensions and discoveries 386 15,622 17,938
Purchase of reserves in place -- 7,223 7,223
Sale of reserves in place (606) (65,567) (69,203)
Revisions of previous estimates 2,766 129,597 146,193
Production (592) (20,037) (23,589)
-------------- --------------- ---------------
DECEMBER 31, 2000 8,653 373,529 425,447
Extensions and discoveries 285 13,591 15,301
Purchase of reserves in place -- 28,557 28,557
Sale of reserves in place (54) (1,129) (1,453)
Revisions of previous estimates (2,651) (61,780) (77,686)
Production (646) (18,541) (22,417)
-------------- --------------- ---------------
DECEMBER 31, 2001 5,587 334,227 367,749
Extensions and discoveries 32 2,382 2,574
Purchase of reserves in place 13 21,300 21,378
Sale of reserves in place (741) (29,179) (33,625)
Revisions of previous estimates 2,206 23,894 37,130
Production (523) (17,106) (20,244)
-------------- --------------- ---------------
DECEMBER 31, 2002 6,574 335,518 374,962
============== =============== ===============
PROVED DEVELOPED RESERVES
December 31, 2000 5,954 251,747 287,471
============== =============== ===============
December 31, 2001 4,788 218,148 246,876
============== =============== ===============
December 31, 2002 4,103 206,719 231,337
============== =============== ===============
(1) THOUSAND BARRELS (2) MILLION CUBIC FEET (3) MILLION CUBIC FEET EQUIVALENT
F-28
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVES (UNAUDITED)
The following tables, which present a standardized measure of
discounted future net cash flows and changes therein relating to proved oil and
gas reserves, are presented pursuant to SFAS No. 69. In computing this data,
assumptions other than those required by the FASB could produce different
results. Accordingly, the data should not be construed as representative of the
fair market value of the Company's proved oil and gas reserves. The following
assumptions have been made:
- Future revenues were based on year-end oil and gas prices.
Future price changes were included only to the extent provided
by existing contractual agreements.
- Production and development costs were computed using year-end
costs assuming no change in present economic conditions.
- Future net cash flows were discounted at an annual rate of 10%.
- Future income taxes were computed using the approximate
statutory tax rate and giving effect to available net
operating losses, tax credits and statutory depletion.
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves is presented below:
DECEMBER 31,
-------------------------------------------------
2002 2001 2000
-------------- --------------- --------------
(IN THOUSANDS)
Estimated future cash inflows (outflows)
Revenues from the sale of oil and gas $ 1,855,414 $ 1,075,151 $ 3,835,298
Production costs (423,643) (396,654) (633,567)
Development costs (167,295) (130,723) (171,458)
-------------- --------------- --------------
Future net cash flows before income taxes 1,264,476 547,774 3,030,273
Future income taxes (412,193) (133,992) (1,037,843)
-------------- --------------- --------------
Future net cash flows 852,283 413,782 1,992,430
10% timing discount (519,464) (231,920) (1,171,666)
-------------- --------------- --------------
Standardized measure of discounted
future net cash flows $ 332,819 $ 181,862 $ 820,764
============== =============== ==============
At December 31, 2002, as specified by the SEC, the prices for oil and
natural gas used in this calculation were regional cash price quotes on the last
day of the year except for volumes subject to fixed price contracts. The
weighted average prices for the total proved reserves at December 31, 2002 were
$4.99 per Mcf of natural gas and $27.81 per barrel of oil. The Company does not
include its natural gas hedging financial instruments, consisting of natural gas
swaps and collars, in the determination of its oil and gas reserves.
F-29
The principal sources of changes in the standardized measure of future
net cash flows are as follows:
YEAR ENDED DECEMBER 31,
--------------------------------------------
2002 2001 2000
------------- ------------- ------------
(IN THOUSANDS)
Beginning of year $ 181,862 $ 820,764 $ 216,888
Sale of oil and gas, net of production costs (73,351) (72,132) (56,416)
Extensions and discoveries, less related estimated
future development and production costs 7,153 8,721 69,990
Purchase of reserves in place less
estimated future production costs 26,385 7,924 13,383
Sale of reserves in place less
estimated future production costs (16,727) (3,226) (50,817)
Revisions of previous quantity estimates 53,423 (63,294) 445,976
Net changes in prices and production costs 239,368 (1,026,055) 608,442
Change in income taxes (103,641) 371,059 (363,561)
Accretion of 10% timing discount 22,499 123,495 26,751
Changes in production rates (timing) and other (4,152) 14,606 (89,872)
------------- ------------- ------------
End of year $ 332,819 $ 181,862 $ 820,764
============= ============= ============
(17) INDUSTRY SEGMENT FINANCIAL INFORMATION
The Company operates in one reportable segment, as an independent
energy company engaged in producing oil and natural gas; exploring for and
developing oil and gas reserves; acquiring and enhancing the economic
performance of producing oil and gas properties; and marketing and gathering
natural gas for delivery to intrastate and interstate gas transmission
pipelines. The Company's operations are conducted entirely in the United States.
MAJOR CUSTOMERS
One customer accounted for more than 10% of consolidated revenues
during each of the years ended December 31, 2002, 2001 and 2000, sales to which
amounted to $12.9 million, $21.0 million and $21.6 million, respectively.
F-30
(18) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The results of operations for the four quarters of 2002 and 2001 are
shown below (in thousands).
FIRST SECOND THIRD FOURTH
----------- ----------- ----------- -----------
2002
Sales and other operating revenues $ 28,488 $ 30,217 $ 26,561 $ 26,820
Gross profit 9,488 9,706 8,045 5,447
Income (loss) from continuing operations 1,509 2,118 1,068 (950)
(Loss) income from discontinued operations, net of tax (65) 462 75 (1,752)
Net income (loss) 1,444 2,580 1,143 (2,702)
2001
Sales and other operating revenues $ 29,993 $ 29,435 $ 27,989 $ 29,422
Gross profit 9,508 9,456 8,125 5,836
Income (loss) from continuing operations 1,396 3,564 706 110
Income (loss) from discontinued operations, net of tax 666 228 (24) (179)
Net income (loss) 2,062 3,792 682 (69)
During the fourth quarter of 2002, the Company recorded a loss on sale
of $3.2 million ($1.8 million net of tax benefit) from discontinued operations
(see note 4). Sales and gross profit from all prior quarters presented have been
restated to reflect the discontinued operations.
The Company reclassified certain gas marketing revenues and oilfield
service revenues in the fourth quarter of 2002. This had no impact on gross
profit or net income (loss). Prior quarters in 2002 have been restated to
conform to the current presentation.
During 2002, the Company recorded exploratory dry hole expense of
approximately $4.6 million, of which $2.2 million was incurred in the fourth
quarter.
(19) SUBSEQUENT EVENT
In February 2003, the Company purchased reserves in certain wells the
Company operates in Michigan for $3.75 million in cash. These properties were
subject to a prior monetization transaction of the Section 29 tax credits which
the Company entered into in 1996. The Company had the option to purchase these
properties beginning in 2003. The Company previously held a production payment
on these properties including a 75% reversionary interest in certain future
production. The Company purchased those reserve volumes beyond its currently
held production payment along with the 25% reversionary interest not owned. The
estimated volumes acquired were 4.4 Bcf of proved developed producing gas
reserves.
F-31