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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, 2003
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: NONE
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 29, 2004, Belden & Blake Corporation had outstanding
10,427,831 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"). The Company undertakes no obligation
to publicly update or revise any forward-looking statement, whether as a result
of new information, future events, changes in assumptions, or otherwise.
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 larger 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, 2003, the Company conducted business
in Ohio, Pennsylvania, New York, Michigan, Kentucky, Indiana and West Virginia.
In the fourth quarter of 2003, the Company's net production was
approximately 50.6 Mmcfe (million cubic feet of natural gas equivalent) per day
consisting of 43.6 Mmcf (million cubic feet) of natural gas and 1,160 Bbls
(barrels) of oil per day. At December 31, 2003, the Company owned interests in
4,126 gross (3,155 net) productive oil and gas wells in Ohio, Pennsylvania, New
York and Michigan with proved reserves totaling 360 Bcfe (billion cubic feet of
natural gas equivalent) consisting of 323 Bcf (billion cubic feet) of natural
gas and 6.2 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 $597 million at December 31, 2003. The weighted average
prices related to proved reserves at December 31, 2003 were $6.19 per Mcf
(thousand cubic feet) for natural gas and $29.78 per Bbl for oil. At December
31, 2003, the Company operated approximately 3,400 wells (82% of the
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Company's gross wells), including wells operated for third parties. At that
date, the Company held leases on 1,118,512 gross (924,033 net) acres, including
477,434 gross (355,826 net) undeveloped acres. At December 31, 2003, the Company
owned and operated 1,254 miles of gas gathering systems with access to the
commercial and industrial gas markets of the northeastern United States.
During 2003, the Company drilled 98 gross (86.4 net) wells at a direct
cost, including exploratory dry hole expense, of approximately $33.9 million for
the net wells. The 2003 drilling activity added 20.5 Bcfe of proved developed
reserves at an average cost of $1.65 per Mcfe (thousand cubic feet of natural
gas equivalent). The cost was impacted by exploratory dry hole costs from wells
drilled in the Trenton Black River ("TBR") formations. Excluding the costs of
six exploratory dry holes drilled in the TBR during 2003, the average cost of
developing proved reserves was $1.31 per Mcfe. The Company also made production
enhancements to existing wells during the year which increased proved developed
reserves by 595 Mmcfe at an average cost of $1.31 per Mcfe. Acquisitions of
proved developed properties in 2003 added 4.6 Bcfe of proved developed reserves
at an average cost of $0.83 per Mcfe. Proved developed reserves added through
drilling, enhancements and acquisitions in 2003 represented approximately 148%
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
The Company's production volumes declined from 2002 to 2003 due to the
sale of wells during 2002, the natural decline of the wells and cold weather in
the first quarter of 2003. These declines were partially offset by new drilling
and other production enhancement actions taken during 2002 and 2003. Production
volumes bottomed out in the first quarter of 2003 at 45.0 Mmcfe per day
following the asset sales in 2002 and increased each quarter throughout 2003,
reaching 50.6 Mmcfe per day in the fourth quarter of 2003. The fourth quarter
2003 production rate was an increase of 11% over the fourth quarter of 2002 and
a 12% increase over the first quarter of 2003.
During 2003, the Company completed its first successful exploratory TBR
wells. Through December 31, 2003, the Company has drilled six successful TBR
wells including the recently announced two significant discoveries in New York.
The first of these two wells began production in December 2003 and is currently
producing at a rate of approximately 3.5 to 4.0 Mmcf of natural gas per day (1.4
to 1.6 Mmcf per day net to the Company's interest). The second well began
production in March 2004 and is currently producing at a pipeline-restricted
rate of approximately 3.4 Mmcf of natural gas per day (1.5 Mmcf per day net
to the Company's interest). These two wells are in addition to two other
successful wells that began producing earlier in the year. Two additional wells
have been completed in the TBR and are awaiting completion of pipelines to
begin production. The Company's completion rate for wells drilled to the TBR in
2002 and 2003 is 35%. All three of the TBR wells drilled in one area of
south-central New York have been completed as producers. The Company plans to
drill five TBR wells in this area in 2004.
In the fourth quarter of 2003, the Company completed a review of its
current undeveloped acreage position relative to drilling results in various
areas. In addition to its successful TBR drilling in 2003, the Company drilled
six exploratory dry holes in the TBR. The cost of these exploratory TBR dry
holes was approximately $7.0 million. The Company determined that a portion of
its acreage in certain exploratory TBR areas had a fair value of less than its
book value. As a result, an impairment of approximately $4.7 million was
recorded to reduce the book value of the TBR acreage to its estimated fair
value. Additionally, an impairment of approximately $460,000 was recorded to
reduce the book value of other acreage to its estimated fair value.
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The Company's $100 million revolving credit facility (the "Revolver")
was amended on March 31, 2003 to increase the letter of credit sub-limit to $55
million. On May 30, 2003, the Company amended the Revolver to increase the total
commitment amount from $100 million to $125 million solely to provide for a
special letter of credit facility in the amount of $25 million which combined
with the existing letter of credit sub-limit of $55 million would allow a total
of $80 million in letters of credit. The amendment also extended the Revolver's
final maturity date to June 30, 2006, from December 31, 2005.
On March 9, 2004, the Company announced that it had engaged Randall &
Dewey Partners, L.P., an oil and gas strategic advisory and consulting firm
based in Houston, Texas, to assist the Company in evaluating its strategic
alternatives.
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
larger 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 and to a lesser extent deeper formations.
Drilling completion rates of the Company and others drilling in these shallow,
highly developed blanket 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.
During 2003, the Company strategically acquired approximately 20,096
gross (11,532 net) leasehold acres with potential in the deeper, less developed
TBR formations. The Company drilled 12 gross (8.2 net) wells to the TBR,
including three wells that were classified as wells in progress at December 31,
2002, at a cost of $15.9 million. Six of these wells (3.4 net wells) were
completed in the TBR and six (4.8 net) wells were exploratory dry holes. The six
successful wells added 4.7 Bcfe of proved developed reserves net to the
Company's interests.
The Company currently holds approximately 313,000 gross (215,000 net)
leasehold acres and approximately 525 miles of 2-D seismic and 50 square miles
of 3-D seismic data in prospective TBR areas in the Appalachian Basin and
intends to continue to lease additional acreage and acquire additional
3
seismic data primarily in the currently productive TBR areas. The Company plans
to drill 13 gross (7.7 net) wells in these TBR areas in 2004.
The Company operates 139 producing coalbed methane ("CBM") wells in
Pennsylvania and holds leases on approximately 73,000 acres of prospective CBM
properties. Current gross production from these wells is 3.7 Mmcf (3.1 Mmcf net)
per day. The Company drilled six CBM wells in 2003 and plans to drill an
additional 18 CBM wells in 2004. The Company owns a 100% working interest in all
of its CBM wells.
During 2003, the Company also drilled 25 gross (24.0 net) development
Medina wells and 15 gross (15.0 net) development Clarendon wells in
Pennsylvania. The Company plans to continue this development drilling program by
drilling 25 gross (24.4 net) Medina wells and 15 gross (15.0 net) Clarendon
wells in 2004.
The Company, through its subsidiary, Ward Lake, currently operates 840
wells in the Michigan Basin producing approximately 34.9 Mmcf (18.8 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 20 years or more. 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.
During 2003, the Company drilled 33 gross (29.2 net) wells to the
Antrim Shale formation. The Company plans to drill 36 gross (33.1 net) to the
Antrim Shale formation in 2004.
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 fifteen to sixty cents per
Mcf higher than comparable NYMEX prices.
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
4
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 and 2003, 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 spent
approximately 46% of its drilling capital expenditures on highly developed
or blanket formations and approximately 54% of its drilling capital
expenditures on deeper, or less developed, potentially more prolific
prospects. The deeper wells drilled by the Company in 2002 and 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, 2003, the Company
had a deficit in shareholders' equity of $57.3 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 improve
production include modifying surface facilities, redesigning downhole
equipment and recompleting existing wells. These actions can result in
increased operating costs.
- - 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 82% 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
5
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 control 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 1,254 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.
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,
------------------------------------------------------------------
1999 2000 2001 2002 2003
---------- ---------- ---------- ---------- ----------
PRODUCTION
Gas (Mmcf) 26,988 20,037 18,541 17,106 14,912
Oil (Mbbl) 713 592 646 523 413
Total production (Mmcfe) 31,267 23,591 22,415 20,244 17,389
AVERAGE PRICE
Gas (per Mcf) $ 2.50 $ 3.17 $ 4.34 $ 4.84 $ 4.93
Oil (per Bbl) 16.57 27.29 23.04 22.72 28.06
Mcfe 2.54 3.38 4.26 4.67 4.89
AVERAGE COSTS (PER MCFE)
Production expense 0.70 0.89 1.01 1.04 1.15
Production taxes 0.10 0.10 0.11 0.09 0.14
Depletion 0.92 0.77 0.91 0.88 0.84
OPERATING MARGIN (PER MCFE) 1.74 2.39 3.14 3.54 3.60
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
6
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,
------------------------------------------------------------------
1999 2000 2001 2002 2003
---------- ---------- ---------- ---------- ----------
PRODUCTION
Gas (Mmcf) 19,812 17,371 17,164 15,882 14,909
Oil (Mbbl) 639 573 644 522 413
Total production (Mmcfe) 23,647 20,811 21,030 19,012 17,386
AVERAGE PRICE
Gas (per Mcf) $ 2.50 $ 3.14 $ 4.35 $ 4.95 $ 4.93
Oil (per Bbl) 16.51 27.35 23.04 22.72 28.06
Mcfe 2.54 3.38 4.26 4.76 4.89
AVERAGE COSTS (PER MCFE)
Production expense 0.73 0.89 1.00 1.05 1.15
Production taxes 0.08 0.10 0.11 0.09 0.14
Depletion 0.99 0.78 0.91 0.88 0.84
OPERATING MARGIN (PER MCFE) 1.73 2.39 3.15 3.62 3.60
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 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 2003, the Company drilled 79 gross (74.2 net) wells to highly
developed or shallow blanket formations in its operating area at a net direct
cost of approximately $15.7 million. The Company also drilled 19 gross (12.2
net) wells to less developed and deeper formations in 2003 at a net direct cost
of approximately $18.2 million, including exploratory dry hole expense. The
result of this drilling activity is shown in the table on page 11.
In 2004, the Company expects to spend approximately $27.4 million,
including exploratory dry hole expense, on development and exploratory drilling
of approximately 120 gross (106.3 net) wells. In 2004, the Company plans to
spend approximately 61% of its drilling capital expenditures on highly developed
or blanket formations and approximately 39% 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.
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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 139 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 76,000 CBM acres currently under lease in
Pennsylvania, the Company believes the CBM will contribute significantly to its
drilling portfolio. The Company plans to drill 18 gross (18.0 net) CBM wells in
2004.
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 36 gross (33.1 net) wells to the Antrim Shale formation in 2004.
In addition to its CBM and Antrim drilling, the Company also plans to
drill 25 gross (24.4 net) wells to the Medina formation and 15 gross (15.0 net)
wells to the Clarendon formation in Pennsylvania during 2004.
Certain typical characteristics of the highly developed or blanket
formations targeted by the Company are described below:
RANGE OF AVERAGE
DRILLING AND RANGE OF AVERAGE
COMPLETION COSTS PER GROSS RESERVES PER
RANGE OF WELL DEPTHS WELL COMPLETED WELL
-------------------- -------------------- ------------------
(IN FEET) (IN THOUSANDS) (IN MMCFE)
Ohio:
Clinton 3,000 - 5,500 $ 170 - 210 80 - 150
Pennsylvania:
Coalbed Methane 1,200 - 1,500 150 - 180 150 - 250
Clarendon 1,100 - 2,000 65 - 80 30 - 50
Medina 5,000 - 6,200 210 - 260 150 - 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 4.0 Bcf of natural gas
during
8
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 12 Bcf
of natural gas per well. With significant discoveries by the Company and other
operators in south-central New York, the Company believes the potential exists
for numerous opportunities in the Company's existing areas of operations. The
Company plans to drill five gross (3.0 net) wells in this area in 2004.
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.
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 2003, the Company strategically acquired approximately 20,096
gross (11,532 net) leasehold acres with potential in the deeper, less developed
TBR formations. The Company drilled 12 gross (8.2 net) wells to the TBR,
including three wells that were classified as wells in progress at December 31,
2002, at a cost of $15.9 million. Six of these wells (3.4 net wells) were
completed in the TBR and six (4.8 net) wells were exploratory dry holes. The six
successful wells added 4.7 Bcfe of proved developed reserves net to the
Company's interests.
The Company currently holds approximately 313,000 gross (215,000 net)
leasehold acres and approximately 575 miles of 2-D seismic and 50 square miles
of 3-D seismic data in prospective TBR areas in the Appalachian Basin and
intends to continue to lease additional acreage and acquire additional seismic
data primarily in the currently productive TBR areas.
Exploration and drilling activities in the TBR formations, found at
depths ranging from 2,000 to 12,000 feet, are focused on testing many of the
currently identified prospects and confirming potential future drill sites. In
2004, the Company anticipates spending approximately $9.2 million to drill 13
gross (7.7 net) wells on TBR acreage. In addition, the Company plans to spend
$1.2 million to acquire additional acreage and seismic data in the TBR,
including an additional 50 square miles of 3-D seismic.
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 two gross (1.0 net) wells to other deep formations in
2004. The Company also plans to drill 11 gross (7.1 net) exploratory wells in
Kentucky and Indiana to various shallow, less developed formations in 2004.
9
Certain typical characteristics of the less developed or deeper
formations targeted by the Company are described below:
AVERAGE DRILLING COSTS RANGE OF
---------------------- 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 2,000 - 12,000 $ 1,000 $ 1,600 500 - 3,200
Knox formations OH, NY 2,500 - 8,000 180 350 300 - 600
Niagaran Carbonate MI 4,500 - 5,500 300 600 900 - 1,500
Onondaga Limestone PA, NY 4,000 - 5,500 180 250 200 - 1,500
Oriskany Sandstone PA, NY 4,500 - 7,000 200 350 300 - 1,000
(1) TBR costs vary significantly based on the depths drilled. The average dry
hole cost ranges from approximately $125,000 for a 2,000 foot well to over $1.5
million for wells drilled to 12,000 feet. The average completed well cost ranges
from approximately $250,000 for a 2,000 foot well to over $3.0 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)
---------------------------------------------- --------------------------------------------------
1999 2000 2001 2002 2003 1999 2000 2001 2002 2003 (6)
------ ------ ------ ------ ------ ------- ------ ------ ------ ------
Productive:
Gross - 108 142 83 79 9(3) 17(4) 14(5) 12 9
Net - 83.6 130.6 63.7 74.2 2.1 7.2 7.4 6.2 4.9
Dry:
Gross - 3 3 1 - 9 21 16 16 10
Net - 2.6 3.0 0.9 - 2.7 10.7 8.0 8.4 7.3
Reserves developed-net
(Bcfe) - 15.4 20.6 15.2 15.3 0.5 2.5 2.3 1.6 5.2
Approximate cost (in
millions) $ - $ 11.5 $ 21.1 $ 13.3 $ 15.7 $ 0.8 $ 5.5 $ 3.5 $ 7.5 $ 18.2
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) One additional well which was dry in the Knox formations was subsequently
completed in shallower formations.
(4) Three additional wells which were dry in the Knox formations were
subsequently completed in the shallower Clinton formation.
(5) 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.
(6) Includes four wells that were classified as wells in progress in 2002.
ACQUISITION OF PRODUCING PROPERTIES
In 2003, the Company purchased reserves in certain wells the Company
operates in Michigan for $3.8 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.
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.
11
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.
DISPOSITION OF ASSETS
As a result of the Company's decision to shift focus away from
exploration and development activities in the Knox formation in Ohio, the
Company sold substantially all of its undeveloped Knox acreage in Ohio,
approximately 290,000 gross (272,000 net) acres, for approximately $2.8 million
in September 2003. The sale resulted in a loss of approximately $150,000. The
Company retained certain shallow development rights related to the Knox acreage.
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 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.
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 were relocated to maximize compression
efficiency. A gain on the sale of $168,000 was deferred and 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.
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
12
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 29, 2004, the Company had 305 full-time employees,
including 156 oil and gas exploration and production employees, 127 oilfield
service employees and 22 general and administrative employees. The Company's
management and technical staff in the categories above included 10 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 and 2001
was FirstEnergy Corp., sales to which amounted to $12.9 million and $21.0
million, respectively. During 2003, the Company had three customers that each
accounted for 10% or more of consolidated revenues. The three customers were WPS
Energy Services, Exelon Energy and National Fuel Gas with sales of $19.8
million, $11.5 million and $10.8 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, 2001, 2002 and 2003 determined in accordance with
the rules and regulations of the SEC. These estimates of proved reserves were
prepared 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,
--------------------------
2001 2002 2003
------ ------ ------
Estimated proved reserves
Gas (Bcf) 334.2 335.5 322.7
Oil (Mbbl) 5,587 6,574 6,176
Bcfe 367.7 375.0 359.8
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, 2003,
determined in accordance with the rules and regulations of the SEC, was $597
million ($416 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, 2003 without escalation, except where changes in
prices were fixed and readily determinable under existing contracts.
14
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 natural gas hedging financial
instruments, consisting of natural gas swaps and collars, in the determination
of its oil and gas reserves.
DECEMBER 31,
--------------------------
2001 2002 2003
------ ------ ------
Gas (per Mcf) $ 2.92 $ 4.99 $ 6.19
Oil (per barrel) 17.85 27.81 29.78
At December 31, 2003, 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 $4.75 per Mmbtu (million British thermal units) which
equated to a weighted average gas price of $5.09 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 $28.25 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 355 Bcfe. Estimated future net cash flows from
these reserves had a present value (discounted at 10 percent) before income
taxes of approximately $455 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. In 2001,
as a result of declining natural gas and oil prices, the Company recorded an
impairment of $1.4 million related to producing properties. No impairment was
recorded in 2002. In 2003, the Company recorded impairments of $5.2 million
related to unproved properties and $572,000 related to producing properties. The
impairment of unproved properties resulted primarily from a review of the
Company's undeveloped acreage in areas of unsuccessful TBR drilling. The
impairment does not terminate the Company's rights to develop the leasehold
acreage.
PRODUCING WELL DATA
As of December 31, 2003, the Company owned interests in 4,126 gross
(3,155 net) producing oil and gas wells and operated approximately 3,400 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 2003, the Company's net production was approximately 50.6
Mmcfe per day consisting of 43.6 Mmcf of natural gas and 1,160 Bbls of oil per
day.
15
The following table summarizes by state the Company's productive wells
at December 31, 2003:
DECEMBER 31, 2003
-------------------------------------------------------------
GAS WELLS OIL WELLS TOTAL
-------------------- ----------------- ----------------
STATE GROSS NET GROSS NET GROSS NET
- ------------- ------- --------- ------- ------ ------ ------
Ohio 939 764 875 807 1,814 1,571
Pennsylvania 701 570 461 460 1,162 1,030
New York 27 17 - - 27 17
Michigan 1,116 533 7 4 1,123 537
------- --------- ------- ------ ------ ------
2,783 1,884 1,343 1,271 4,126 3,155
======= ========= ======= ====== ====== ======
ACREAGE DATA
The following table summarizes by state the Company's gross and net
developed and undeveloped leasehold acreage at December 31, 2003:
DECEMBER 31, 2003
--------------------------------------------------------------------------
DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL ACREAGE
---------------------- ---------------------- ----------------------
STATE GROSS NET GROSS NET GROSS NET
- ------------- --------- --------- --------- --------- --------- ---------
Ohio 289,709 254,562 83,776 71,669 373,485 326,231
Pennsylvania 155,793 143,576 145,576 118,504 301,369 262,080
New York 137,502 132,048 144,957 74,120 282,459 206,168
Michigan 58,074 38,021 39,428 36,927 97,502 74,948
West Virginia - - 37,099 35,277 37,099 35,277
Kentucky - - 18,039 10,823 18,039 10,823
Indiana - - 8,559 8,506 8,559 8,506
--------- --------- --------- --------- --------- ---------
641,078 568,207 477,434 355,826 1,118,512 924,033
========= ========= ========= ========= ========= =========
Developed acreage includes 467,770 gross (430,255 net) acres of
undrilled acreage held by production under the terms of lease agreements.
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
16
above and beyond the amount accrued as of December 31, 2003 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 has appealed. The Company
believes there will be no material amount payable above and beyond the amount
accrued as of December 31, 2003 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 paid $521,000 in 2003 based on the ruling.
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, 2003, 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, RELATED
STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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 29, 2004 was as follows:
Number of
Title of Class Record Holders
- -------------- --------------
Common Stock 15
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) 1999 2000(3) 2001 2002(2) 2003(1)
- ---------------------------------------------------- --------- --------- --------- --------- ---------
CONTINUING OPERATIONS:
Revenues $ 130,628 $ 104,902 $ 118,883 $ 113,920 $ 109,102
Depreciation, depletion
and amortization 39,726 26,331 25,979 22,379 19,343
Impairment of oil and gas properties - 477 1,398 - 5,774
(Loss) income from continuing operations before
cummulative effect of change in accounting principle (17,922) 3,425 5,776 3,745 (4,610)
BALANCE SHEET DATA:
Working capital from continuing operations (43,893) 2,715 12,727 (6,466) (6,973)
Oil and gas properties and
gathering systems, net 267,986 212,714 223,180 220,397 236,075
Total assets 350,695 285,117 305,349 263,845 283,911
Long-term liabilities,
less current portion 303,731 286,858 284,745 251,959 277,132
Total shareholders' equity (deficit) (51,590) (48,313) (27,279) (44,645) (57,340)
(1) See Note 2 to the Consolidated Financial Statements. The cummulative effect
of change in accounting principle, net of tax, was $2.4 million.
(2) See Note 4 to the Consolidated Financial Statements for information on
discontinued operations.
(3) In March 2000, the Company sold Peake.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
The Company conducts its operations in the United States in one
reportable segment which is oil and gas exploration and production. 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 operates primarily in the Appalachian and Michigan Basins
(a region which includes Ohio, Pennsylvania, New York, West Virginia and
Michigan).
The Company earns revenue through the production and sale of natural
gas and oil and, to a lesser extent, from oilfield services, gas gathering and
marketing. The Company's financial results and cash flows can be significantly
impacted as commodity prices fluctuate widely in response to changing market
conditions. The Company utilizes derivative instruments on a portion of its
natural gas production to reduce the volatility of natural gas prices and to
protect cash flow available for its development drilling and exploration
program.
Commodity prices of natural gas and oil increased during 2003 over
2002. The monthly average settle for natural gas trading on the NYMEX increased
from $3.22 per Mmbtu during 2002 to $5.39 per Mmbtu during 2003. The Company's
average unit price for natural gas was $4.95 per Mcf in 2002 and $4.93 per Mcf
in 2003. The Company's selling price of natural gas is generally higher than the
NYMEX price due to the favorable regional basis received throughout its areas of
operations along with a favorable Btu content of its gas. The remainder of the
difference is due to fixed price contracts and its hedging
18
activities during 2002 and 2003. The price the Company received for its oil
sales was $22.72 per Bbl in 2002 and $28.06 per Bbl in 2003.
The Company's production volumes declined from 2002 to 2003 due to the
sale of wells during 2002, the natural decline of the wells and cold weather in
the first quarter of 2003. These declines were partially offset by new drilling
and other production enhancement actions taken during 2002 and 2003. Production
volumes bottomed out in the first quarter of 2003 at 45.0 Mmcfe per day
following the asset sales in 2002 and increased each quarter throughout 2003
reaching 50.6 Mmcfe per day in the fourth quarter of 2003. The fourth quarter
2003 production rate was an increase of 11% over the fourth quarter of 2002 and
a 12% increase over the first quarter of 2003.
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 more
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:
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.
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
19
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 prepared by independent petroleum engineers. Estimates
prepared by others may be higher or lower than these estimates.
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 are 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.
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.
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. Fair value is
determined 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. Impairment of unproved properties is based on the
estimated fair value of the property.
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).
20
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 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.
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.
ASSET RETIREMENT OBLIGATIONS
On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 143 amends SFAS 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies" to require the Company to
recognize a liability for the fair value of its asset retirement obligations
associated with its tangible, long-lived assets. The majority of the asset
retirement obligations recorded by the Company relate to the plugging and
abandonment (excluding salvage value) of its oil and gas properties.
NEW ACCOUNTING PRONOUNCEMENTS
On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 143 amends SFAS 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies" to require the Company to
recognize a liability for the fair value of its asset retirement obligations
associated with its tangible, long-lived assets. The majority of the asset
retirement obligations recorded by the Company relate to the plugging and
abandonment (excluding salvage value) of its oil and gas properties. At January
1, 2003, there were no assets legally restricted for purposes of settling asset
retirement obligations. The adoption of SFAS 143 resulted in a January 1, 2003
cumulative effect adjustment to record a $4.0 million increase in long-term
asset retirement obligation liabilities, a $621,000 increase in current asset
retirement obligation liabilities, a $3.2 million increase in the carrying value
of oil and gas assets, a $5.2 million decrease in accumulated depreciation,
depletion and amortization and a $1.4 million increase in deferred income tax
liabilities. The net effect of adoption was
21
to record a gain of $2.4 million, net of tax, as a cumulative effect of a change
in accounting principle in the Company's consolidated statement of operations in
the first quarter of 2003.
Subsequent to the adoption of SFAS 143, there has been no significant
current period activity with respect to additional retirement obligations,
settled obligations, accretion expense and revisions of estimated cash flows.
The unaudited pro forma income from continuing operations for the years ended
December 31, 2002 and 2001 was $4.3 million and $6.9 million, respectively, and
has been prepared to give effect to the adoption of SFAS 143 as if it had been
adopted on January 1, 2002 and January 1, 2001. Assuming retroactive application
of the change in accounting principle as of January 1, 2002, liabilities would
have increased approximately $6 million.
A reconciliation of the Company's liability for asset retirement
obligations for the year ended December 31, 2003 is as follows (in thousands):
Asset retirement obligation, December 31, 2002 $ -
Cumulative effect adjustment 4,603
Liabilities incurred 345
Liabilities settled (491)
Accretion expense 365
Revisions in estimated cash flows 294
----------
Asset retirement obligation, December 31, 2003 $ 5,116
==========
On January 1, 2003, the Company adopted 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 Accounting
Principles Board Opinion No. (APB) 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. The adoption of SFAS 145 did not have any
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 was effective for the
Company for disposal activities initiated after December 31, 2002. The adoption
of this standard did not have any effect on the Company's financial position,
results of operations or cash flows.
In January 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities - An Interpretation of Accounting Research Bulletin (ARB) 51."
FIN 46 is an interpretation of ARB 51, "Consolidated Financial Statements," and
addresses consolidation by business enterprises of variable interest entities
(VIEs). The primary objective of FIN 46 is to provide guidance on the
identification of, and financial reporting for, entities over which control is
achieved through means other than voting rights; such entities are known as
VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has
a variable interest that will absorb a majority of the entity's expected losses
if they occur, receive a majority of the entity's expected residual returns if
they occur, or both. An enterprise shall consider the rights and obligations
conveyed by its variable interests in making this determination. This guidance
applies immediately to VIEs created after January 31, 2003, and to VIEs in which
an enterprise obtains an
22
interest after that date. It applies in the first fiscal year or interim period
beginning after December 15, 2003, to VIEs in which an enterprise holds a
variable interest that it acquired before February 1, 2003. The adoption of FIN
46 did not have any effect on the Company's financial statement disclosures,
financial position, results of operations or cash flows.
In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This Statement is intended to
result in more consistent reporting of contracts as either freestanding
derivative instruments subject to Statement 133 in its entirety, or as hybrid
instruments with debt host contracts and embedded derivative features. SFAS 149
is effective for the Company's financial statements for the interim period
beginning July 1, 2003. The adoption of SFAS 149 did not have a material effect
on the Company's financial position, results of operations or cash flows.
In May 2003, the FASB issued SFAS 150, "Accounting for Financial
Instruments with Characteristics of both Liabilities and Equity." This Statement
establishes standards for classifying and measuring as liabilities certain
financial instruments that embody obligations of the issuer and have
characteristics of both liabilities and equity. Instruments that are indexed to
and potentially settled in an issuer's own shares that are not within the scope
of Statement 150 remain subject to existing guidance. SFAS 150 is effective for
the Company's financial statements for the interim period beginning July 1,
2003. The adoption of SFAS 150 did not have a material effect on the Company's
financial position, results of operations or cash flows.
The Company has been made aware of an issue regarding the application
of provisions of SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and
Other Intangible Assets," to oil and gas companies. The issue is whether SFAS
142 requires registrants to reclassify costs associated with mineral rights,
including both proved and unproved leasehold acquisition costs, as intangible
assets in the balance sheet, apart from other capitalized oil and gas property
costs. Historically, the Company and other oil and gas companies have included
the cost of oil and gas leasehold interests as part of oil and gas properties
and provided the disclosures required by SFAS 69, "Disclosures about Oil and Gas
Producing Activities."
If it is ultimately determined that SFAS 142 requires the Company to
reclassify costs associated with mineral rights from property and equipment to
intangible assets, the Company currently believes that its financial condition,
results of operations or cash flows would not be affected, since such intangible
assets would continue to be depleted and assessed for impairment in accordance
with existing successful efforts accounting rules and impairment standards. The
Company had undeveloped leasehold costs of $7.7 million and $14.2 million at
December 31, 2003 and 2002, respectively. The amount of potential balance sheet
reclassifications for developed leasehold costs has not been determined.
In December 2003, the FASB issued SFAS 132 (revised 2003), "Employers'
Disclosures about Pensions and Other Postretirement Benefits," an amendment of
SFAS 87, 88, and 106, and a revision of SFAS 132. This statement revises
employers' disclosures about pension plans and other postretirement benefit
plans. It does not change the measurement or recognition of those plans required
by FASB Statements No. 87, Employers' Accounting for Pensions, No. 88,
Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits, and No. 106, Employers' Accounting
for Postretirement Benefits Other Than Pensions. This Statement retains the
disclosure requirements contained in FASB Statement No. 132, Employers'
Disclosures about Pensions and Other Postretirement Benefits, which it replaces.
It requires additional disclosures to those in the original Statement 132 about
the assets, obligations, cash flows, and net periodic benefit cost of defined
benefit pension plans and other defined benefit postretirement plans. The
required information should be provided separately for pension plans and for
other postretirement benefit plans. This Statement is
23
effective for financial statements with fiscal years ending after December 15,
2003. The adoption of this standard did not have a material effect on the
Company's financial position, results of operations or cash flows.
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,
----------------------------------------------------------------------------
2003 2002 2001
---------------------- ---------------------- ----------------------
REVENUES
Oil and gas sales $ 85,023 77.9% $ 90,462 79.4% $ 89,491 75.3%
Gas gathering, marketing, and oilfield service 23,741 21.8 21,624 19.0 27,348 23.0
Other 338 0.3 1,834 1.6 2,044 1.7
--------- -------- --------- -------- --------- --------
109,102 100.0 113,920 100.0 118,883 100.0
EXPENSES
Production expense 19,937 18.2 19,936 17.5 20,952 17.6
Production taxes 2,455 2.3 1,789 1.6 2,298 1.9
Gas gathering, marketing, and oilfield service 21,378 19.6 17,996 15.8 22,760 19.1
Exploration expense 16,882 15.5 16,256 14.3 8,335 7.0
General and administrative expense 4,559 4.2 4,557 4.0 4,395 3.7
Franchise, property and other taxes 282 0.3 91 0.1 238 0.2
Depreciation, depletion and amortization 19,343 17.7 22,379 19.6 25,979 21.9
Impairment of oil and gas properties 5,774 5.3 - - 1,398 1.2
Accretion expense 365 0.3 - - - -
Derivative fair value gain (319) (0.3) - - - -
Severance and other nonrecurring expense - - 953 0.8 1,954 1.7
--------- -------- --------- -------- --------- --------
90,656 83.1 83,957 73.7 88,309 74.3
--------- -------- --------- -------- --------- --------
OPERATING INCOME 18,446 16.9 29,963 26.3 30,574 25.7
OTHER EXPENSE
Loss on sale of businesses - - 154 0.1 - -
Interest expense 25,537 23.4 23,608 20.7 25,753 21.7
--------- -------- --------- -------- --------- --------
(LOSS) INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES AND CUMULATIVE EFFECT
OF CHANGE IN ACCOUNTING PRINCIPLE (7,091) (6.5) 6,201 5.5 4,821 4.0
(Benefit) provision for income taxes (2,481) (2.3) 2,456 2.2 (955) (0.8)
--------- -------- --------- -------- --------- --------
(LOSS) INCOME FROM CONTINUING OPERATIONS
BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE (4,610) (4.2) 3,745 3.3 5,776 4.8
(Loss ) income from discontinued
operations, net of tax (111) (0.1) (1,280) (1.1) 691 0.6
--------- -------- --------- -------- --------- --------
(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE (4,721) (4.3) 2,465 2.2 6,467 5.4
Cumulative effect of change in accounting
principle, net of tax 2,397 2.2 - - - -
--------- -------- --------- -------- --------- --------
NET (LOSS) INCOME $ (2,324) (2.1)% $ 2,465 2.2% $ 6,467 5.4%
========= ======== ========= ======== ========= ========
24
The following Management's 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.
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 operations only.
YEAR ENDED DECEMBER 31,
--------------------------------------
2003 2002 2001
---------- ---------- ----------
PRODUCTION
Gas (Mmcf) 14,909 15,882 17,164
Oil (Mbbl) 413 522 644
Total production (Mmcfe) 17,386 19,012 21,030
AVERAGE PRICE
Gas (per Mcf) $ 4.93 $ 4.95 $ 4.35
Oil (per Bbl) 28.06 22.72 23.04
Mcfe 4.89 4.76 4.26
AVERAGE COSTS (PER MCFE)
Production expense 1.15 1.05 1.00
Production taxes 0.14 0.09 0.11
Depletion 0.84 0.88 0.91
OPERATING MARGIN (PER MCFE) 3.60 3.62 3.15
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
2003 COMPARED TO 2002
REVENUES
Net operating revenues decreased from $112.1 million in 2002 to $108.8
million in 2003. The decrease was due to lower gas sales revenues of $5.2
million and lower oil sales revenues of $266,000 partially offset by higher
revenues from gas gathering, marketing and oilfield service services of $2.1
million.
Gas volumes sold decreased 1.0 Bcf (6%) from 15.9 Bcf in 2002 to 14.9
Bcf in 2003 resulting in a decrease in gas sales revenues of approximately $4.8
million. Oil volumes sold decreased approximately 109,000 Bbls (21%) from
522,000 Bbls in 2002 to 413,000 Bbls in 2003 resulting in a decrease in oil
sales revenues of approximately $2.5 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 2002 and 2003.
The average price realized for the Company's natural gas decreased
$0.02 per Mcf to $4.93 per Mcf in 2003 compared to 2002 which decreased gas
sales revenues in 2003 by approximately $300,000. As a result of the Company's
hedging activities, gas sales revenues were decreased by $10.3 million ($0.69
per Mcf) in 2003 and increased by $21.6 million ($1.36 per Mcf) in 2002. The
average price paid for the Company's oil increased from $22.72 per barrel in
2002 to $28.06 per barrel in 2003 which increased oil sales revenues by
approximately $2.2 million.
25
The operating margin from oil and gas sales (oil and gas sales revenues
less production expense and production taxes) on a per unit basis decreased from
$3.62 per Mcfe in 2002 to $3.60 per Mcfe in 2003.
The increase in gas gathering, marketing and oilfield service revenues
was primarily due to a $5.1 million increase in oilfield service revenues
partially offset by a $3.0 million decrease in gas gathering and marketing
revenues. The increase in oilfield service revenues was due primarily to the
acquisition of a drilling consulting business in the second quarter of 2002. The
lower gas gathering and marketing revenues were the result of decreased gas
marketing activity, the termination of a gas marketing contract and lower
margins on a gathering system in Pennsylvania.
COSTS AND EXPENSES
Production expense in 2003 was flat with 2002 at $19.9 million.
Production expense in 2003 decreased due to the sale of wells in Ohio and
Pennsylvania during 2002, but this was offset by higher operating costs incurred
as a result of colder temperatures and greater amounts of snow during the first
quarter of 2003 coupled with increased costs to stimulate production on
declining wells in the higher oil and natural gas price environment of 2003.
These efforts increased production volumes during 2003 but also had the effect
of increasing the per unit cost. The average production cost increased from
$1.05 per Mcfe in 2002 to $1.15 per Mcfe in 2003. The per unit increase was
primarily due to the higher costs incurred during 2003 as discussed above and
due to certain fixed costs spread over fewer volumes in 2003.
Production taxes increased $666,000 from $1.8 million in 2002 to $2.5
million in 2003 primarily due to higher oil and gas prices in Michigan, where
production taxes are based on a percentage of revenues, excluding the effects of
hedging. Average per unit production taxes increased 50% from $0.09 per Mcfe in
2002 to $0.14 per Mcfe in 2003 primarily due to a 56% increase in the selling
price of natural gas in 2003, excluding the effects of hedging.
Exploration expense increased $626,000 from $16.3 million in 2002 to
$16.9 million in 2003 due to a $4.0 million increase in exploratory dry hole
cost, partially offset by a decrease in land leasing costs of $956,000, a
decrease in seismic costs of $1.7 million along with a decrease in expired or
dropped leases of $500,000. The increase in exploratory dry hole cost was
primarily due to the increased exploration activities in the TBR play. During
2003 the Company drilled six TBR wells with a cost of $7.0 million that were dry
holes compared with five wells in 2002 with a cost of $3.4 million.
Depreciation, depletion and amortization decreased by $3.1 million from
$22.4 million in 2002 to $19.3 million in 2003. This decrease was primarily due
to a $286,000 reduction in amortization of loan costs, a $404,000 reduction in
the amortization of nonconventional fuel source tax credits and a decrease in
depletion expense. Depletion expense decreased $2.1 million (12%) from $16.7
million in 2002 to $14.6 million in 2003 due to lower oil and gas volumes and a
lower depletion rate per Mcfe. Depletion per Mcfe decreased from $0.88 per Mcfe
in 2002 to $0.84 per Mcfe in 2003, primarily due to the effect of the adoption
of SFAS 143. The basis used to calculate depletion expense for oil and gas
properties was increased by the fair value of the estimated future plugging
liability and decreased by the gross amount of the estimated salvage value of
the well equipment.
Impairment of oil and gas properties was $5.8 million in 2003 due to
impairment of acreage of $5.2 million in certain areas and an impairment of
$572,000 in two of the Company's smaller producing pools. The Company impaired
the value of certain TBR acreage in areas where drilling resulted in dry holes
and where no future drilling is planned. The impairments reduced the property's
book value to its estimated fair value.
26
Accretion expense was $365,000 in 2003 as a result of the adoption of
SFAS 143 at the beginning of 2003.
Derivative fair value gain was $319,000 in 2003 related to certain
derivative instruments that are not designated as cash flow hedges. The gain
reflects the changes in fair value of those instruments.
The Company recorded severance and other nonrecurring charges of $1.0
million in 2002 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.
Interest expense increased $1.9 million (8%) from $23.6 million in 2002
to $25.5 million in 2003. This increase was due to a increase in average
outstanding borrowings and higher blended interest rates.
Income tax expense decreased $5.0 million from expense of $2.5 million
in 2002 to an income tax benefit of $2.5 million in 2003. The decrease in
expense is due to a decrease in income from continuing operations and a lower
effective tax rate in 2003.
Discontinued operations relating to the New York Medina wells sold in
2002 resulted in a net loss of $1.3 million in 2002 and $111,000 in 2003. The
2002 amount is primarily attributable to the $3.2 million ($1.8 million net of
tax benefit) loss recorded on the sale in 2002.
2002 COMPARED TO 2001
REVENUES
Net operating revenues decreased from $116.8 million in 2001 to $112.1
million in 2002. The decrease was due to lower oil sales revenues of $3.0
million, lower revenues from gas gathering, marketing and oilfield service
services of $5.7 million, partially offset by higher gas sales revenues of $4.0
million.
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 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 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.
27
The decrease in gas gathering, marketing and oilfield service revenues
was due to a decrease in gas marketing activity and the termination of a gas
marketing contract.
COSTS AND EXPENSES
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,
an increase in land leasing costs of $614,000, an 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 the Company's increased exploration activities in the TBR play
along with an increase in expired or dropped leases of $1.3 million.
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.
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.
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.
28
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 was primarily attributable to the $3.2 million ($1.8
million net of tax benefit) loss recorded on the sale in 2002.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
The primary sources of cash in the three-year period ended December 31,
2003 have been from funds generated from operations, asset dispositions and from
borrowings under the credit agreement. Funds used during this period were
primarily used for operations, exploration and development expenditures,
interest expense and repayment of debt. 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 following table summarizes the net cash flow from operations,
investing activities and financing activities:
YEAR ENDED DECEMBER 31,
-----------------------------------------
2003 2002 CHANGE
----------- ----------- -----------
(IN MILLIONS)
Cash flows provided by operating activities $ 27.1 $ 50.9 $ (23.8)
Cash flows from investing activities (48.2) (32.5) (15.7)
Cash flows from financing activities 20.2 (33.4) 53.6
Changes in cash from discontinued operations 0.6 14.8 (14.2)
----------- ----------- -----------
Net increase or decrease in cash and cash equivalents $ (0.3) $ (0.2) $ (0.1)
=========== =========== ===========
The Company's operating activities provided cash flows of $27.1 million
during 2003 compared to $50.9 million in 2002. The decrease was primarily due to
lower cash received for oil and gas revenues (net of hedging) of $11 million,
higher interest expense of $2 million and changes in working capital items of $9
million.
Cash flows used in investing activities increased in 2003 due to $11
million in lower asset sales in 2003 compared to 2002, $2 million of increased
acquisitions in 2003 and $3 million of increased capital expenditures.
Cash flows provided by financing activities in 2003 were primarily due
to borrowings on the credit facility during 2003 to fund the acquisitions,
exploration and development expenditures in 2003.
During 2003, working capital from continuing operations decreased
$507,000 from a deficit of $6.5 million at December 31, 2002 to a deficit of
$7.0 million at December 31, 2003. The decrease was primarily due to an increase
in liability for the fair value of derivatives of $9.0 million which was
partially offset by an increase in accounts receivable of $2.9 million, an
increase in deferred tax assets of $2.7 million and a decrease in accrued
expenses of $2.4 million.
29
CAPITAL EXPENDITURES
The table below sets forth the Company's' capital and exploration
expenditures for the three years ending December 31, 2003.
YEAR ENDED DECEMBER 31,
------------------------------------------------
FORECAST ACTUAL
--------- -----------------------------------
2004 2003 2002 2001
--------- --------- --------- ---------
(IN MILLIONS)
Drilling and completion $ 25 $ 25 $ 16 $ 23
Production enhancements and field improvements 4 3 2 4
Leasehold acreage 3 1 6 6
Other capital expenditures 1 2 4 4
--------- --------- --------- ---------
Subtotal capital expenditures $ 33 $ 31 $ 28 $ 37
Exploration costs 8 8 12 7
Exploratory dry hole costs 3 9 4 1
Acquisitions -- 5 3 2
--------- --------- --------- ---------
Total $ 44 $ 53 $ 47 $ 47
========= ========= ========= =========
During 2003, the Company invested $33.9 million, including exploratory
dry hole expense, to drill 83 development wells and 15 exploratory wells. Of
these wells, all 83 development wells and five exploratory wells were completed
as producers in the target formation, for a completion rate of 100% and 33%,
respectively (an overall completion rate of 90%). In addition, $3.8 million was
invested in proved developed reserve acquisitions.
During 2003 the Company explored the TBR in six different areas and
drilled 12 gross wells of which six were completed as producers in the TBR. The
Company has abandoned certain areas where it has been unsuccessful and as a
result recorded impairment expense for acreage in those areas. The Company plans
to continue to explore certain TBR areas with a focus on those areas where
commercial production has been established by the Company or others.
The Company currently expects to spend approximately $36 million during
2004 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
facility and, to a lesser extent, the sale of non-strategic assets. At December
31, 2003, the Company had approximately $38.9 million available under the
Revolver. At February 29, 2004, the Company had approximately $38.0 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.
FINANCING AND CREDIT FACILITIES
During 2003, amendments to the Company's $100 million revolving credit
facility extended the Revolver's final maturity date to June 30, 2006, from
December 31, 2005, increased the letter of credit sub-limit from $40 million to
$55 million, then increased the total commitment amount from $100 million to
$125 million solely to provide for a special letter of credit facility in the
amount of $25 million which combined with the existing letter of credit
sub-limit of $55 million would allow a total of $80 million in letters of
credit. This amendment also permitted the Company to enter into the transactions
to sell oil and gas leases in Ohio during 2003.
30
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 March 31, 2006; and a senior debt leverage ratio of 2.7 to 1
extended through March 31, 2006. The amendment extended the early termination
fee, equal to .125% of the Revolver, through June 30, 2005. There is no
termination fee after June 30, 2005. 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 September 2005.
The Revolver, as amended, also contains other financial covenants.
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, 2003, the Company's current ratio including the above
adjustments was 3.46 to 1. The Company had satisfied all financial covenants as
of December 31, 2003.
The Revolver bears interest at the prime rate plus two percentage
points, payable monthly. At December 31, 2003, the interest rate was 6.00%. At
December 31, 2003, the Company had $38.7 million of outstanding letters of
credit. At December 31, 2003, the outstanding balance under the credit agreement
was $47.4 million with $38.9 million of borrowing capacity available for general
corporate purposes. As of February 29, 2004, there was $47.3 million outstanding
under the Revolver, letters of credit commitments of $39.7 million and $38.0
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 financial hedges in place. The
weighted average price at December 31, 2003, was $4.87 per Mcfe. The present
value (using a 10% discount rate) of the Company's future net income at December
31, 2003, using the borrowing base price forecast was $426 million. The present
value under the borrowing base formula above, was approximately $253 million for
all proved reserves of the Company and $174 million for properties secured by a
mortgage.
The Company has $225 million of 9 7/8% Senior Subordinated Notes
outstanding as of December 31, 2003. The notes mature on 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
31
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, 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. There were no interest rate swaps in 2003 or 2002.
DERIVATIVE INSTRUMENTS
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 were
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, 2003, 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 recognized as increases to gas revenues during the same
periods in which the underlying forecasted transactions were recognized in net
income (loss).
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
------- ------- ------- ------- -------
(IN THOUSANDS)
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
32
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 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.
In April 2003, the Company entered into a collar for 6,000 Bbtu of its
natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a
floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.10 per Mmbtu
on this volume of gas. This aggregate structure has the effect of: 1) setting a
maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per
Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.10 and
$4.00 per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if
the price is $3.10 or less. All prices are based on monthly NYMEX settle.
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 February 29, 2004:
NATURAL GAS SWAPS NATURAL GAS COLLARS FIXED PRICE CONTRACTS
------------------------------------- ---------------------------------------- -------------------------
ESTIMATED NYMEX PRICE ESTIMATED ESTIMATED
NYMEX PRICE WELLHEAD PER MMBTU WELLHEAD PRICE ESTIMATED WELLHEAD
QUARTER ENDING BBTU PER MMBTU PRICE PER MCF BBTU FLOOR/CAP (1) PER MCF (1) MMCF PRICE PER MCF
- ------------------ ----- ----------- ------------- ----- ------------- -------------- --------- -------------
March 31, 2004 2,040 $ 3.84 $ 4.09 1,080 $ 4.00 - 5.80 $ 4.25 - 6.05 54 $ 4.10
June 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 37 4.06
September 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 - -
December 31, 2004 2,040 3.84 4.06 1,080 4.00 - 5.80 4.22 - 6.02 - -
----- ----------- ------------- ----- ------------- -------------- --------- -------------
8,160 $ 3.84 $ 4.03 4,320 $ 4.00 - 5.80 $ 4.19 - 5.99 91 $ 4.08
===== =========== ============= ===== ============= ============== ========= =============
March 31, 2005 1,500 $ 3.84 $ 4.09 1,500 $ 4.00 - 5.37 $ 4.25 - 5.62
June 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52
September 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52
December 31, 2005 1,500 3.73 3.95 1,500 4.00 - 5.37 4.22 - 5.59
----- ----------- ------------- ----- ------------- --------------
6,000 $ 3.76 $ 3.95 6,000 $ 4.00 - 5.37 $ 4.19 - 5.56
===== =========== ============= ===== ============= ==============
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.
The NYMEX price per Mmbtu floor/cap and the estimated wellhead price per Mcf for
the natural gas collars in 2005 assume the monthly NYMEX settles at $3.10 per
Mmbtu or higher. If the monthly NYMEX settles at less than $3.10 per Mmbtu then
the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90 and the estimated
wellhead price per Mcf will be the NYMEX settle plus $1.05 to $1.15.
33
INFLATION AND CHANGES IN PRICES
The average price of the Company's natural gas increased from $4.35 per
Mcf in 2001 to $4.95 per Mcf in 2002, then decreased to $4.93 in 2003. 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. During 2003, the
price paid for the Company's crude oil fluctuated between a low of $22.00 per
barrel and a high of $34.25 per barrel, with an average price of $28.06 per
barrel. 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.
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.
CONTRACTUAL OBLIGATIONS
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 Company has no off-balance sheet debt or other such unrecorded obligations,
and has not guaranteed the debt of any other party.
The following table summarizes the Company's contractual obligations at
December 31, 2003.
PAYMENTS DUE BY PERIOD
--------------------------------------------------------------------
CONTRACTUAL OBLIGATIONS AT LESS THAN 1 AFTER 5
DECEMBER 31, 2003 TOTAL YEAR 1 - 3 YEARS 4 - 5 YEARS YEARS
- ---------------------------------- --------- ----------- ------------ ----------- ---------
(IN THOUSANDS)
Long term debt $ 272,508 $ 5 $ 47,418 $ 225,015 $ 70
Capital lease obligations 208 100 71 37 -
Operating leases 10,784 3,465 5,180 2,139 -
--------- ----------- ------------ ----------- ---------
Total contractual cash obligations $ 283,500 $ 3,570 $ 52,669 $ 227,191 $ 70
========= =========== ============ =========== =========
In addition to the items above, the Company has an employment agreement
with its Chief Executive Officer, a retention plan, 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.
34
The following table summarizes the Company's commercial commitments at
December 31, 2003.
AMOUNT OF COMMITMENT EXPIRATION PER PERIOD
---------------------------------------------------
TOTAL
COMMERCIAL COMMITMENTS AT AMOUNTS LESS THAN 1 OVER 5
DECEMBER 31, 2003 COMMITTED YEAR 1 - 3 YEARS 4 - 5 YEARS YEARS
- ---------------------------- --------- ----------- ----------- ----------- ------
(IN THOUSANDS)
Standby Letters of Credit $ 38,650 $ 38,650 $ - $ - $ -
--------- ----------- ----------- ----------- ------
Total Commercial Commitments $ 38,650 $ 38,650 $ - $ - $ -
========= =========== =========== =========== ======
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.
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, 2003, 2002 and 2001. If market interest
rates for short-term borrowings increased 1%, the increase in the Company's
interest expense would be approximately $474,000. This sensitivity analysis is
based on the Company's financial structure at December 31, 2003.
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 $0.50 per Mcf, the Company's
35
gas sales revenues would decrease by $3.3 million, after considering the effects
of the hedging contracts in place at December 31, 2003. The Company had no
hedges or fixed price contracts on its oil production during 2003. If the price
of crude oil decreased $3.00 per Bbl, the Company's oil sales revenues would
decrease by $1.2 million. This sensitivity analysis is based on the Company's
2003 oil and gas sales volumes and assumes the NYMEX gas price would be within
the collars in 2004 listed in the table on page 33.
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.
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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
ITEM 9A. CONTROLS AND PROCEDURES
The Company's management, with the participation of the Company's Chief
Executive Officer and Chief Financial Officer, has evaluated the effectiveness
of the Company's disclosure controls and procedures as of December 31, 2003.
Based on that evaluation, the Company's Chief Executive Officer and Chief
Financial Officer concluded that the Company's disclosure controls and
procedures were effective as of December 31, 2003. There were no changes in the
Company's internal control over financial reporting during the fourth quarter of
2003 that materially affected, or are reasonably likely to affect, the Company's
internal control over financial reporting.
36
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Executive officers and directors of the Company as of March 5, 2004
were as follows:
Name Age Position
- --------------------- ---- ----------------------------------------------------------
John L. Schwager 55 President, Chief Executive Officer and Director
R. Mark Hackett 41 Senior Vice President Geoscience and Engineering
Richard R. Hoffman 53 Senior Vice President Operations
Robert W. Peshek 49 Senior Vice President and Chief Financial Officer
David M. Becker 42 Vice President and General Manager, Michigan Exploration
and Production District
Duane D. Clark 48 Vice President Legal Affairs/Gas Marketing
John G. Corp 44 Vice President and General Manager, Arrow Oilfield Service
Company
Patricia A. Harcourt 40 Vice President Administration
Frederick J. Stair 44 Vice President and Corporate Controller
Lawrence W. Kellner 45 Director
Robert S. Maust 66 Director
William S. Price, III 47 Director
Gareth Roberts 51 Director
Jeffrey C. Smith 42 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 in September
1999. He has over 35 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 President and Chief
Executive Officer from 1987 to 1997; Executive Vice President from May 1987 to
October 1987; and, Senior Vice President -
37
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 by Callon Petroleum Company in Natchez, Mississippi,
serving as the Vice President of Production from 1982 to 1984. 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, is a current a member and past director of the Ohio Oil and Gas
Association and is a current member of the Independent Petroleum Association of
America. He also was the cofounder of the Oil and Gas Political Action Committee
of West Virginia, serving as co-chairman for many years.
R. MARK HACKETT joined the Company as Senior Vice President of
Geoscience and Engineering in December of 2003. He has over 15 years of
extensive experience in drilling, engineering and producing operations in the
Appalachian Basin. Prior to joining the Company, Mr. Hackett held various
positions at Columbia Natural Resources, Inc. from 1997 to 2003, including Vice
President of Operations. From 1988 to 1997, he was employed by Alamco, Inc.,
where he last held the position of Vice President of Engineering. Mr. Hackett
graduated from West Virginia University in 1985 with a Bachelor of Science
degree in Petroleum and Natural Gas Engineering.
RICHARD R. HOFFMAN joined the Company as Senior Vice President of
Exploration and Production in March of 2001. As of December, 2003 Mr. Hoffman
became Senior Vice President of Operations. Mr. Hoffman has worked in the oil
and gas industry for 31 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 been elected by the Board of Directors as Senior
Vice President of the Company in December 2003. Previously, he served as Vice
President of Finance for the Company since 1997 and in 1999 was appointed Chief
Financial Officer. Prior to that, 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.
38
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 22 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.
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 25 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 25 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 and Director of Corporate Communications from 1994 to 2001.
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 16 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 Investor Relations
Institute and the Society for Human Resource Management.
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 23 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 the Petroleum Accountants Society of
Appalachia.
LAWRENCE W. KELLNER has been a director since 1997. He has been
President and Chief Operating Officer of Continental Airlines, Inc. since May
2003. He was President (May 2001-March 2003) and Executive Vice President and
Chief Financial Officer (November 1996-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., Express Jet Holdings, Inc., and Mariott International, Inc.
39
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 Director of the Division of Accounting for 15
years. 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 Del Monte Foods Company, Denbury
Resources, Inc., Gemplus International, S.A., Petco, 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.
AUDIT COMMITTEE
The primary purpose of the Audit Committee is to assist the Board of
Directors' oversight of (1) the integrity of the Company's financial statements,
(2) the Company's compliance with legal and regulatory requirements, (3) the
independent auditor's qualifications and independence, and (4) the performance
of the Company's internal audit function and independent auditors. The Audit
Committee is solely responsible for the appointment and compensation of the
Company's independent auditors. The
40
Audit Committee operates under a written charter adopted and approved by the
Board of Directors.
The Audit Committee is composed of three members of the Board of
Directors, Messrs. Kellner, Smith and Maust. Mr. Kellner is the Audit Committee
Chairman and has been designated by the Board of Directors as the "audit
committee financial expert" as described in Item 401(h) of Regulation S-K. In
addition, the Board of Directors has determined that Messrs. Kellner and Maust
are "independent audit committee members" as defined in the listing standards
for the New York Stock Exchange. Mr. Smith is not independent. Mr. Smith is
employed by TPG, a significant stockholder of the Company. TPG is deemed to be
an affiliate of the Company as a result of its controlling ownership of the
Company. However, the Board of Directors has determined that Mr. Smith's
membership on the committee is required by the best interests of the Company.
The Committee meets periodically with the Company's independent
auditors, Ernst & Young, LLP, representatives of the Company's internal audit
staff and management to review financial statements and the results of audit
activities.
REPORT OF THE AUDIT COMMITTEE
The Audit Committee oversees the Company's financial reporting process
on behalf of the Board of Directors. Management has the primary responsibility
for the financial statements and the reporting process including the systems of
internal controls. In fulfilling its oversight responsibilities, the Committee
reviewed the audited financial statements in the Annual Report with management
including a discussion of the quality, not just the acceptability, of the
accounting principles, the reasonableness of significant judgments, and the
clarity of disclosures in the financial statements. The Committee reviewed with
the independent auditors, who are responsible for expressing an opinion on the
conformity of those audited financial statements with generally accepted
accounting principles, their judgments as to the quality, not just the
acceptability, of the Company's accounting principles and such other matters as
are required to be discussed with the Committee by Statement on Auditing
Standards No. 61, as amended by Statement on Auditing Standards No. 90
(Communication With Audit Committees). In addition, the Committee has discussed
with the independent auditors the auditors' independence from management and the
Company, including the matters in the written disclosures required by
Independence Standards Board Standard No. 1, and considered the compatibility of
nonaudit services with the auditors' independence.
The Committee discussed with the Company's internal and independent
auditors the overall scope and plans for their respective audits. The Committee
meets with the internal and independent auditors, with and without management
present, to discuss the results of their examinations, their evaluations of the
Company's internal controls, and the overall quality of the Company's financial
reporting.
In reliance on the reviews and discussions referred to above, the
Committee recommended to the Board of Directors (and the Board has approved)
that the audited financial statements be included in the Annual Report on Form
10-K for the year ended December 31, 2003 for filing with the Securities and
Exchange Commission. The Committee and the Board have also recommended the
selection of the Company's independent auditors.
41
The Committee is governed by a charter. The committee held four
meetings during the year 2003.
Lawrence W. Kellner, Audit Committee Chairman
Robert S. Maust, Audit Committee Member
Jeffrey C. Smith, Audit Committee Member
March 12, 2004
The Company has adopted a Code of Ethics that applies to its Chief
Executive Officer, Chief Financial Officer, Chief Accounting Officer, Corporate
Controller and any person performing similar functions. The Company's Code of
Ethics is attached as Exhibit 14.1 to this Form 10-K.
42
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, 2003, 2002 and 2001 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 2003 $ 349,327 $ 540,000 (3) $ - - $ 10,000
President and 2002 325,000 573,750 - - 10,500
Chief Executive Officer 2001 317,692 292,277 - 100,000 8,500
Richard R. Hoffman (4) 2003 207,111 52,075 - - 5,941
Senior Vice President of 2002 198,000 39,600 - - 5,000
Exploration and Production 2001 145,385 83,769 - 82,500 43,742 (2)
Robert W. Peshek 2003 178,924 63,108 - - 10,000
Senior Vice President and 2002 168,308 58,910 - - 9,187
Chief Financial Officer 2001 164,915 90,703 - 17,500 8,500
David M. Becker 2003 159,130 30,741 - - 9,133
Vice President of 2002 154,707 23,200 - - 9,187
Michigan Operations 2001 139,644 41,893 - - 7,831
Duane D. Clark 2003 109,502 33,092 - - 7,202
Vice President of Legal 2002 103,310 36,160 - - 7,953
Affairs and Gas Marketing 2001 101,371 55,754 - - 6,328
Barry K. Lay (5) 2003 129,423 19,500 - - -
2002 - - - - -
2001 - - - - -
(1) Represents contributions of cash and common stock to the Company's 401(k)
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 $210,000 and an annual
retention bonus of $330,000 paid to Mr. Schwager on June 30, 2003. For
financial statement purposes the Company has accrued an additional
retention bonus of $165,000 for the period July 1, 2003 through December
31, 2003.
(4) Mr. Hoffman joined the Company in March 2001.
(5) Mr. Lay was not an Executive Officer as of December 31, 2003, as he moved
into an operations role.
43
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 97,915 $ 105,653 25,000 29,353 $ 45,625 $ 61,971
Richard R. Hoffman - - 41,250 41,250 75,281 75,281
Robert W. Peshek 15,000 31,950 62,500 8,750 223,050 15,969
David M. Becker - - 25,000 - 96,875 -
Duane D. Clark - - 30,000 - 116,650 -
Barry K. Lay - - 11,875 18,125 21,627 33,078
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.
44
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
worked as a part-time employee of the Company. During the transition period, Mr.
Schrider received the full base salary per year that he was receiving as of
December 31, 2001.
In February 2004, the Company entered into a retention plan effective
until December 31, 2006, for certain executive officers that provides for a
retention bonus payable six months after a change of control event (as defined
in the plan). The purpose of the plan is to promote a stable management team
during the period preceding and immediately following a potential change of
control event. Under the plan, Messrs. Becker, Clark, Hoffman and Peshek would
be eligible for a retention bonus (as defined in the plan) after a change of
control event.
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 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.
45
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
The following table sets forth certain information as of February 29,
2004 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:
PERCENTAGE OF
FIVE PERCENT SHAREHOLDERS NUMBER OF SHARES SHARES
------------------------- ---------------- ------
TPG Advisors II, Inc.
201 Main Street, Suite 2420
Fort Worth, Texas 76102 9,353,038 (1) 86.9%
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) 86.9%
John L. Schwager 309,075 (2) 2.9%
Lawrence W. Kellner -0- -0-
Gareth Roberts -0- -0-
Robert S. Maust -0- -0-
Jeffrey C. Smith -0- -0-
Richard R. Hoffman 46,406 (2) *
Robert W. Peshek 92,344 (2) *
David M. Becker 30,000 (2) *
Duane D. Clark 30,000 (2) *
All directors and executive
officers (14) as a group 9,916,802 92.2%
* 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 29,353 shares, Mr. Hoffman as to 46,406 shares, Mr.
Peshek as to 63,594 shares, Mr. Becker as to 25,000 shares and Mr. Clark
as to 30,000 shares.
46
EQUITY COMPENSATION PLAN INFORMATION:
Weighted- Number of securities
Number of average remaining available
securities to be exercise price for future issuance
issued upon of under equity
exercise of outstanding compensation plans
outstanding options, (excluding securities
options, warrants warrants and reflected in column
Plan category and rights rights (a))
- ------------- ----------------- ------------- ---------------------
(a) (b) (c)
Equity compensation plans
approved by security holders - $ - -
Equity compensation plans not
approved by security holders 616,321 $ 1.29 733,394
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, 2003, options to purchase 616,321 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 calendar quarter-end 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 years prior to 2002. TPG
was paid a transaction fee pursuant to this agreement for the $16.2 million sale
of the properties in New York and Pennsylvania in December 2002. The fee
amounted to $238,000 which was accrued in 2002 and paid in 2003. TPG waived the
fee on all other acquisition and sale transactions in 2003 and 2002.
47
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Ernst & Young served as the Company's independent auditor for the year
ended December 31, 2003. Aggregate fees for professional services provided to
the Company by Ernst & Young for the years ended December 31, 2003 and 2002 were
as follows:
DECEMBER 31,
------------------------
2003 2002
---- ----
Audit fees $ 187,000 $ 192,245
Audit-related fees - 4,500
Tax fees 41,120 54,700
Other fees 1,600 1,500
--------- ---------
$ 229,720 $ 252,945
========= =========
Fees for audit services include fees associated with the annual audit
and the reviews of the Company's quarterly reports on Form 10-Q. Audit-related
fees principally included accounting consultation. Tax fees included tax
compliance and tax planning. Other fees include research materials.
AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES
The Audit Committee has adopted a policy that requires advance approval
of all audit, audit-related, and other services performed by the independent
auditor or other public accounting firms. The policy provides for pre-approval
by the Audit Committee of specifically defined audit and non-audit services.
Unless the specific service has been previously pre-approved with respect to
that year, the Audit Committee must approve the permitted service before the
independent auditor or public accounting firm is engaged to perform it. The
Audit Committee has delegated to the Chairman of the Audit Committee authority
to approve permitted services up to $75,000 per year provided that the Chairman
reports any decisions to the Committee at its next scheduled meeting. All
services of $75,000 or more are required to be approved by a majority of the
Committee members.
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
48
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).
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.
49
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.-- incorporated by reference to Exhibit 10.1 (e) to the
Company's Annual Report on Form 10-K for the year ended December 31,
2002.
10.1(f) Amendment to the Credit Agreement dated as of March 31, 2003 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 March 31,
2003.
10.1(g) Amendment to the Credit Agreement dated as of May 30, 2003 by and among
the Company, Ableco Finance LLC and Foothill Capital
Corporation.--incorporated by reference to Exhibit 10.1 to the
Company's Current Report on Form 8-K dated May 30, 2003.
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.
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.--incorporated by reference to Exhibit 10.7 (a) to the Company's
Annual Report on Form 10-K for the year ended December 31, 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.--incorporated by reference to Exhibit 10.7 (b) to the Company's
Annual Report on Form 10-K for the year ended December 31, 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.--incorporated by reference to Exhibit 10.8
(a) to the Company's Annual Report on Form 10-K for the year ended
December 31, 2002.
50
10.8(b) Amendment - 2 to the Belden & Blake Corporation 1999 Severance Pay Plan
dated as of September 12, 2002.--incorporated by reference to Exhibit
10.8 (b) to the Company's Annual Report on Form 10-K for the year ended
December 31, 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.
14.1* Code of Ethics for Senior Financial Officers.
21* Subsidiaries of the Registrant
23* Consent of Independent Auditors
31.1* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2* 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 December 4, 2003, the Company filed a Current Report on Form 8-K
dated December 1, 2003, reporting under Item 9 the Company's operational outlook
for 2003.
(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.
51
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 16, 2004 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 16, 2004
- ---------------------------------- and Chief Executive Officer --------------
John L. Schwager (Principal Executive Officer) Date
/s/ Robert W. Peshek Senior Vice President and March 16, 2004
- ---------------------------------- Chief Financial Officer --------------
Robert W. Peshek (Principal Financial and Date
Accounting Officer)
/s/ Lawrence W. Kellner Director March 16, 2004
- ---------------------------------- --------------
Lawrence W. Kellner Date
/s/ Robert S. Maust Director March 16, 2004
- ---------------------------------- --------------
Robert S. Maust Date
/s/ William S. Price, III Director March 15, 2004
- ---------------------------------- --------------
William S. Price, III Date
/s/ Gareth Roberts Director March 16, 2004
- ---------------------------------- --------------
Gareth Roberts Date
/s/ Jeffrey C. Smith Director March 17, 2004
- ---------------------------------- --------------
Jeffrey C. Smith Date
52
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, 2003 and 2002.................................... F-3
Consolidated Statements of Operations:
Years ended December 31, 2003, 2002 and 2001.................................................. F-4
Consolidated Statements of Shareholders' Equity (Deficit):
Years ended December 31, 2003, 2002 and 2001.................................................. F-5
Consolidated Statements of Cash Flows:
Years ended December 31, 2003, 2002 and 2001.................................................. 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, 2003 and 2002, 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, 2003. 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, 2003 and 2002 and the consolidated results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2003, in conformity with accounting principles generally accepted
in the United States.
As discussed in Note 1 to the consolidated financial statements, in 2003 the
Company adopted the provisions of Statement of Financial Accounting Standards
No. 143, "Asset Retirement Obligations."
ERNST & YOUNG LLP
Cleveland, Ohio
March 8, 2004
F-2
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31,
----------------------------
2003 2002
---- ----
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 1,440 $ 1,722
Accounts receivable, net 17,597 14,652
Inventories 786 848
Deferred income taxes 6,853 4,200
Other current assets 2,415 1,341
Fair value of derivatives 319 -
Assets of discontinued operations - 1,066
---------- ---------
TOTAL CURRENT ASSETS 29,410 23,829
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 464,262 438,240
Gas gathering systems 15,264 14,482
Land, buildings, machinery and equipment 23,107 22,748
---------- ---------
502,633 475,470
Less accumulated depreciation, depletion and amortization 256,050 243,596
---------- ---------
PROPERTY AND EQUIPMENT, NET 246,583 231,874
FAIR VALUE OF DERIVATIVES 755 3
OTHER ASSETS 7,163 8,139
---------- ---------
$ 283,911 $ 263,845
========== =========
LIABILITIES AND SHAREHOLDERS' DEFICIT
CURRENT LIABILITIES
Accounts payable $ 5,496 $ 5,661
Accrued expenses 15,393 17,767
Current portion of long-term liabilities 729 315
Fair value of derivatives 14,765 5,486
Liabilities of discontinued operations - 335
---------- ---------
TOTAL CURRENT LIABILITIES 36,383 29,564
LONG-TERM LIABILITIES
Bank and other long-term debt 47,503 26,868
Senior subordinated notes 225,000 225,000
Other 4,629 91
---------- ---------
277,132 251,959
FAIR VALUE OF DERIVATIVES 9,723 4,371
DEFERRED INCOME TAXES 18,013 22,596
SHAREHOLDERS' DEFICIT
Common stock without par value; $.10 stated value per share; authorized
58,000,000 shares; issued 10,610,450 and 10,490,440 shares
(which includes 214,593 and 194,890 treasury shares, respectively) 1,040 1,030
Paid in capital 107,633 107,118
Deficit (150,656) (148,332)
Accumulated other comprehensive loss (15,357) (4,461)
---------- ---------
TOTAL SHAREHOLDERS' DEFICIT (57,340) (44,645)
---------- ---------
$ 283,911 $ 263,845
========== =========
See accompanying notes.
F-3
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31,
-----------------------------------------
2003 2002 2001
---- ---- ----
REVENUES
Oil and gas sales $ 85,023 $ 90,462 $ 89,491
Gas gathering, marketing, and oilfield service 23,741 21,624 27,348
Other 338 1,834 2,044
-------- --------- -----------
109,102 113,920 118,883
EXPENSES
Production expense 19,937 19,936 20,952
Production taxes 2,455 1,789 2,298
Gas gathering, marketing, and oilfield service 21,378 17,996 22,760
Exploration expense 16,882 16,256 8,335
General and administrative expense 4,559 4,557 4,395
Franchise, property and other taxes 282 91 238
Depreciation, depletion and amortization 19,343 22,379 25,979
Impairment of oil and gas properties 5,774 - 1,398
Accretion expense 365 - -
Derivative fair value gain (319) - -
Severance and other nonrecurring expense - 953 1,954
-------- --------- -----------
90,656 83,957 88,309
-------- --------- -----------
OPERATING INCOME 18,446 29,963 30,574
OTHER EXPENSE
Loss on sale of businesses - 154 -
Interest expense 25,537 23,608 25,753
-------- --------- -----------
25,537 23,762 25,753
-------- --------- -----------
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (7,091) 6,201 4,821
(Benefit) provision for income taxes (2,481) 2,456 (955)
-------- --------- -----------
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (4,610) 3,745 5,776
(Loss) income from discontinued operations, net of tax (111) (1,280) 691
-------- --------- -----------
(LOSS) INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE (4,721) 2,465 6,467
Cumulative effect of change in accounting principle, net of tax 2,397 - -
-------- --------- -----------
NET (LOSS) INCOME $ (2,324) $ 2,465 $ 6,467
======== ========= ===========
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, 2001 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)
Comprehensive income:
Net loss (2,324) (2,324)
Other comprehensive income, net of tax:
Change in derivative fair value (17,439) (17,439)
Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales 6,543 6,543
-----------
Total comprehensive income (13,220)
-----------
Stock options exercised 120 12 108 120
Stock-based compensation 326 326
Repurchase of stock options (48) (48)
Tax benefit of repurchase of stock options
and stock options exercised 170 170
Treasury stock (20) (2) (41) (43)
------ -------- --------- ---------- ------------- -----------
DECEMBER 31, 2003 10,396 $ 1,040 $ 107,633 $ (150,656) $ (15,357) $ (57,340)
====== ======== ========= ========== ============= ===========
See accompanying notes.
F-5
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
IN THOUSANDS
YEAR ENDED DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
(Loss) income from continuing operations $ (2,213) $ 3,745 $ 5,776
Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:
Depreciation, depletion and amortization 19,343 22,379 25,979
Impairment of oil and gas properties and other assets 5,774 - 1,398
Accretion 365 - -
Loss on sale of businesses - 154 -
Loss on disposal of property and equipment 1 ,452 198 92
Net monetization of derivatives - 22,185 -
Amortization of derivatives and other noncash hedging activities (3,456) (19,241) -
Exploration expense 16,882 16,256 8,335
Deferred income taxes (2,481) 2,468 (1,069)
Cumulative effect of change in accounting principle (2,397) - -
Stock-based compensation 326 82 275
Change in operating assets and liabilities, net of
effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets (3,969) (1,420) 8,521
Inventories 62 453 571
Accounts payable and accrued expenses (2,539) 3,646 (5,008)
--------- --------- ---------
NET CASH PROVIDED BY CONTINUING OPERATIONS 27,149 50,905 44,870
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of businesses, net of cash acquired (4,841) (2,773) (489)
Disposition of businesses, net of cash 100 12,390 897
Proceeds from property and equipment disposals 2,997 1,927 768
Exploration expense (16,882) (16,256) (8,335)
Additions to property and equipment (29,540) (26,215) (35,730)
Increase in other assets (120) (1,541) (81)
--------- --------- ---------
NET CASH USED IN INVESTING ACTIVITIES (48,286) (32,468) (42,970)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving line of credit and term loan 195,859 151,158 181,645
Repayment of long-term debt and other obligations (175,573) (184,003) (184,071)
Debt issue costs (250) (152) (210)
Proceeds from stock options exercised 120 5 6
Repurchase of stock options 122 (29) (772)
Purchase of treasury stock (43) (398) (289)
--------- --------- ---------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 20,235 (33,419) (3,691)
--------- --------- ---------
NET DECREASE IN CASH AND CASH EQUIVALENTS
FROM CONTINUING OPERATIONS (902) (14,982) (1,791)
NET INCREASE IN CASH AND CASH EQUIVALENTS
FROM DISCONTINUED OPERATIONS 620 14,769 1,928
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,722 1,935 1,798
--------- --------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,440 $ 1,722 $ 1,935
========= ========= =========
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 2003.
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 2003 and 2001 were $5.2 million and
$179,000, 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 2003 and 2001, the Company
recorded $572,000 and $1.2 million, respectively, 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.
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 $6.6 million at December 31, 2003, include
$3.9 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, 2003, the amortization of deferred debt issuance costs in
the next five years is as follows: $1.2 million in each of the next two years
(2004,
F-8
and 2005), $1.0 million in 2006 and $403,000 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 asset and 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 the years ended December 31, 2003, 2002 and
2001, respectively: risk-free interest rates of 3.7%, 4.1% and 5.0%; 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, 2003,
2002 and 2001 were not material.
The changes in share value and the vesting of shares are reported as
adjustments to compensation expense. The change in share value in 2003, 2002 and
2001 resulted in an increase in compensation expense of $325,000, $82,000 and
$275,000, respectively.
F-9
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). 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. 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.
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.
(2) NEW ACCOUNTING PRONOUNCEMENTS
On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset
Retirement Obligations." SFAS 143 amends SFAS 19, "Financial Accounting and
Reporting by Oil and Gas Producing Companies" to require the Company to
recognize a liability for the fair value of its asset retirement obligations
associated with its tangible, long-lived assets. The majority of the asset
retirement obligations recorded by the Company relate to the plugging and
abandonment (excluding salvage value) of its oil and gas properties. At January
1, 2003, there were no assets legally restricted for purposes of settling asset
retirement obligations. The adoption of SFAS 143 resulted in a January 1, 2003
cumulative effect adjustment to record a $4.0 million increase in long-term
asset retirement obligation liabilities, a $621,000 increase in current asset
retirement obligation liabilities, a $3.2 million increase in the carrying value
of oil and gas assets, a $5.2 million decrease in accumulated depreciation,
depletion and amortization and a $1.4 million increase in deferred income tax
liabilities. The net effect of adoption was to record a gain of $2.4 million,
net of tax, as a cumulative effect of a change in accounting principle in the
Company's consolidated statement of operations in the first quarter of 2003.
F-10
Subsequent to the adoption of SFAS 143, there has been no significant
current period activity with respect to additional retirement obligations,
settled obligations, accretion expense and revisions of estimated cash flows.
The unaudited pro forma income from continuing operations for the years ended
December 31, 2002 and 2001 was $4.3 million and $6.9 million, respectively, and
has been prepared to give effect to the adoption of SFAS 143 as if it had been
adopted on January 1, 2002 and January 1, 2001. Assuming retroactive application
of the change in accounting principle as of January 1, 2002, liabilities would
have increased approximately $6 million.
A reconciliation of the Company's liability for plugging and
abandonment costs for the year ended December 31, 2003 is as follows (in
thousands):
Asset retirement obligation, December 31, 2002 $ -
Cumulative effect adjustment 4,603
Liabilities incurred 345
Liabilities settled (491)
Accretion expense 365
Revisions in estimated cash flows 294
-------------
Asset retirement obligation, December 31, 2003 $ 5,116
=============
On January 1, 2003, the Company adopted 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, "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. The adoption
of SFAS 145 did not have any 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 was effective for the
Company for disposal activities initiated after December 31, 2002. The adoption
of this standard did not have any effect on the Company's financial position,
results of operations or cash flows.
In October 2002, the FASB issued SFAS 147, "Acquisitions of Certain
Financial Institutions - an amendment of FASB Statements No. 72 and 144 and FASB
Interpretation No. 9." SFAS 147 was effective for the Company for acquisition
activities initiated on or after October 1, 2002. The adoption of this standard
did not have any 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
F-11
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. The adoption of FIN 45 did not have any effect on
the Company's financial statement disclosures, financial position, results of
operations or cash flows.
In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure." SFAS 148 amends FASB 123, "Accounting
for Stock-Based Compensation," to provide alternative methods of transition for
a voluntary change to the fair value based method of accounting for stock-based
employee compensation. In addition, SFAS 148 amends the disclosure requirements
of SFAS 123 to require prominent disclosures in both annual and interim
financial statements about the method of accounting for stock-based employee
compensation and the effect of the method used on the reported results. The
Company measures expense associated with stock-based compensation using the
intrinsic value method prescribed by 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 provisions
of SFAS 148 were effective for financial statements for fiscal years ending
after December 15, 2002. The adoption of SFAS 148 did not have a material effect
on the Company's financial position, results of operations or cash flows.
In January 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities - An Interpretation of Accounting Research Bulletin (ARB) 51."
FIN 46 is an interpretation of ARB 51, "Consolidated Financial Statements," and
addresses consolidation by business enterprises of variable interest entities
(VIEs). The primary objective of FIN 46 is to provide guidance on the
identification of, and financial reporting for, entities over which control is
achieved through means other than voting rights; such entities are known as
VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has
a variable interest that will absorb a majority of the entity's expected losses
if they occur, receive a majority of the entity's expected residual returns if
they occur, or both. An enterprise shall consider the rights and obligations
conveyed by its variable interests in making this determination. This guidance
applies immediately to VIEs created after January 31, 2003, and to VIEs in which
an enterprise obtains an interest after that date. It applies in the first
fiscal year or interim period beginning after December 15, 2003, to VIEs in
which an enterprise holds a variable interest that it acquired before February
1, 2003. The adoption of FIN 46 did not have any effect on the Company's
financial statement disclosures, financial position, results of operations or
cash flows.
In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." This Statement is intended to
result in more consistent reporting of contracts as either freestanding
derivative instruments subject to Statement 133 in its entirety, or as hybrid
instruments with debt host contracts and embedded derivative features. SFAS 149
is effective for the Company's financial statements for the interim period
beginning July 1, 2003. The adoption of SFAS 149 did not have a material effect
on the Company's financial position, results of operations or cash flows.
In May 2003, the FASB issued SFAS 150, "Accounting for Financial
Instruments with Characteristics of both Liabilities and Equity." This Statement
establishes standards for classifying and measuring as liabilities certain
financial instruments that embody obligations of the issuer and have
characteristics of both liabilities and equity. Instruments that are indexed to
and potentially settled in an issuer's own shares that are not within the scope
of Statement 150 remain subject to existing guidance. SFAS 150 is effective for
the Company's financial statements for the interim period beginning July 1,
F-12
2003. The adoption of SFAS 150 did not have a material effect on the Company's
financial position, results of operations or cash flows.
The Company has been made aware of an issue regarding the application
of provisions of SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and
Other Intangible Assets," to oil and gas companies. The issue is whether SFAS
142 requires registrants to reclassify costs associated with mineral rights,
including both proved and unproved leasehold acquisition costs, as intangible
assets in the balance sheet, apart from other capitalized oil and gas property
costs. Historically, the Company and other oil and gas companies have included
the cost of oil and gas leasehold interests as part of oil and gas properties
and provided the disclosures required by SFAS 69, "Disclosures about Oil and Gas
Producing Activities."
If it is ultimately determined that SFAS 142 requires the Company to
reclassify costs associated with mineral rights from property and equipment to
intangible assets, the Company currently believes that its financial condition,
results of operations or cash flows would not be affected, since such intangible
assets would continue to be depleted and assessed for impairment in accordance
with existing successful efforts accounting rules and impairment standards. The
Company had undeveloped leasehold costs of $7.7 million and $14.2 million at
December 31, 2003 and 2002, respectively. The amount of potential balance sheet
reclassifications for developed leasehold costs has not been determined.
In December 2003, the FASB issued SFAS 132 (revised 2003), "Employers'
Disclosures about Pensions and Other Postretirement Benefits," an amendment of
SFAS 87, 88, and 106, and a revision of SFAS 132. This statement revises
employers' disclosures about pension plans and other postretirement benefit
plans. It does not change the measurement or recognition of those plans required
by FASB Statements No. 87, Employers' Accounting for Pensions, No. 88,
Employers' Accounting for Settlements and Curtailments of Defined Benefit
Pension Plans and for Termination Benefits, and No. 106, Employers' Accounting
for Postretirement Benefits Other Than Pensions. This Statement retains the
disclosure requirements contained in FASB Statement No. 132, Employers'
Disclosures about Pensions and Other Postretirement Benefits, which it replaces.
It requires additional disclosures to those in the original Statement 132 about
the assets, obligations, cash flows, and net periodic benefit cost of defined
benefit pension plans and other defined benefit postretirement plans. The
required information should be provided separately for pension plans and for
other postretirement benefit plans. This Statement is effective for financial
statements with fiscal years ending after December 15, 2003. The adoption of
this standard did not have a material effect on the Company's financial
position, results of operations or cash flows.
(3) ACQUISITIONS
In February 2003, the Company purchased reserves in certain wells the
Company operates in Michigan for $3.8 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 (billion cubic feet) of proved developed
producing gas reserves.
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.
F-13
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
As a result of the Company's decision to shift focus away from
exploration and development activities in the Knox formation in Ohio, the
Company sold substantially all of its undeveloped Knox acreage in Ohio for
approximately $2.8 million in September 2003. The sale resulted in a loss of
approximately $150,000.
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 (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) in 2002. 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 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 and 2001 were $1.5 million and
$1.7 million, respectively.
F-14
Revenues and (loss) income from discontinued operations are as follows:
YEAR ENDED DECEMBER 31,
----------------------------------------
2003 2002 2001
---------- ----------- ---------
Revenue from discontinued operations $ 10 $ 9,245 $ 12,646
(Loss) income from operations of discontinued business $ (107) $ 960 $ 1,155
(Benefit) provision for income taxes (40) 408 464
---------- ----------- ---------
(67) 552 691
Loss on sale of discontinued business (69) (3,188)
Income tax benefit (25) (1,356)
---------- -----------
(44) (1,832)
---------- ----------- ---------
(Loss) income from discontinued operations, net of tax $ (111) $ (1,280) $ 691
========== =========== =========
Assets and liabilities of the discontinued operations are as follows:
DECEMBER 31,
--------------------------
2003 2002
---------- -----------
Assets
Current assets $ - $ -
Net property and equipment - 1,066
---------- -----------
Total assets $ - $ 1,066
========== ===========
Liabilities
Current liabilities $ - $ 335
Noncurrent deferred tax liability - -
---------- -----------
Total liabilities $ - $ 335
---------- -----------
Net assets of discontinued operations $ - $ 731
========== ===========
A transaction fee of $238,000 was paid in 2003 to TPG in connection
with the sale. The fee was paid 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 were 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.
F-15
(5) DERIVATIVES AND HEDGING
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, 2003, the Company's derivative
contracts consisted of natural gas swaps, collars and options. Qualifying NYMEX
based derivative contracts were designated as cash flow hedges. The changes in
fair value of non-qualifying derivative contracts 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.
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, 2003. During 2003, a net loss on contract settlements of
$10.3 million ($6.5 million after tax) was reclassified from accumulated other
comprehensive income to earnings and the fair value of open hedges decreased by
$27.1 million ($17.4 million after tax). At December 31, 2003, the estimated net
losses in accumulated other comprehensive income that are expected to be
reclassified into earnings within the next 12 months are approximately $14.6
million. The Company has partially hedged its exposure to the variability in
future cash flows through December 2005.
In March 2003, the Company entered into a collar for 4,320 Bbtu
(billion British thermal units) of its natural gas production in 2004 with a
ceiling price of $5.80 per Mmbtu (million British thermal units) 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 which was designated as a non-qualifying cash flow hedge
under SFAS 133. 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.
In April 2003, the Company entered into a collar for 6,000 Bbtu of its
natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a
floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.10 per Mmbtu
on this volume of gas which was designated as a non-qualifying cash flow hedge
under SFAS 133. This aggregate structure has the effect of: 1) setting a maximum
price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per Mmbtu;
3) locking in a price of $4.00 per Mmbtu if prices are between $3.10 and $4.00
per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if the
price is $3.10 or less. All prices are based on monthly NYMEX settle.
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
F-16
Mmbtu on this volume of gas which was designated as a non-qualifying cash flow
hedge under SFAS 133.
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, 2003, 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 recognized as increases to gas sales revenues during
the periods in which the underlying forecasted transactions were recognized in
net income (loss).
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER TOTAL
------- -------------- ------- ------- -------
(IN THOUSANDS)
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.
The following tables reflect the natural gas volumes and the weighted
average prices under financial hedges (including settled hedges) at December 31,
2003:
NATURAL GAS SWAPS NATURAL GAS COLLARS FIXED PRICE CONTRACTS
----------------------------------- --------------------------------------- -------------------------
ESTIMATED NYMEX PRICE ESTIMATED ESTIMATED
NYMEX PRICE WELLHEAD PER MMBTU WELLHEAD PRICE ESTIMATED WELLHEAD
QUARTER ENDING BBTU PER MMBTU PRICE PER MCF BBTU FLOOR/CAP PER MCF MMCF PRICE PER MCF
- ------------------ ----- ----------- ------------- ----- ------------- -------------- --------- -------------
March 31, 2004 2,040 $ 3.84 $ 4.09 1,080 $ 4.00 - 5.80 $ 4.25 - 6.05 54 $ 4.10
June 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 37 4.06
September 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 -- --
December 31, 2004 2,040 3.84 4.06 1,080 4.00 - 5.80 4.22 - 6.02 -- --
----- ----------- ------------- ----- ------------- -------------- --------- -------------
8,160 $ 3.84 $ 4.03 4,320 $ 4.00 - 5.80 $ 4.19 - 5.99 91 $ 4.08
===== =========== ============= ===== ============= ============== ========= =============
March 31, 2005 1,500 $ 3.84 $ 4.09 1,500 $ 4.00 - 5.37 $ 4.25 - 5.62
June 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52
September 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52
December 31, 2005 1,500 3.73 3.95 1,500 4.00 - 5.37 4.22 - 5.59
----- ----------- ------------- ----- ------------- --------------
6,000 $ 3.76 $ 3.95 6,000 $ 4.00 - 5.37 $ 4.19 - 5.56
===== =========== ============= ===== ============= ==============
MCF - THOUSAND CUBIC FEET MMBTU - MILLION BRITISH THERMAL UNITS
BBTU - BILLION BRITISH THERMAL UNITS
F-17
(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 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.
F-18
(7) DETAILS OF BALANCE SHEETS
DECEMBER 31,
-----------------------
2003 2002
--------- ---------
(IN THOUSANDS)
ACCOUNTS RECEIVABLE
Accounts receivable $ 7,393 $ 7,610
Allowance for doubtful accounts (1,547) (1,588)
Oil and gas production receivable 11,672 8,417
Current portion of notes receivable 79 213
--------- ---------
$ 17,597 $ 14,652
========= =========
INVENTORIES
Oil $ 459 $ 665
Natural gas 33 18
Material, pipe and supplies 294 165
--------- ---------
$ 786 $ 848
========= =========
PROPERTY AND EQUIPMENT, GROSS
OIL AND GAS PROPERTIES
Producing properties $ 446,967 $ 406,336
Non-producing properties 8,283 14,291
Other 9,012 17,613
--------- ---------
$ 464,262 $ 438,240
========= =========
LAND, BUILDINGS, MACHINERY AND EQUIPMENT
Land, buildings and improvements $ 5,443 $ 5,168
Machinery and equipment 17,664 17,580
--------- ---------
$ 23,107 $ 22,748
========= =========
ACCRUED EXPENSES
Accrued expenses $ 4,185 $ 5,870
Accrued drilling and completion costs 2,583 3,480
Accrued income taxes 73 85
Ad valorem and other taxes 1,517 1,619
Compensation and related benefits 2,541 2,222
Undistributed production revenue 4,494 4,491
--------- ---------
$ 15,393 $ 17,767
========= =========
F-19
(8) LONG-TERM DEBT
Long-term debt consists of the following (in thousands):
DECEMBER 31,
--------------------
2003 2002
-------- --------
Revolving credit facility $ 47,406 $ 26,764
Senior subordinated notes 225,000 225,000
Other 102 286
-------- --------
272,508 252,050
Less current portion 5 182
-------- --------
Long-term debt $272,503 $251,868
======== ========
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, 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.
The Company has a $100 million revolving credit facility (the
"Revolver") from Ableco Finance LLC and Wells Fargo Foothill, Inc. (formerly
known as Foothill Capital Corporation) which matures on June 30, 2006. The
Revolver bears interest at the prime rate plus two percentage points, payable
monthly. At December 31, 2003, the interest rate was 6.00%. At December 31,
2003, the Company had $38.7 million of outstanding letters of credit. At
December 31, 2003, the outstanding balance under the credit agreement was $47.4
million with $38.9 million of borrowing capacity available for general corporate
purposes.
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.
F-20
The Revolver was amended on March 31, 2003 to increase the letter of
credit sub-limit to $55 million. On May 30, 2003, the Company amended its $100
million revolving credit facility. The amendment increased the total commitment
amount from $100 million to $125 million solely to provide for a special letter
of credit facility in the amount of $25 million which combined with the existing
letter of credit sub-limit of $55 million would allow a total of $80 million in
letters of credit. The amendment also extended the Revolver's final maturity
date to June 30, 2006, from December 31, 2005 and permitted the Company to enter
into transactions to sell certain oil and gas leases in Ohio in 2003.
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 March 31, 2006; and a senior debt leverage ratio of 2.7 to 1
extended through March 31, 2006. The amendment extended the early termination
fee, equal to .125% of the Revolver, through June 30, 2005. There is no
termination fee after June 30, 2005. 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 September 2005.
The Revolver, as amended, also contains other financial covenants.
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, 2003, the Company's current ratio including the above
adjustments was 3.46 to 1. The Company had satisfied all financial covenants as
of December 31, 2003.
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, 2003, was $4.87 per Mcfe. The present
value (using a 10% discount rate) of the Company's future net income at December
31, 2003, using the borrowing base price forecast was $426 million. The present
value under the borrowing base formula above, applying the stated percents of
each group of reserves, was approximately $253 million for all proved reserves
of the Company and $174 million for properties secured by a mortgage.
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. There were no interest rate swaps in 2003, 2002 or 2001.
At December 31, 2003, the aggregate long-term debt maturing in the next
five years is as follows: $5,000 (2004); $6,000 (2005); $47,412,000 (2006);
$225,007,000 (2007) and $78,000 (2008 and thereafter).
F-21
(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 $3.3 million, $2.8 million and
$2.9 million for the years ended December 31, 2003, 2002 and 2001, respectively.
The Company also leases certain computer equipment accounted for as
capital leases. Property and equipment includes $506,000 and $747,000 of
computer equipment under capital leases at December 31, 2003 and 2002,
respectively. Accumulated depreciation for such equipment includes approximately
$298,000 and $523,000 at December 31, 2003 and 2002, respectively.
Future minimum commitments under leasing arrangements at December 31,
2003 were as follows:
OPERATING CAPITAL
YEAR ENDING DECEMBER 31, 2003 LEASES LEASES
- -------------------------------------------- ---------- --------
(IN THOUSANDS)
2004 $ 3,465 $ 104
2005 2,696 39
2006 2,484 36
2007 1,956 36
2008 and thereafter 183 2
---------- --------
Total minimum rental payments $ 10,784 217
==========
Less amount representing interest 9
--------
Present value of net minimum rental payments 208
Less current portion 100
--------
Long-term capitalized lease obligations $ 108
========
(10) STOCK OPTION PLANS
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, 2003, options to purchase 616,321 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 calendar quarter-end 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.
F-22
Stock option activity consisted of the following:
WEIGHTED
AVERAGE
NUMBER OF EXERCISE
SHARES PRICE
-------- --------
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
Granted 77,500 2.14
Forfeitures (781) 0.30
Exercised or put (144,854) 0.83
--------
BALANCE AT DECEMBER 31, 2003 616,321 1.29
========
OPTIONS EXERCISABLE AT DECEMBER 31, 2003 387,594 $ 0.81
========
The weighted average fair value of options granted during 2003, 2002
and 2001 was $0.49, $0.52 and $0.79, respectively. The exercise price for the
options outstanding as of December 31, 2003 ranged from $0.01 to $2.14 per
share. At December 31, 2003, the weighted average remaining contractual life of
the outstanding options is 6.6 years.
F-23
(11) TAXES
The provision (benefit) for income taxes on income from continuing
operations before cumulative effect of change in accounting principle includes
the following (in thousands):
YEAR ENDED DECEMBER 31,
------------------------------------
2003 2002 2001
-------- -------- --------
CURRENT
Federal $ -- $ (190) $ 114
State -- 76 --
-------- -------- --------
-- (114) 114
DEFERRED
Federal (2,580) 2,140 (1,004)
State 99 430 (65)
-------- -------- --------
(2,481) 2,570 (1,069)
-------- -------- --------
TOTAL $ (2,481) $ 2,456 $ (955)
======== ======== ========
The effective tax rate for income from continuing operations before
cumulative effect of change in accounting principle differs from the U.S.
federal statutory tax rate as follows:
YEAR ENDED DECEMBER 31,
-------------------------
2003 2002 2001
---- ---- -----
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 0.9 5.3 --
Settlement of IRS exam and other tax issues -- -- (40.9)
Change in valuation allowance -- -- (14.5)
Permanent differences (0.9) -- --
Other, net -- (0.7) 0.6
---- ---- -----
Effective income tax rate for the period 35.0% 39.6% (19.8)%
==== ==== =====
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 believes it can fully utilize.
F-24
Significant components of deferred income tax liabilities and assets
are as follows (in thousands):
DECEMBER 31, DECEMBER 31,
2003 2002
------------ ------------
Deferred income tax liabilities:
Property and equipment, net $ 45,302 $ 46,698
------------ ------------
Total deferred income tax liabilities 45,302 46,698
Deferred income tax assets:
Accrued expenses 1,224 2,666
Fair value of derivatives 8,254 2,449
Net operating loss carryforwards 28,605 26,012
Tax credit carryforwards 913 913
Other, net 534 514
Valuation allowance (5,388) (4,252)
------------ ------------
Total deferred income tax assets 34,142 28,302
------------ ------------
Net deferred income tax liability $ 11,160 $ 18,396
============ ============
Current liability $ -- $ --
Long-term liability 18,013 22,596
Current asset (6,853) (4,200)
------------ ------------
Net deferred income tax liability $ 11,160 $ 18,396
============ ============
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, 2003 and 2002 relates
principally to certain state net operating loss carryforwards which management
estimates will expire before they can be utilized.
At December 31, 2003, the Company had approximately $60 million of net
operating loss carryforwards available for federal income tax reporting
purposes. These net operating loss carryforwards, if unused, will expire in 2012
through 2023. 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 $1.3 million, $1.1 million and $1.4 million
for the years ended December 31, 2003, 2002 and 2001, respectively, for
contributions to the profit sharing plan and discretionary bonuses. All amounts
were paid in cash.
As of December 31, 2003, 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 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 $433,000, $557,000 and
$550,000 for the years ended December 31, 2003, 2002 and 2001, 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'
F-25
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, 2003 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 has appealed. The Company
believes there will be no material amount payable above and beyond the amount
accrued as of December 31, 2003 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, pursuant to
the arbitrator's ruling, the Company repurchased 31,168 shares of common stock
for $337,000 plus interest from the date of the employment agreement. The
Company paid $521,000 in 2003 based on the ruling. The Company recorded the
stock purchase as treasury stock in 2002 and expensed the interest in the
appropriate periods.
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 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, 2003, 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.
F-26
(14) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
YEAR ENDED DECEMBER 31,
--------------------------------------------
(IN THOUSANDS) 2003 2002 2001
- --------------------------------------------------------------- ------------ ------------ ------------
CASH PAID DURING THE PERIOD FOR:
Interest $ 25,427 $ 23,750 $ 27,737
Income taxes, net of refunds 172 (221) 359
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Acquisition of assets in exchange for long-term liabilities 136 281 443
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX 2,397 -- --
(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 $222.7 million at
December 31, 2003 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, 2003, the Company's derivative contracts consisted of natural gas swaps,
collars and options. Qualifying NYMEX based derivative contracts are designated
as cash flow hedges. The Company incurred a pre-tax loss on its hedging
activities of $10.3 million in 2003 and pre-tax gains of $21.6 million in 2002
and $4.5 million in 2001. At December 31, 2003, the fair value of futures
contracts covering 2004 and 2005 natural gas production represented an
unrealized loss of $23.4 million.
F-27
(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) 2003 2002 2001
- -------------------------------------------------- ---------- ---------- ----------
Acquisition costs:
Proved properties $ 3,923 $ 1,724 $ 2,399
Unproved properties 2,135 5,364 5,574
Developmental costs 25,361 16,222 23,409
Exploratory costs 16,882 16,282 8,346
Estimated asset retirement obligations incurred (1) 639 -- --
- ------
(1) amounts are shown net of revisions of estimated cash flows
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, 2003, 2002 and 2001 have
been prepared by Wright & Company, Inc., independent petroleum engineers.
F-28
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, 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
Extensions and discoveries -- 6,164 6,164
Purchase of reserves in place -- 8,988 8,988
Sale of reserves in place (1) (41) (48)
Revisions of previous estimates 16 (12,976) (12,880)
Production (413) (14,912) (17,389)
--------- --------- --------
DECEMBER 31, 2003 6,176 322,741 359,797
========= ========= ========
PROVED DEVELOPED RESERVES
December 31, 2001 4,788 218,148 246,876
========= ========= ========
December 31, 2002 4,103 206,719 231,337
========= ========= ========
December 31, 2003 3,809 212,494 235,348
========= ========= ========
(1) THOUSAND BARRELS (2) MILLION CUBIC FEET (3) MILLION CUBIC FEET EQUIVALENT
F-29
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,
-----------------------------------------------
2003 2002 2001
------------- ------------- -------------
(IN THOUSANDS)
Estimated future cash inflows (outflows)
Revenues from the sale of oil and gas $ 2,180,423 $ 1,855,414 $ 1,075,151
Production costs (471,563) (423,643) (396,654)
Development costs (168,874) (167,295) (130,723)
------------- ------------- -------------
Future net cash flows before income taxes 1,539,986 1,264,476 547,774
Future income taxes (511,160) (412,193) (133,992)
------------- ------------- -------------
Future net cash flows 1,028,826 852,283 413,782
10% timing discount (612,929) (519,464) (231,920)
------------- ------------- -------------
Standardized measure of discounted
future net cash flows $ 415,897 $ 332,819 $ 181,862
============= ============= =============
At December 31, 2003, 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, 2003 were
$6.19 per Mcf of natural gas and $29.78 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-30
The principal sources of changes in the standardized measure of future
net cash flows are as follows:
YEAR ENDED DECEMBER 31,
-----------------------------------------------
2003 2002 2001
------------- ------------- -------------
(IN THOUSANDS)
Beginning of year $ 332,819 $ 181,862 $ 820,764
Sale of oil and gas, net of production costs (63,722) (73,351) (72,132)
Extensions and discoveries, less related estimated
future development and production costs 24,144 7,153 8,721
Purchase of reserves in place less
estimated future production costs 10,193 26,385 7,924
Sale of reserves in place less
estimated future production costs (60) (16,727) (3,226)
Revisions of previous quantity estimates (23,296) 53,423 (63,294)
Net changes in prices and production costs 153,492 239,368 (1,026,055)
Change in income taxes (34,288) (103,641) 371,059
Accretion of 10% timing discount 47,959 22,499 123,495
Changes in production rates (timing) and other (31,344) (4,152) 14,606
------------- ------------- -------------
End of year $ 415,897 $ 332,819 $ 181,862
============= ============= =============
(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
During 2003 the Company had three customers that each accounted for 10%
or more of consolidated revenues with sales of $19.8 million, $11.5 million and
$10.8 million, respectively. One customer accounted for more than 10% of
consolidated revenues during each of the years ended December 31, 2002 and 2001,
sales to which amounted to $12.9 million and $21.0 million, respectively.
F-31
(18) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The results of operations for the four quarters of 2003 and 2002 are
shown below (in thousands).
FIRST SECOND THIRD FOURTH
------------ ------------ ------------ ------------
2003
- ----
Operating revenues $ 27,531 $ 27,262 $ 26,409 $ 27,562
Gross profit 8,198 9,556 5,451 5,282
Income (loss) from continuing operations before
cumulative effect of change in accounting principle 395 1,699 (1,641) (5,063)
(Loss) income from discontinued operations, net of tax (25) (86) -- --
Net income (loss) 2,768 1,612 (1,641) (5,063)
2002
- ----
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)
During 2003, the Company recorded exploratory dry hole expense of
approximately $8.5 million, of which $4.1 million and $4.2 million were incurred
in the third and fourth quarters, respectively. In the fourth quarter of 2003,
the Company recorded impairments of $5.2 million related to unproved properties
and $572,000 related to producing properties.
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 for the first three quarters in 2002 were
restated in the fourth quarter of 2002 to reflect the discontinued operations.
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
On March 9, 2004, the Company announced that it had engaged Randall &
Dewey Partners, L.P., an oil and gas strategic advisory and consulting firm
based in Houston, Texas, to assist the Company in evaluating its strategic
alternatives.
F-32