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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, 1998
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)
<TABLE>
<S> <C>
OHIO 34-1686642
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number)
</TABLE>
5200 STONEHAM ROAD
NORTH CANTON, OHIO 44720
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (330) 499-1660
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, WITHOUT PAR VALUE
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. X
---
The aggregate market value of the voting stock held by non-affiliates
of the registrant as of February 28, 1999 was $2,400,654.
The number of shares outstanding of registrant's common stock,
without par value, as of February 28, 1999 was 10,229,189.
DOCUMENTS INCORPORATED BY REFERENCE
None.
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PART I
Item 1. BUSINESS
Belden & Blake Corporation ("successor company") and its predecessor
were acquired by TPG Partners II L.P. ("TPG") and certain other investors on
June 27, 1997 ("the Acquisition"). The operations of the successor company
represent 100% of the businesses of the predecessor. Therefore certain
operational data for the twelve months ended December 31, 1997 have been
presented on a combined basis because such information is comparable to the
historical data of the predecessor and the current data of the successor.
The historical financial statements of the successor company and its
predecessor are presented separately as described in Note 1 to the consolidated
financial statements included under Item 8.
GENERAL
Belden & Blake Corporation, an Ohio corporation (the "Company"), is an
integrated energy company engaged in marketing natural gas directly to end users
in a six state area; producing oil and natural gas; acquiring and enhancing the
economic performance of producing oil and natural gas properties; exploring for
and developing natural gas and oil reserves; and gathering natural gas for
delivery to intrastate and interstate gas transmission pipelines. Until 1995,
the Company conducted business exclusively in the Appalachian Basin where it has
operated since 1942 through several predecessor entities. It is a fast-growing
independent natural gas marketer and one of the largest gas producers operating
in the Appalachian, Michigan, and Illinois Basins (the Company operates in Ohio,
Pennsylvania, New York, West Virginia, Michigan and Kentucky). In early 1995,
the Company commenced gas marketing, production and drilling operations in the
Michigan Basin through the acquisition of Ward Lake Drilling, Inc. ("Ward
Lake"), an independent energy company, which markets gas and owns and operates
oil and gas properties in Michigan's lower peninsula. In September 1996, the
Company entered the Illinois Basin by acquiring a natural gas gathering system
and the Shrewsbury Gas Field in western Kentucky.
At December 31, 1998, the Company marketed approximately 149 Mmcf
(million cubic feet) of natural gas per day to more than 360 commercial and
industrial customers. Approximately 58% of such marketed gas represented the
Company's own production, with the balance purchased from third parties. The
Company owned and operated approximately 2,600 miles of gas gathering systems
with access to the commercial and industrial gas markets of the northeastern
United States at December 31, 1998.
At December 31, 1998, the Company's net production was approximately 86
Mmcf of gas and 2,194 Bbls (barrels) of oil per day. At that date the Company
owned interests in 8,069 gross (7,101 net) productive gas and oil wells in Ohio,
West Virginia, Pennsylvania, New York, Michigan and Kentucky with proved
reserves totaling 315.3 Bcf (billion cubic feet) of gas and 4.2 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
$256.6 million at December 31, 1998. At December 31, 1998, the Company operated
approximately 7,850 wells, including wells operated for third parties. At that
date, the Company held leases on 1,410,888 gross (1,206,211 net) acres,
including 770,534 gross (646,646 net) undeveloped acres.
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The Company's production and reserves have grown principally through
the acquisition of producing properties and related gas gathering facilities and
exploration and development of its own acreage. From its formation in March 1992
through December 31, 1998, the Company acquired for $158.3 million producing
properties with 235.2 Bcfe (billion cubic feet of natural gas equivalent) of
proved developed reserves at an average cost of $0.67 per Mcfe (thousand cubic
feet of natural gas equivalent) and spent $21.6 million to acquire and develop
additional gas gathering facilities. During the period from 1992 through 1998,
the Company drilled 1,057 gross (808.7 net) wells at an aggregate cost of
approximately $151.2 million for the net wells. This drilling added 159.3 Bcfe
to the Company's proved reserves. During 1998, the Company drilled 249 gross
(199.2 net) wells at a direct cost of approximately $36.0 million for the net
wells. The 1998 drilling activity added 35.3 Bcfe of proved developed reserves
at an average cost of $1.02 per Mcfe. Proved developed reserves added through
drilling in 1998 represent approximately 102% of 1998 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
In July 1998, the Company began development of a major expansion of
its gas marketing capability with the objective of substantially increasing the
number of commercial and industrial customers served, the volumes of gas sold
and the Company's future net operating margins from gas sales. The expansion
includes the selection and installation of systems and technology to enhance
the efficiency of the gas marketing operation. During 1998, $731,000 was
expensed and $924,000 was capitalized relating to this expansion project. See
Note 6 to the consolidated financial statements.
In conjunction with the expansion of its gas marketing capability, the
Company formed Belden Energy Services Company ("BESCO"), a wholly-owned
subsidiary, in September 1998. BESCO was formed to market natural gas to retail
and wholesale customers in the midwestern and northeastern United States. BESCO
may elect to expand its retail and wholesale marketing activities to electricity
as the marketing of this commodity is deregulated in its area of operations.
Through the use of internally developed and licensed marketing programs, BESCO
increased the number of commercial and industrial customers it serves by 44%
from October 1998 through February 1999. BESCO's objective is to significantly
increase the number of commercial and industrial customers served in 1999.
RECENT DEVELOPMENTS
SUBSEQUENT EVENTS
On January 15, 1999, the Company was notified that the several lenders
under its revolving credit agreement had reduced the Company's borrowing base
from $170 million to $126 million. The Company's outstanding borrowings on that
date exceeded the redetermined borrowing base by $28 million. Under the terms of
the existing credit agreement, the Company is required to prepay 50% of such
excess by April 15, 1999 and the balance by July 14, 1999, unless the lenders
and the Company otherwise agree.
The Company and its lenders have agreed to a required prepayment of $14
million on March 22, 1999 and an additional $14 million on May 10, 1999. In
conjunction with this agreement, the Company
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has been granted a waiver by the lenders of certain terms of its working
capital ratio covenant. As a result, as of December 31, 1998, the Company has
met all covenants under the credit agreement.
On March 22, 1999, the Company made a $14 million payment to reduce the
outstanding amount under the credit agreement to $140 million. The funds for the
payment were provided by internally generated cash flow and a term loan provided
by Chase Manhattan Bank. This term loan provided borrowings of $9 million and is
due on September 22, 1999. Interest is payable monthly at LIBOR plus 1.5%. The
Company is in the process of renegotiating its revolving credit facility with
its lenders and expects to have a new facility in place prior to May 10, 1999,
when the second payment of $14 million is due. Should the Company not
be successful in renegotiating an acceptable facility, the Company
expects to be able to meet its 1999 debt service requirements through internally
generated cash flow, the sale of non-strategic assets and/or the use of
instruments in financial futures markets.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The Company's operations are conducted in the United States and are
managed along three reportable segments which include: (1) exploration and
production, (2) gas marketing and gathering and (3) oilfield sales and service.
The information with respect to the Company's operating segments is shown in
Note 18 to the consolidated financial statements.
DESCRIPTION OF BUSINESS
OVERVIEW
The Company, founded in 1942, is actively engaged in natural gas
marketing and gathering, and the production, acquisition, exploration and
development of natural gas and oil in the Appalachian, Michigan and Illinois
Basins. The Company operates principally in the Appalachian and Michigan Basins
(a region which includes Ohio, Pennsylvania, New York, West Virginia and
Michigan) where it is a fast-growing natural gas marketer and one of the largest
gas producers. It commenced operations in Kentucky in September 1996, which
marked its entrance into the Illinois Basin.
The Company has been selling natural gas directly to commercial and
industrial customers since 1974. The major industrial centers of Akron, Buffalo,
Canton, Cleveland, Detroit, Grand Rapids and Pittsburgh are all located in close
proximity to the Company's production operations and along with other urban
areas in the midwestern and northeastern United States provide a large potential
market for direct natural gas sales. The states of Ohio, Pennsylvania, New York
and Michigan account for approximately 19% of the natural gas consumed in the
United States. These states produce in aggregate less than 16% of the gas they
consume on an annual basis.
The Company focuses its gas marketing efforts on commercial customers
and small to mid-sized industrial customers that require more service and have
the potential to generate higher margins per Mcf than large industrial users.
The Company currently markets natural gas to approximately 500 commercial and
industrial customers and various local gas distribution companies in its region
of operations. It currently markets approximately 149 million cubic feet of gas
per day, of which more than 85% consists of its own production and production it
controls through operations.
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The Company's capability to market gas directly to end users is
enhanced by its ability to deliver gas through its approximately 2,600 miles of
gathering systems. The Company's gathering systems can interconnect with local
gas distribution companies and the many interstate gas pipelines that traverse
its operating region, thus allowing the Company to deliver gas throughout its
primary marketing area.
The proximity of the Appalachian and Michigan Basins to large
commercial and industrial natural gas markets has generally resulted in premium
wellhead gas prices that since 1986 have ranged from $0.31 to $1.30 per Mcf
(thousand cubic feet) above national wellhead prices. The Company's average
wellhead gas price in 1998 was $0.57 per Mcf above the estimated average
national wellhead price. The Company believes that its growing natural gas
production base in these premium markets enhances its gas marketing ability and
the net margins it is able to secure for its marketed gas.
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 gas is currently
produced primarily from shallow, highly developed blanket formations at depths
of 1,000 to 5,500 feet. Drilling success rates of the Company and others
drilling in these formations historically have exceeded 90% with production
generally lasting longer than 20 years.
The combination of long-lived production and high drilling success
rates at these shallower depths has resulted in a highly fragmented, extensively
drilled, low technology operating environment in the Appalachian Basin. As of
December 31, 1998, there were over 10,000 independent operators of record and
approximately 175,000 producing oil and gas wells in Ohio, West Virginia,
Pennsylvania and New York. There has been only limited testing or development of
the formations below the existing shallow production in the Appalachian Basin.
Fewer than 2,500 wells have been drilled to a depth greater than 7,500 feet, and
fewer than 100 wells have been drilled to a depth greater than 12,500 feet in
the entire Appalachian Basin. As a result, the Company believes 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.
In January 1995, the Company purchased Ward Lake Drilling, Inc., a
privately-held energy company headquartered in Gaylord, Michigan, and commenced
operations in the Michigan Basin. At the time of purchase, Ward Lake operated
approximately 500 Antrim Shale gas wells producing approximately 41 Mmcf per day
in Michigan's lower peninsula. The Company's primary objective in acquiring Ward
Lake was to allow the Company to pursue gas marketing and production
opportunities in the Michigan Basin with an established operating company that
provided the critical mass to operate efficiently. Ward Lake currently operates
approximately 700 wells producing approximately 57 Mmcf per day in Michigan.
In September 1996, the Company commenced operations in the Illinois
Basin by acquiring a 100% working interest in 98 natural gas wells and an
extensive gas gathering system in the Shrewsbury Gas Field located in western
Kentucky.
The Company's rationale for entering the Michigan and Illinois Basins
was based on their geologic and operational similarities to the Appalachian
Basin, their geographic proximity to the Company's operations in the Appalachian
Basin and their proximity to premium gas markets. Geologically, the Michigan and
Illinois Basins resemble the Appalachian Basin with shallow blanket formations
and deeper formations with greater reserve potential. Operationally, economies
of scale and
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cost containment are essential to operating profitability. The operating
environment in each of these basins 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 1,700 feet) blanket Antrim Shale formation which has not
been extensively developed. Success rates for companies drilling to this
formation have exceeded 90%, with production often lasting as long as 20 years.
The Michigan Basin also contains deeper formations with greater reserve
potential. The Company has also established production from certain of these
deeper formations through its drilling operations. The Michigan Basin has
approximately 200 operators of record, most of which are private companies, and
more than 9,500 producing wells. Because the production rate from Antrim Shale
wells is relatively low, cost containment is a crucial aspect of operations. In
contrast to the shallow, highly developed blanket formations in the Appalachian
Basin, the operating environment in the Antrim Shale is more capital intensive
because of the low natural reservoir pressures and the high initial water
content of the formation.
The Company's production in the Illinois Basin is primarily from the
New Albany Shale formation, which is a stratigraphic equivalent of the Antrim
Shale formation. The New Albany Shale has likewise not been widely developed.
The New Albany Shale has similar operating characteristics to shale formations
in the adjacent Appalachian and Michigan Basins from which the Company is
currently producing.
BUSINESS STRATEGY
The Company seeks to increase shareholder value by increasing cash flow
through the integration of its proactive gas marketing operations with a growing
base of primarily natural gas production and a balanced program of strategic
acquisitions and exploration and development drilling. Specifically, the Company
believes that being able to control the flow of natural gas from the wellhead to
the burner tip end user will maximize the economic rewards to the Company and
its shareholders. The key elements of the Company's strategy are as follows:
o EXPAND NATURAL GAS MARKETING AND GATHERING. The Company is located and
operates in an area of major United States gas markets. The recent
deregulation of natural gas markets by various states and the beginning of
"open access" to these markets to independent gas marketers creates the
opportunity for the Company to greatly expand its commercial and
industrial customer base. There are an estimated 510,000 commercial and
industrial natural gas customers in Ohio, Pennsylvania and Michigan alone.
While the Company has been marketing directly to large industrial end
users since 1974, much of the commercial and smaller industrial market has
been under the monopoly control of local gas distribution companies
("LDCs") franchised and regulated by the various states.
The Company's extensive gas gathering systems enhance its ability to market
its own production and purchased gas throughout its marketing region. The
gathering systems' ability to connect to local distribution systems and
interstate pipelines further enables the Company to deliver gas to premium
gas markets. The Company's gas gathering systems are also integral to the
Company's low cost structure and high revenues per unit of gas production.
It is the Company's intention to expand its gas gathering systems, to
include the addition of storage capacity, in order to further enhance its
gas marketing capability and to improve the rate of return on the Company's
drilling and development activities.
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o PURSUE CONSOLIDATION OPPORTUNITIES. There is a continuing trend toward
consolidation in the energy industry in general. The basins in which the
Company operates are highly fragmented. The Company believes this provides
the basis for significant acquisition opportunities as capital constrained
operators, the majority of which are privately held, seek liquidity or
operating capital. The Company intends to capitalize on its geographic
knowledge, technical expertise, low cost structure and decentralized
organization to pursue additional strategic acquisitions in its area of
operations.
The Company's acquisition strategy focuses on acquiring producing
properties that: (i) are properties in which the Company already owns an
interest and operates or that are strategically located in relation to its
existing operations, (ii) have the potential for increased revenues
resulting from the Company's gas marketing capabilities, (iii) can be
enhanced through operating cost reductions, advanced production
technologies, mechanical improvements, recompleting or reworking wells
and/or the use of enhanced and secondary recovery techniques, (iv) provide
development and exploratory drilling opportunities or opportunities to
improve the Company's acreage position, or (v) are of sufficient size to
allow the Company to operate efficiently in new areas.
o MAINTAIN A BALANCED DRILLING PROGRAM. It is the Company's intention to
expand production and reserves through a balanced program of developmental
and exploratory drilling. 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 has identified
numerous development and exploratory drilling locations in the deeper
formations of these Basins. Originally, the Company's drilling budget for
1999 was approximately $28 million to drill 251 wells. However, due to
continued depressed pricing in oil and gas markets and capital constraints
as a result of the decrease in the Company's borrowing base, the drilling
budget has been reduced to a minimal amount for 1999.
o UTILIZE ADVANCED TECHNOLOGY. The combination of long-lived production and
high drilling success rates at the shallow depths has resulted in a highly
fragmented, extensively drilled, low technology operating environment in
the Appalachian Basin. The Company has been applying more advanced
technology, including 3-D seismic, horizontal drilling, advanced
fracturing techniques and enhanced oil recovery methods. The Company is
implementing these techniques to improve drilling success rates, reserves
discovered per well, production rates, reserve recovery rates and total
economics in its operating area.
GAS MARKETING AND GATHERING
Gas Marketing. The Company began marketing natural gas directly to
industrial end users in 1974 under the provisions of Ohio's Self Help Act. In
1993, the Federal Energy Regulatory Commission ("FERC") issued Order 636 which,
along with other provisions, required pipelines to separate ("unbundle") their
gas sales from their transportation services. Order 636 was designed to place
all natural gas sellers on an equal footing. Subsequent to the issuance of Order
636, several states, including Michigan, Ohio and Pennsylvania, have passed
legislation to remove the monopoly distribution authority previously granted to
local gas distribution companies. Such legislation was intended to encourage
competition among gas marketers and reduce the cost of gas to industrial,
commercial and residential consumers.
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In 1997 and 1998, various LDCs in Michigan, Ohio and Pennsylvania began
pilot programs of open access to allow their small industrial, commercial and
residential customers to purchase natural gas from other marketers, with the LDC
continuing to provide physical delivery of the commodity. By the end of 1999 the
two largest LDCs in Ohio and the largest LDC in western Pennsylvania are
expected to afford full open access to all of their customers. The two largest
LDCs in Michigan are similarly expected to be in a full open access status by
the end of 2000. These LDCs in aggregate have an estimated 510,000 commercial
and industrial customers.
In July 1998, the Company began development of a major expansion of its
gas marketing capability with the objective of capturing a significant share of
these newly-opened natural gas markets. The Company intends to substantially
increase the number of commercial and industrial customers served, the volumes
of gas sold and the Company's future net operating margins from gas sales. The
expansion includes the selection and installation of systems and technology to
enhance the efficiency of the gas marketing operation.
In conjunction with the expansion of its gas marketing capability, the
Company formed BESCO, a wholly-owned subsidiary, in September 1998. BESCO was
formed to market natural gas to wholesale and retail customers in the midwestern
and northeastern United States independent of the Company's own natural gas
production. Through BESCO the Company may elect to expand its wholesale and
retail marketing activities in its market area to electricity as the marketing
of this commodity is deregulated. Through the use of internally developed and
licensed marketing programs, BESCO increased the number of commercial and
industrial customers it serves by 44% from October 1998 through February 1999.
BESCO's objective is to significantly increase the number of commercial and
industrial customers served in 1999.
The major industrial centers of Akron, Buffalo, Canton, Cleveland,
Columbus, Detroit, Grand Rapids, Pittsburgh and Toledo are all located in
BESCO's market area and provide a very large potential market for retail and
wholesale natural gas sales. At present, BESCO markets gas directly to
approximately 500 customers in a six-state area. BESCO intends to focus its gas
marketing efforts on commercial and small to mid-sized industrial customers that
require more service and have the potential to generate higher margins per Mcf
than large industrial users.
The Company sells the gas it produces to its commercial and industrial
customers, local distribution companies and on the spot market. In addition to
its own production, the Company buys gas from other producers and third parties
and resells it. At December 31, 1998, the Company marketed approximately 149
Mmcf of gas per day of which approximately 58% consisted of its own production.
Gas sold by the Company to end users and local distribution companies is usually
sold pursuant to contracts which extend for periods of one or more years at
either fixed prices or market sensitive prices. Gas sold on the spot market is
generally priced on the basis of a regional index. Since late 1995, the Company
has attempted to maintain a balance between gas volumes sold under fixed price
contracts and volumes sold under market sensitive contracts. At December 31,
1998, approximately 46% of the gas marketed by the Company was at fixed prices
and 54% was at market sensitive prices. This contract strategy is intended to
reduce price volatility and place a partial floor under the price received while
still maintaining the potential for gains from upward movement in market
sensitive prices.
The Company has a policy which governs its ability to trade in the
financial futures markets. The Company may, from time to time, partially hedge
its physical gas sales prices by selling futures contracts on the New York
Mercantile Exchange ("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 or options. At December 31, 1998, the
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Company had 620 open futures contracts covering 1999, at an average price of
$2.44 per Mcf. To offset these hedges, the Company has contracted for the
physical delivery of gas into various pipelines in its producing areas at a
NYMEX price plus a fixed basis. Additionally, the Company has entered into a
"swaption" whereby the counterparty has the option to extend a current swap of
20 contracts per month through calendar year 2000 by giving notice on September
30, 1999.
The following table shows the type of buyer for gas marketed by the
Company at December 31, 1998:
<TABLE>
<CAPTION>
Marketed Gas
--------------------
Mmcf per Percent
Purchaser Day of Total
- ---------------------------- -------- --------
<S> <C> <C>
End users 59.0 40%
Local distribution companies 11.7 8%
Spot markets 78.3 52%
----- -----
Total 149.0 100%
===== =====
</TABLE>
Gas Gathering. The Company operates approximately 2,600 miles of
natural gas gathering lines in Ohio, West Virginia, Pennsylvania, New York,
Michigan and Kentucky which are tied directly to various interstate natural gas
transmission systems. The interconnections with these interstate pipelines
afford the Company potential marketing access to numerous major gas markets. The
Company's gas gathering revenues totaled $6.9 million in 1998. Direct costs
associated with gas gathering in 1998 totaled approximately $1.7 million.
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ACQUISITION OF PRODUCING PROPERTIES
The Company employs a disciplined approach to acquisition analysis that
requires input and approval from all key areas of the Company. These areas
include field operations, exploration and production, finance, legal, gas
marketing, land management and environmental compliance. Although the Company
often reviews in excess of 50 acquisition opportunities per year, this
disciplined approach can result in uneven annual spending on acquisitions. The
following table sets forth information pertaining to acquisitions completed
during the period 1992 through 1998.
<TABLE>
<CAPTION>
Proved Developed Reserves (2)
---------------------------------
Number of Purchase Oil Gas Combined
Period Transactions Price (1) (Mbbl) (Mmcf) (Mmcfe)
------ ------------ --------- ------ ------ -------
(in thousands)
<S> <C> <C> <C> <C> <C>
1992 5 $ 23,733 466 41,477 44,273
1993 8 3,883 119 4,121 4,835
1994 11 20,274 223 26,877 28,215
1995 6 77,388 1,850 97,314 108,414
1996 3 4,103 205 6,000 7,230
1997 10 21,295 101 32,800 33,406
1998 3 7,640 34 8,574 8,778
-- -------- ----- ------- -------
Total 46 $158,316 2,998 217,163 235,151
== ======== ===== ======= =======
</TABLE>
- ------------
(1) Represents the portion of the purchase price allocated to proved developed
reserves.
(2) Mbbl - thousand barrels Mmcf - million cubic feet
Mmcfe - million cubic feet equivalent
During 1998, the Company acquired for approximately $7.6 million,
working interests in 898 oil and gas wells in Ohio, Michigan, West Virginia and
New York. Estimated proved developed reserves associated with the wells totaled
8.6 Bcf of natural gas and 34,000 Bbls of oil, net to the Company's interest.
OIL AND GAS OPERATIONS AND PRODUCTION
Operations. The Company serves as the operator of substantially all of
the wells in which it holds working interests. The Company seeks to maximize the
value of its properties through operating efficiencies associated with economies
of scale and through operating cost reductions, advanced production technology,
mechanical improvements and/or the use of enhanced and secondary recovery
techniques.
Through its production field offices in Ohio, West Virginia,
Pennsylvania, New York, Michigan and Kentucky, the Company continuously reviews
its properties, especially recently acquired properties, to determine what
action can be taken to reduce operating costs and/or improve production. The
Company has successfully reduced field level costs through improved operating
practices such as computerized production scheduling and the use of hand-held
computers to gather field data. On
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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 and
redesigning downhole equipment.
The Company may also implement enhanced and secondary recovery
techniques. Secondary recovery methods typically involve all methods of oil
extraction in which extrinsic energy sources are applied to extract additional
reserves. The principal secondary recovery technique used by the Company is
waterflooding, which the Company has used successfully in Ohio and Pennsylvania.
Production. The following table sets forth certain information regarding oil
and gas production from the Company's properties:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------------------------
1994 1995 1996 1997 1998
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Production:
Oil (Mbbl) 496 556 719 753 768
Gas (Bcf) 9.6 17.0 25.4 27.2 30.1
Average sales price:
Oil (per Bbl) $ 15.98 $ 16.78 $ 20.24 $ 18.10 $ 12.61
Gas (per Mcf) 2.58 2.21 2.56 2.65 2.57
Average production costs per Mcfe
(including production taxes) 0.73 0.68 0.72 0.78 0.77
Total oil and gas revenues
(in thousands) 32,574 46,853 79,491 85,756 87,055
Total production expenses
(in thousands) 9,184 13,816 21,266 24,668 26,725
</TABLE>
EXPLORATION AND DEVELOPMENT
The Company's exploration and development activities include
development drilling in the highly developed or blanket formations and
development and exploratory drilling in the less developed formations of the
Appalachian, Michigan and Illinois 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 1998, the Company drilled 192 gross (169.5 net) wells to highly
developed or shallow blanket formations in its six state operating area at a
direct cost of approximately $28.4 million for the net wells. The Company also
drilled 57 gross (29.7 net) wells to less developed and deeper formations in
1998 at a direct cost of approximately $7.6 million for the net wells. The
result of this drilling activity is shown in the table on page 15.
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.
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Highly Developed Formations. In general, the highly developed or
blanket formations found in the Appalachian, Michigan and Illinois Basins are
widespread in extent and hydrocarbon accumulations are not dependent upon local
stratigraphic or structural trapping. Drilling success rates exceed 90%. The
principal risk of such wells is uneconomic recoverable reserves.
The highly developed formations in the Appalachian Basin are relatively
tight reservoirs that produce 20% to 30% of their recoverable reserves in the
first year and 40% to 50% of their total recoverable reserves in the first three
years, with steady declines in subsequent years. Average well lives range from
15 years to 25 years or more.
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 at rates of 100 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.
Producing natural gas in the form of methane from coalbed formations is
becoming a more common practice, particularly in Pennsylvania. In 1998, the
Company completed its second project area near Connellsville, PA, with the
completion of 12 coalbed methane wells. This brings the Company's total wells
producing from this type of reservoir to 62. With over 60,000 acres under lease
in the coal seam fairway, the Company believes that substantial additional
opportunities exist for coalbed drilling.
In the Illinois Basin, the highly developed or shallow blanket
formations include the New Albany Shale formation as well as the Mississippian
Sandstones. Production characteristics of the New Albany Shale are very similar
to the Devonian Shale from which the Company produces in West Virginia.
11
<PAGE> 13
Certain typical characteristics of the highly developed or blanket
formations drilled by the Company in 1998 are described below:
<TABLE>
<CAPTION>
Range of Range of
Average Drilling Average Gross
Range of and Completion Reserves
Well Depths Costs per Well per Completed Well
----------- -------------- ------------------
(in feet) (in thousands) (in Mmcfe)
<S> <C> <C> <C>
Ohio 1,200-5,500 $ 65-140 80-150
West Virginia 1,300-6,000 100-220 150-500
Pennsylvania:
Coalbed Methane 900-1,800 75-100 180-250
Clarendon 1,100-2,000 35-45 30-50
Medina 5,000-6,200 150-200 180-300
New York 3,000-5,000 100-150 75-300
Michigan 1,000-1,200 200-250 400-600
Kentucky 1,200-1,800 90-120 125-250
</TABLE>
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 success 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 less developed formations in the Appalachian Basin include the Knox
sequence of sandstones and dolomites which includes the Rose Run, Beekmantown
and Trempealeau productive zones, at depths ranging from 2,500 feet to 8,000
feet. The geographical boundaries of the Knox sequence, which lies approximately
2,000 feet below the highly developed Clinton Sandstone, are generally well
defined in Ohio with less definition in New York and Pennsylvania. Nevertheless,
the Knox group has been only lightly explored, with fewer than 2,000 wells
drilled to this sequence of formations during the past 10 years.
12
<PAGE> 14
The Company began testing the Knox sequence in 1989 by selecting
certain wells that were targeted to be completed to the Clinton formation and
drilling them an additional 2,000 feet to 2,500 feet to test the Knox
formations. In 1991, the Company began using seismic analysis and other
geophysical tools to select drilling locations specifically targeting the Knox
formations. Since 1991, the Company has added substantially to its technical
staff to enhance its ability to develop drilling prospects in the Knox and other
less developed formations in the Appalachian Basin and the deeper formations in
the Michigan Basin. The following table shows the Company's drilling results in
the Knox sequence:
<TABLE>
<CAPTION>
Drilling Results in the Knox Formations
----------------------------------------------------------------------
Average Gross
Wells Drilled Wells Completed (1) Reserves per
------------------- -------------------- Completed Well
Period Gross Net Gross Net (Mmcfe)
- --------- ----- ---- ----- ----- --------------
<S> <C> <C> <C> <C> <C>
1989-1990 18 14.5 5 4.0 456
1991 11 10.3 5 4.7 170
1992 15 12.5 8 6.4 285
1993 30 20.2 16 8.8 360
1994 25 14.2 17 9.8 389
1995 34 16.3 18 8.8 343
1996 38 22.0 25 15.5 422
1997 54 26.6 30 16.4 450
1998 47 22.7 26 11.4 370
</TABLE>
- -------------
(1) Completed as producing wells in the Knox formations.
The Company's historical experience is that the average Knox well
produces 20% to 25% of its recoverable reserves in the first year of production
and approximately 50% of its recoverable reserves in the first three years with
a steady decline thereafter. Wells in the Knox formations have an expected
productive life ranging from 10 to 20 years.
13
<PAGE> 15
As shown in the following table, the Company's production from Knox
formation wells has increased steadily as additional wells have been drilled.
<TABLE>
<CAPTION>
PRODUCING WELLS AND PRODUCTION FROM KNOX FORMATIONS
------------------------------------------------------------------------
1994 1995 1996 1997 1998
------------ ------------ ------------ ------------ -------------
<S> <C> <C> <C> <C> <C>
Number of wells in production:
Gross 41 66 82 112 140
Net 29.7 41.5 58.9 75.6 88.0
Percent of total net wells 0.8% 0.7% 0.9% 1.0% 1.2%
Annual production (net):
Oil (Mbbl) 67.1 74.9 78.2 111.2 181.9
Gas (Mmcf) 1,041 1,624 2,788 3,600 4,111
Combined (Mmcfe) 1,444 2,074 3,257 4,267 5,202
Percent of total combined
production 11% 10% 11% 13% 15%
</TABLE>
Productive Knox wells represented approximately 1.2% of the Company's
total productive wells at December 31, 1998. Production from Knox wells in 1998,
however, equaled 15% of the Company's total production on an Mcfe basis.
The Company is well positioned to exploit the undeveloped potential of
the Knox formations in the future. At December 31, 1998, it held leases on
approximately 560,567 net acres overlying potential Knox drilling locations.
In addition, the Company has also tested the Niagaran Carbonate,
Trenton/Black River Carbonates, Onondaga Limestone, Oriskany Sandstone and
Newburg Sandstone formations. Certain typical characteristics of the less
developed or deeper formations drilled by the Company in 1998 are described
below:
<TABLE>
<CAPTION>
Average Average
Drilling Costs Gross
-------------------------------- Reserves
Range of Dry Completed per Completed
Formation Location Well Depths Hole Well Well
- ------------------- -------- ----------- ----------- ----------- -------------
(in feet) (in thousands) (in Mmcfe)
<S> <C> <C> <C> <C> <C>
Knox formations OH, NY 2,500-8,000 $ 130 $ 240 400
Trenton/Black River Carbonates NY 5,000-7,000 300 525 1,200
Niagaran Carbonate MI 4,500-5,500 275 525 1,200
Onondaga Limestone PA 4,000-5,500 100 190 400
Oriskany Sandstone PA, NY 4,500-7,000 150 225 500
Newburg Sandstone WV 5,500-6,000 175 275 1,000
</TABLE>
14
<PAGE> 16
Drilling Results. The following table sets forth drilling results with
respect to wells drilled during the past five years:
<TABLE>
<CAPTION>
HIGHLY DEVELOPED OR BLANKET FORMATIONS (1) LESS DEVELOPED OR DEEPER FORMATIONS (2)
------------------------------------------- ------------------------------------------------------
1994 1995 1996 1997 1998 1994 1995 1996 1997 1998
------ ------ ------ ------ ------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Productive:
Gross 58 106 153 187 189 22(3) 23(4) 34 39(5) 29(6)
Net 45.6 92.5 126.3 156.5 167.0 12.7 11.5 22.2 24.5 14.2
Dry:
Gross 2 4 2 7 3 10 22 18 28 28
Net 0.4 3.2 2.0 6.3 2.5 4.8 10.7 10.2 12.3 15.5
Reserves
developed-
net (Bcfe) 4.8 18.5 32.7 32.8 32.3 5.2 5.2 7.7 9.0 3.0
Approximate
cost (in millions) $ 5.8 $ 15.1 $ 22.2 $ 31.2 $ 28.4 $ 5.5 $ 5.3 $ 9.0 $ 9.3 $ 7.6
</TABLE>
(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 Limestone and Knox formations in
Ohio, the Niagaran and Dundee Carbonates in Michigan, the 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 the shallower Clinton formation.
(4) 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 Oriskany formation was subsequently completed in
the shallower Berea/Shale formations.
(5) Three additional wells which were dry in the Knox formations were
subsequently completed in shallower formations.
(6) Two additional wells which were dry in the Knox formations were
subsequently completed in the shallower Clinton formation.
OILFIELD SALES AND SERVICE
The Company has 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. In 1992, Arrow Oilfield
Service Company ("Arrow"), a separate service division, was organized. Arrow
provides the Company and third party customers with necessary oilfield services
such as well workovers, well completions, brine hauling and disposal and oil
trucking. Arrow is currently the largest oilfield service company in Ohio. In
1998, approximately 55% of Arrow's revenues were generated by sales to third
parties.
Target Oilfield Pipe & Supply Company ("TOPS"), a wholly-owned
subsidiary of the Company, operates retail sales outlets in the Appalachian and
Michigan Basins from which it sells a broad range of equipment, including pipe,
tanks, fittings, valves and pumping units. The Company originally entered the
15
<PAGE> 17
oilfield supply business to ensure the quality and availability of supplies for
its own operations. In 1998, approximately 72% of TOPS' revenues were
generated by sales to third parties.
EMPLOYEES
As of February 26, 1999, the Company had 574 full-time employees,
including 16 gas marketing employees, 318 oil and gas production employees, 19
petroleum engineers, 9 geologists, 3 geophysicists, 169 oilfield sales and
service employees and 40 general administrative employees.
COMPETITION AND CUSTOMERS
The oil and gas industry is highly competitive. Competition is
particularly intense with respect to the acquisition of producing properties 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,
production and marketing include major integrated oil and gas companies as well
as numerous independent oil and gas companies, individual proprietors, natural
gas pipelines and their affiliates and natural gas marketers and brokers. 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 be dependent on its
ability to exploit its current developed and undeveloped lease holdings and its
ability to select and acquire suitable producing properties and prospects for
future exploration and development.
No customer exceeded 10% of consolidated revenues during the year ended
December 31, 1998, the six months ended June 30, 1997 and December 31, 1997 and
the year ended December 31, 1996.
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 natural gas
and oil, and other matters. Such regulations may impose restrictions on the
production of natural gas and oil 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 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 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
16
<PAGE> 18
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 (the "NGA") and the
Natural Gas Policy Act of 1978 (the "NGPA"). In the past, the federal government
has regulated the prices at which oil and 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, 1996, 1997 and 1998 determined in accordance with
the rules and regulations of the Securities and Exchange Commission. 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.
<TABLE>
<CAPTION>
December 31,
--------------------------------
1996 1997 1998
----- ----- -----
Estimated proved reserves
<S> <C> <C> <C>
Gas (Bcf) 288.6 291.6 315.3
Oil (Mbbl) 7,389 5,552 4,243
</TABLE>
See Note 17 to the consolidated financial statements for more detailed
information regarding the Company's oil and gas reserves. The following table
sets forth the estimated future net cash flows from the proved reserves of the
Company and the present value of such future net cash flows as of December 31,
1998 determined in accordance with the rules and regulations of the Securities
and Exchange Commission.
<TABLE>
<CAPTION>
Estimated future net cash flows (before income taxes) (in thousands)
attributable to estimated production during
<S> <C>
1999 $ 52,625
2000 36,451
2001 41,310
2002 and thereafter 347,694
----------
Total $ 478,080
==========
Present value before income taxes
(discounted at 10% per annum) $ 256,557
==========
Present value after income taxes
(discounted at 10% per annum) $ 208,663
==========
</TABLE>
17
<PAGE> 19
Estimated future net cash flows represent estimated future gross
revenues from the production and sale of proved reserves, net of estimated
production 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, 1998 without escalation, except where changes in prices were
fixed and readily determinable under existing contracts. The following table
sets forth the weighted average year-end prices for oil and gas:
<TABLE>
<CAPTION>
December 31,
--------------------------------------
1996 1997 1998
------ ------ ------
<S> <C> <C> <C>
Gas (per Mcf) $ 3.02 $ 2.73 $ 2.49
Oil (per Bbl) 23.00 14.59 9.73
</TABLE>
IMPAIRMENT OF OIL AND GAS PROPERTIES AND OTHER ASSETS
As described in Note 2 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. As
demonstrated by the chart in the preceding section, the decline in oil and gas
prices since 1996 has been significant and has negatively impacted the quantity
and value of the Company's oil and gas reserves. Given this impairment
indicator, the Company computed the expected future undiscounted cash flows,
employing methods consistent with those utilized to determine the estimated
future net cash flows from proved reserves discussed above. For those assets in
which the sum of the expected future undiscounted cash flows was less than the
carrying amount, an impairment loss was recognized for the difference between
the fair value and carrying value of the asset, with fair value determined based
on discounted cash flow analysis, sale of similar properties or recent offers
for specific assets. As a result of this evaluation, the Company recorded total
impairment charges of $160.7 million (pre-tax) in 1998, consisting of $148.0
million relating to producing properties and related assets, $5.8 million for
unproved properties and $6.9 million relating to other long-lived assets. The
magnitude of the impairment charge was impacted by the Acquisition in 1997, in
which the allocation of the purchase price at fair value resulted in a
significant increase in the book value of the Company's assets.
PRODUCING WELL DATA
The following table summarizes by state the Company's productive wells
at December 31, 1998:
<TABLE>
<CAPTION>
December 31, 1998
--------------------------------------------------------------------------------
Oil Wells Gas Wells Total
-------------------- -------------------- --------------------
State Gross Net Gross Net Gross Net
- ------------- ----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Ohio 1,973 1,859 1,548 1,399 3,521 3,258
West Virginia 376 373 1,416 1,303 1,792 1,676
Pennsylvania 381 376 642 522 1,023 898
New York 7 7 878 859 885 866
Michigan 7 4 731 289 738 293
Kentucky -- -- 110 110 110 110
----- ----- ----- ----- ----- -----
2,744 2,619 5,325 4,482 8,069 7,101
===== ===== ===== ===== ===== =====
</TABLE>
18
<PAGE> 20
ACREAGE DATA
The following table summarizes by state the Company's gross and net
developed and undeveloped leasehold acreage at December 31, 1998:
<TABLE>
<CAPTION>
December 31, 1998
------------------------------------------------------------------------------------------------------
Developed Acreage Undeveloped Acreage Total Acreage
-------------------------- -------------------------- ----------------------------
State Gross Net Gross Net Gross Net
- -------------- ------- ------- ------- ------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Ohio 320,176 290,687 223,343 185,777 543,519 476,464
West Virginia 75,321 66,683 131,171 75,551 206,492 142,234
Pennsylvania 59,422 46,960 272,708 259,780 332,130 306,740
New York 130,142 115,809 76,482 73,415 206,624 189,224
Michigan 42,843 26,976 61,074 46,414 103,917 73,390
Kentucky 12,450 12,450 5,756 5,709 18,206 18,159
------- ------- ------- ------- --------- ---------
640,354 559,565 770,534 646,646 1,410,888 1,206,211
======= ======= ======= ======= ========= =========
</TABLE>
Item 3. LEGAL PROCEEDINGS
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 or the results of operations.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
There is no established public trading market for the Company's equity
securities.
The number of record holders of the Company's equity securities at
February 28, 1999 was as follows:
<TABLE>
<CAPTION>
Number of
Title of Class Record Holders
- ---------------------------------------- --------------------
<S> <C>
Common Stock 7
</TABLE>
19
<PAGE> 21
DIVIDENDS
No dividends have been paid on the Company's Common Stock.
Item 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
PREDECESSOR COMPANY | SUCCESSOR COMPANY
------------------------------------------------- | ------------------------------
| AS OF OR FOR
AS OF OR FOR THE SIX MONTHS | SIX MONTHS THE YEAR
YEAR ENDED DECEMBER 31, ENDED | ENDED ENDED
----------------------------------- JUNE 30, | DECEMBER 31, DECEMBER 31,
(IN THOUSANDS) 1994 1995 1996 1997 | 1997 1998
--------- --------- --------- --------- | --------- -----------
<S> <C> <C> <C> <C> | <C> <C>
OPERATIONS: |
|
Revenues $ 79,365 $ 110,067 $ 153,235 $ 79,397 | $ 84,126 $ 154,839
Depreciation, depletion |
and amortization 11,886 19,717 29,752 15,366 | 31,694 68,488
Impairment of oil and gas |
properties and other assets -- -- -- -- | -- 160,690
Income (loss) from |
continuing operations 4,180 6,260 15,194 (9,873) | (11,372) (130,550)
|
Preferred dividends paid 180 180 180 45 | -- --
|
BALANCE SHEET DATA: | AS OF 12/31/97
| --------------
Working capital 13,612 17,359 22,110 | 19,846 (6,268)
Oil and gas properties and |
gathering systems, net 106,710 216,848 222,127 | 491,183 320,325
Total assets 148,173 297,298 303,763 | 599,320 418,605
Long-term liabilities, |
less current portion 47,858 110,523 97,642 | 355,649 354,382
Preferred stock 2,400 2,400 2,400 | -- --
Total shareholders' equity (deficit) 81,142 142,291 158,918 | 96,858 (33,014)
</TABLE>
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
As disclosed in the accompanying notes to consolidated financial
statements, on March 27, 1997 the Company entered into a merger agreement with
TPG which resulted in all of the Company's common stock being acquired by TPG
and certain other investors on June 27, 1997 in a transaction accounted for as a
purchase. For financial reporting purposes, the Acquisition is considered
effective June 30, 1997 and the operations of the Company prior to July 1, 1997
are classified as predecessor company operations. The consolidated balance
sheets at December 31, 1997 and 1998 include the application of purchase
accounting to measure the Company's assets and liabilities at fair value. Debt
incurred to finance the Acquisition and related transaction costs are reflected
in the December 31, 1997 and 1998 financial statements. A vertical black line is
shown in the financial statements to separate the results of operations of the
predecessor and successor companies.
The allocation of the purchase price at fair value resulted in a
significant increase in the book value of the Company's assets. The increase in
the book value of assets resulted in materially higher charges for depreciation,
depletion and amortization in the second half of 1997 and all of 1998.
20
<PAGE> 22
As described in Note 2 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. Due to
sustained significantly lower oil and gas prices, the quantity and value of the
Company's oil and gas reserves have been negatively impacted. Given this
impairment indicator, the Company computed the expected future undiscounted cash
flows, employing methods consistent with those utilized to determine the
estimated future net cash flows from proved reserves discussed in Note 17 to the
consolidated financial statements. For those assets in which the sum of the
expected future undiscounted cash flows was less than the carrying amount, an
impairment loss was recognized for the difference between the fair value and
carrying value of the asset, with fair value determined based on discounted cash
flow analysis, sale of similar properties or recent offers for specific assets.
As a result of this evaluation, the Company recorded total impairment charges of
$160.7 million (pre-tax) in 1998, consisting of $148.0 million relating to
producing properties and related assets, $5.8 million for unproved properties
and $6.9 million relating to other long-lived assets. The magnitude of the
impairment charge was impacted by the Acquisition in 1997, in which the
allocation of the purchase price at fair value resulted in a significant
increase in the book value of the Company's assets.
The Company incurred transaction costs associated with the Acquisition
of $16.8 million. These costs were expensed in the second quarter of 1997. As a
result of the Acquisition, the Company is highly leveraged, resulting in
materially higher interest charges in the second half of 1997 and all of 1998.
These higher interest charges are expected to continue in subsequent accounting
periods.
The Company's principal business is natural gas marketing and gathering
and the production, acquisition and development of, and exploration for, oil and
gas reserves, principally in Ohio, West Virginia, Pennsylvania, Michigan, New
York and Kentucky.
The Company's gas marketing and gathering operations consist of
purchasing gas at the wellhead and from interstate pipelines and selling gas to
industrial and commercial customers and local gas distribution companies.
The Company utilizes the "successful efforts" method of accounting for
its oil and gas properties. Under this method, property acquisition and
development costs and productive exploration costs are capitalized while
non-productive exploration costs, which include dry holes, expired leases and
delay rentals, are expensed as incurred. Capitalized costs related to proved
properties are depleted using the unit-of-production method. 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.
The Company provides oilfield sales and services to its own operations
and to third parties. Oilfield sales and service provided to the Company's own
operations are provided at cost and all intercompany revenues and expenses are
eliminated in consolidation.
21
<PAGE> 23
RESULTS OF OPERATIONS
As a result of the Acquisition, the results of operations for the
periods subsequent to June 30, 1997 are not necessarily comparable to those
prior to July 1, 1997. The following table combines the six-month predecessor
company period ended June 30, 1997 with the six-month successor company period
ended December 31, 1997 for purposes of the discussion of year-end results
(dollars are stated in thousands and as a percentage of revenue).
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------
1998 1997 1996
----------------------- ------------------------- ----------------------
<S> <C> <C> <C> <C> <C> <C>
REVENUES
Oil and gas sales $ 87,055 56.2% $ 85,756 52.4% $ 79,491 51.9%
Gas marketing and gathering 40,025 25.8 44,371 27.1 44,527 29.0
Oilfield sales and service 23,333 15.1 30,206 18.5 25,517 16.7
Other 4,426 2.9 3,190 2.0 3,700 2.4
--------- ----- -------- ----- --------- -----
154,839 100.0 163,523 100.0 153,235 100.0
EXPENSES
Production expense 23,739 15.3 21,496 13.2 18,098 11.8
Production taxes 2,986 1.9 3,172 1.9 3,168 2.1
Cost of gas and gathering expense 33,588 21.7 37,784 23.1 37,556 24.5
Oilfield sales and service 23,225 15.0 28,021 17.1 23,142 15.1
Exploration expense 9,982 6.5 10,360 6.3 6,064 4.0
General and administrative expense 4,909 3.2 4,258 2.6 4,573 3.0
Depreciation, depletion and amortization 68,488 44.2 47,060 28.8 29,752 19.4
Impairment of oil and gas properties
and other assets 160,690 103.8
Franchise, property and other taxes 1,084 0.7 1,875 1.2 1,739 1.1
--------- ----- -------- ----- --------- -----
328,691 212.3 154,026 94.2 124,092 81.0
--------- ----- -------- ----- --------- -----
OPERATING (LOSS) INCOME (173,852) (112.3) 9,497 5.8 29,143 19.0
Interest expense 32,903 21.2 19,132 11.7 7,383 4.8
Transaction-related expenses 16,758 10.3
--------- ----- -------- ----- --------- -----
32,903 21.2 35,890 22.0 7,383 4.8
--------- ----- -------- ----- --------- -----
(LOSS) INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES (206,755) (133.5) (26,393) (16.2) 21,760 14.2
(Benefit) provision for income taxes (76,205) (49.2) (5,148) (3.2) 6,566 4.3
--------- ----- -------- ----- --------- -----
(LOSS) INCOME FROM CONTINUING OPERATIONS (130,550) (84.3) (21,245) (13.0) 15,194 9.9
LOSS FROM DISCONTINUED OPERATIONS (439) (0.3)
--------- ----- -------- ----- --------- -----
NET (LOSS) INCOME $(130,550) (84.3)% $(21,245) (13.0)% $ 14,755 9.6%
========= ===== ======== ===== ========= =====
EBITDAX $ 65,308 42.2% $ 66,917 40.9% $ 64,959 42.4%
</TABLE>
1998 COMPARED TO 1997
Operating income decreased $183.4 million from $9.5 million in 1997 to
an operating loss of $173.9 million in 1998. The decrease in operating income
was due primarily to the $160.7 million write-down of certain permanently
impaired assets and a $21.4 million increase in depreciation, depletion and
amortization expense from significant increases in the book value of property,
equipment and other assets as a result of the purchase accounting associated
with the Acquisition discussed above.
Loss from continuing operations increased $109.4 million from a loss of
$21.2 million in 1997 to a loss of $130.6 million in 1998. This increase was the
result of the $160.7 million asset impairment, the $21.4 million increase in
depreciation, depletion and amortization expense and an increase of $13.8
million in interest expense offset by the $16.8 million of transaction-related
expenses in 1997 and an increase in the income tax benefit of $71.1 million.
This increase in the income tax benefit was primarily due to the decrease in
income from continuing operations before income taxes combined with a change in
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<PAGE> 24
the effective tax rate due to the nondeductibility of certain transaction-
related expenses and a decrease in the utilization of nonconventional fuel
source tax credits in 1998.
Earnings before interest, income taxes, depreciation, depletion and
amortization and exploration expense ("EBITDAX") was $65.3 million in 1998
compared to $66.9 million in 1997.
Total revenues decreased $8.7 million (5%) in 1998 compared to 1997.
Gross operating margins decreased $3.0 million (4%) in 1998 compared to 1997.
Oil volumes increased 15,000 Bbls (2%) from 753,000 Bbls in 1997 to
768,000 Bbls in 1998 resulting in an increase in oil sales of approximately
$272,000. Gas volumes increased 2.9 Bcf (11%) from 27.2 Bcf in 1997 to 30.1 Bcf
in 1998 resulting in an increase in gas sales of approximately $7.8 million.
These volume increases were primarily due to production from properties acquired
and wells drilled in 1997 and 1998.
The average price paid for the Company's oil decreased from $18.10 per
barrel in 1997 to $12.61 per barrel in 1998 which decreased oil sales by
approximately $4.2 million. The average price paid for the Company's natural gas
decreased $.08 per Mcf to $2.57 per Mcf in 1998 compared to 1997 which decreased
gas sales in 1998 by approximately $2.4 million.
Production expense increased $2.2 million (10%) from $21.5 million in
1997 to $23.7 million in 1998. The average production cost of $.68 per Mcfe in
1998 was consistent when compared to the same period in 1997. Production taxes
decreased $186,000 from $3.2 million in 1997 to $3.0 million in 1998. Average
production taxes decreased from $.10 per Mcfe in 1997 to $.09 per Mcfe in 1998.
Depreciation, depletion and amortization increased by $21.4 million
(46%) from $47.1 million in 1997 to $68.5 million in 1998. Depletion expense
increased $19.2 million (50%) from $38.5 million in 1997 to $57.7 million in
1998. Depletion per Mcfe increased from $1.21 per Mcfe in 1997 to $1.66 per Mcfe
in 1998. These increases were primarily the result of significant increases in
the book value of property, equipment and other assets as a result of the
purchase accounting associated with the Acquisition discussed above.
Interest expense increased $13.8 million (72%) from $19.1 million in
1997 to $32.9 million in 1998. This increase was due to substantial additional
debt incurred primarily to finance the Acquisition.
In the exploration and production segment, 1998 revenues remained
consistent with 1997 revenues. Loss from continuing operations before income
taxes increased $168.0 million from $6.6 million in 1997 to $174.6 million in
1998. This increase was due primarily to the $144.7 million write-down of
certain permanently impaired exploration and production segment assets, a $12.4
million increase in interest expense associated with the additional debt
incurred to finance the Acquisition and the properties acquired and wells
drilled in 1998 and 1997 and a $11.9 million increase in depreciation, depletion
and amortization expense from significant increases in the book value of the
segment's property, equipment and other assets as a result of the purchase
accounting associated with the Acquisition and the properties acquired and wells
drilled in 1998 and 1997.
Gas marketing and gathering segment revenues decreased $1.8 million
from $41.4 million in 1997 to $39.6 million in 1998. Income from continuing
operations before income taxes decreased $18.6 million from $2.9 million in 1997
to a loss of $15.7 million in 1998. This decrease was due
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<PAGE> 25
primarily to the $9.1 million write-down of certain permanently impaired gas
marketing and gathering segment assets and a $8.7 million increase in
depreciation, depletion and amortization expense from significant increases in
the book value of the segment's property, equipment and other assets as a
result of the purchase accounting associated with the Acquisition.
Oilfield sales and service segment revenues decreased $6.6 million from
$30.4 million in 1997 to $23.8 million in 1998. This decrease was primarily the
result of work deferred by the Company and third parties due to low oil prices.
Income from continuing operations before income taxes decreased $9.9 million
from $681,000 in 1997 to a loss of $9.2 million in 1998. This decrease was due
primarily to the $6.9 million write-down of certain permanently impaired
oilfield sales and service segment assets and a $2.3 million decrease in the
oilfield sales and service operating margin.
1997 COMPARED TO 1996
Operating income decreased $19.6 million (67%) from $29.1 million in
1996 to $9.5 million in 1997. The decrease in operating income was due primarily
to an $17.3 million increase in depreciation, depletion and amortization expense
from significant increases in the book value of property, equipment and other
assets as a result of the purchase accounting associated with the Acquisition
discussed above.
Income from continuing operations decreased $36.4 million from income
of $15.2 million in 1996 to a loss of $21.2 million in 1997. This decrease was
the result of $16.8 million of transaction-related expenses, the $17.3 million
increase in depreciation, depletion and amortization expense and an increase of
$11.7 million in interest expense offset by a decrease in the provision for
income taxes of $11.7 million. This decrease in the provision for income taxes
was primarily due to the decrease in income from continuing operations before
income taxes combined with a change in the effective tax rate due to the
nondeductibility of certain transaction-related expenses and a decrease in the
utilization of nonconventional fuel source tax credits in 1997.
Earnings before interest, income taxes, depreciation, depletion and
amortization and exploration expense was $66.9 million in 1997 compared to $65.0
million in 1996.
Total revenues increased $10.3 million (7%) in 1997 compared to the
same period of 1996. Gross operating margins in 1997 were consistent when
compared to the same period in 1996.
Oil volumes increased 34,000 Bbls (5%) from 719,000 Bbls in 1996 to
753,000 Bbls in 1997 resulting in an increase in oil sales of approximately
$700,000. Gas volumes increased 1.8 Bcf (7%) from 25.4 Bcf in 1996 to 27.2 Bcf
in 1997 resulting in an increase in gas sales of approximately $4.6 million.
These volume increases were primarily due to production from properties acquired
and wells drilled in 1996 and 1997.
The average price paid for the Company's oil decreased from $20.24 per
barrel in 1996 to $18.10 per barrel in 1997 which decreased oil sales by
approximately $1.6 million. The average price paid for the Company's natural gas
increased $.09 per Mcf to $2.65 per Mcf in 1997 compared to 1996 which increased
gas sales in 1997 by approximately $2.4 million.
Production expense increased $3.4 million (19%) from $18.1 million in
1996 to $21.5 million in 1997. The average production cost increased from $.61
per Mcfe in 1996 to $.68 per Mcfe in 1997. These increases were due to an
anticipated steep decline in production volumes from certain high volume wells
with low production costs coupled with a reduction in operating fees received
from third parties
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<PAGE> 26
primarily due to the purchase of certain third party working interests by the
Company. Such fees are recorded as a reduction of production expense.
Production taxes were consistent at $3.2 million in 1997 and 1996.
Depreciation, depletion and amortization increased by $17.3 million
(58%) from $29.8 million in 1996 to $47.1 million in 1997. Depletion expense
increased $15.5 million (68%) from $23.0 million in 1996 to $38.5 million in
1997. Depletion per Mcfe increased from $.77 per Mcfe in 1996 to $1.21 per Mcfe
in 1997. These increases were primarily the result of significant increases in
the book value of property, equipment and other assets as a result of the
purchase accounting associated with the Acquisition discussed above.
Interest expense increased $11.7 million (159%) from $7.4 million in
1996 to $19.1 million in 1997. This increase was due to substantial additional
debt incurred primarily to finance the Acquisition.
Exploration and production segment revenues increased $5.7 million from
$85.6 million in 1996 to $91.3 million in 1997 due to the changes in oil and gas
volumes and prices discussed above. Income from continuing operations before
income taxes decreased $29.2 million from $22.6 million in 1996 to a loss of
$6.6 million in 1997. This decrease was due primarily to a $10.9 million
increase in interest expense associated with the additional debt incurred to
finance the properties acquired and wells drilled in 1997 and a $16.5 million
increase in depreciation, depletion and amortization expense from significant
increases in the book value of the segment's property, equipment and other
assets as a result of the purchase accounting associated with the Acquisition.
In the gas marketing and gathering segment, 1997 revenues remained
consistent with 1996 revenues. Income from continuing operations before income
taxes decreased $596,000 from $3.5 million in 1996 to $2.9 million in 1997.
Oilfield sales and service segment revenues increased $4.9
million from $25.5 million in 1996 to $30.4 million in 1997. Income from
continuing operations before income taxes decreased $687,000 from $1.4 million
in 1996 to $681,000 in 1997.
LIQUIDITY AND CAPITAL RESOURCES
The Company's liquidity and capital resources are closely related to
and dependent on the current prices paid for its oil and gas.
The Company's current ratio at December 31, 1998 was 0.90 to 1.00.
During 1998, working capital decreased $26.1 million from $19.8 million to a
deficit of $6.3 million. The decrease was primarily due to an increase in
current portion of long-term debt of $28.1 million offset by an increase in cash
of $4.1 million. The Company's operating activities provided cash flows of $25.3
million in 1998.
On June 27, 1997, the Company entered into a senior revolving credit
agreement with several lenders. These lenders have committed, subject to
compliance with the borrowing base, to provide the Company with revolving credit
loans of up to $200 million, of which $25 million will be available for the
issuance of letters of credit. The borrowing base is determined based on the
Company's oil and gas reserves and other assets and is subject to annual or
semiannual adjustment. The Company's borrowing base at December 31, 1998, was
$170 million. On January 15, 1999, the Company's borrowing base was reduced to
$126 million. The Company had $154 million outstanding under this agreement at
December 31, 1998, which resulted in the Company having a borrowing base
deficiency of $28 million. The
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<PAGE> 27
Company has agreed with the lenders to reduce this deficiency by $14 million on
March 22, 1999 and by the remaining $14 million on May 10, 1999.
On March 22, 1999, the Company made a $14 million payment to reduce the
outstanding amount under the credit agreement to $140 million. The funds for the
payment were provided by internally generated cash flow and a term loan provided
by Chase Manhattan Bank. This term loan provided borrowings of $9 million and is
due on September 22, 1999. Interest is payable monthly at LIBOR plus 1.5%. The
Company is in the process of renegotiating its revolving credit facility with
its lenders and expects to have a new facility in place prior to May 10, 1999,
when the second payment of $14 million is due. Should the Company not be
successful in renegotiating an acceptable facility, the Company expects to be
able to meet its 1999 debt service requirements through internally generated
cash flow, the sale of non-strategic assets and/or the use of instruments in
financial futures markets.
At December 31, 1998, the outstanding balance under the credit
agreement was $154 million. The credit agreement will mature on June 27, 2002.
Outstanding balances under the agreement incur interest at the Company's choice
of several indexed rates, the most favorable being 6.566% at December 31, 1998.
The credit agreement contains a number of covenants that, among other
things, restricts the ability of the Company and its subsidiaries to dispose of
assets, incur additional indebtedness, prepay other indebtedness or amend
certain debt instruments, pay dividends, create liens on assets, enter into sale
and leaseback transactions, make investments, loans or advances, make
acquisitions, engage in mergers or consolidations, change the business conducted
by the Company or its subsidiaries, make capital expenditures or engage in
certain transactions with affiliates and otherwise restrict certain corporate
activities. In addition, under the credit agreement, the Company is required to
maintain specified financial ratios and tests, including minimum interest
coverage ratios and maximum leverage ratios. The agreement requires a minimum
working capital ratio of 1.00 to 1.00. As of December 31, 1998, the Company's
working capital ratio was .90 to 1.00. The Company and its lenders have agreed
to exclude the $28 million required reduction in outstanding borrowings from the
covenant requiring a specific working capital ratio. The ratio after excluding
the $28 million results in a working capital ratio of 1.58 to 1.00.
The Company issued $225 million of 9.875% Senior Subordinated Notes on
June 27, 1997. The notes mature June 15, 2007. Interest is payable semiannually
on June 15 and December 15 of each year, commencing December 15, 1997.
The notes are general unsecured obligations of the Company and are
subordinated in right of payment to senior debt. Except as otherwise described
below, the notes are not redeemable prior to June 15, 2002. Thereafter, the
notes are subject to redemption at the option of the Company at specific
redemption prices. Prior to June 15, 2000, the Company may, at its option, on
any one or more occasions, redeem up to 40% of the original aggregate principal
amount of the notes at a redemption price equal to 109.875% of the principal
amount, plus accrued and unpaid interest, if any on the redemption date, with
all or a portion of net proceeds of public sales of common stock of the Company;
provided that at least 60% of the original aggregate principal amount of the
notes remains outstanding immediately after the occurrence of such redemption;
and provided, further, that such redemption shall occur within 60 days of the
date of the closing of the related sale of common stock of the Company. Prior to
June 15, 2002, the notes may be redeemed as a whole at the option of the Company
upon the occurrence of a change in control.
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<PAGE> 28
The indenture contains certain covenants that limit the ability of the
Company and its subsidiaries to incur additional indebtedness and issue stock,
pay dividends, make distributions, make investments, make certain other
restricted payments, enter into certain transactions with affiliates, dispose of
certain assets, incur liens securing indebtedness of any kind other than
permitted liens, and engage in mergers and consolidations.
On March 31, 1997, the Company redeemed all of the outstanding Class II
Series A preferred stock for $2.4 million in cash.
On April 3, 1997, the Company gave notice of redemption of all of the
outstanding 9.25% convertible subordinated debentures for 104% of face value.
Redemption of these debentures occurred June 10, 1997 when holders of the
debentures elected to convert them into 275,425 shares of predecessor common
stock.
On June 25, 1997, the Company redeemed all $35 million of its 7%
fixed-rate senior notes.
On June 27, 1997, the Company repaid all outstanding amounts due under
the then existing revolving bank facility in the amount of $94 million.
The Company currently expects to spend approximately $4 million during
1999 on its drilling activities and other capital expenditures. The Company
intends to finance such activities, as well as its acquisition program, through
its available cash flow, available revolving credit line, additional borrowings
or additional equity. The level of the Company's cash flow in the future will
depend on a number of factors including the demand and price levels for oil and
gas, its ability to acquire additional producing properties and the scope and
success of its drilling activities.
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 would be exchanged for a fixed
interest rate. During October 1997, the Company entered into two interest rate
swap arrangements covering $90 million of debt. The Company swapped $40 million
of floating three-month LIBOR +1.5% for a fixed rate of 7.485% for three years,
extendible at the institution's option for an additional two years. The Company
also swapped $50 million of floating three-month LIBOR +1.5% for a fixed rate of
7.649% for five years. During June 1998, the Company entered into a third
interest rate swap covering $50 million of debt. The Company swapped $50 million
of floating rate three-month LIBOR + 1.5% for a fixed rate of 7.2825% for three
years.
INFLATION AND CHANGES IN PRICES
During 1996, the price paid for the Company's crude oil increased from
a low of $16.50 per barrel at year-end 1995 to a high of $22.50 per barrel at
year-end 1996, with an average price of $20.24 per barrel. During 1997, the
price paid for the Company's crude oil increased from $22.50 per barrel at
year-end 1996 to a high of $23.50 per barrel in early 1997, then decreased to a
low of $14.25 at year-end 1997, with an average price of $18.10 per barrel.
During 1998, the price paid for the Company's crude oil increased to a high of
$14.50 per barrel in January, then decreased to a low of $8.50 per barrel in
December and increased to $9.25 per barrel at year-end 1998, with an average
price of $12.61 per barrel. The average price of the Company's natural gas
increased from $2.56 per Mcf in 1996 to $2.65 per Mcf in 1997, then decreased to
$2.57 per Mcf in 1998.
The price of oil and gas has a significant impact on the Company's
results of operations. Oil and gas prices fluctuate based on market conditions
and, accordingly, cannot be predicted. As a result of
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<PAGE> 29
increased competition among drilling contractors and suppliers and continuing
low levels of drilling activity in the Company's operating area, costs to
drill, complete, and service wells have remained relatively constant in recent
years.
Historically, a large portion of the Company's natural gas sales has
been under long-term fixed price contracts. As a result of recent acquisitions,
certain natural gas sales are currently based on indexed prices. Many of these
contracts contain "trigger" clauses which allow the Company to fix the price at
which deliveries in future months will be sold at the NYMEX price for one or
more future months. The Company may also, from time to time, enter into hedging
transactions with financial institutions to reduce its exposure to variable
commodity pricing.
READINESS FOR YEAR 2000
Like most companies, the Company is faced with the Year 2000 ("Y2K")
issue. The Y2K problem arose because many existing computer programs use only
the last two digits to refer to a year. This does not allow programs to properly
recognize a year that begins with "20" instead of "19". Any computer programs
that have date-sensitive software may recognize a date using "00" as the year
1900 instead of the year 2000. This could result in system failures and
miscalculations causing disruptions of operations or financial processes, such
as equipment failures or a temporary inability to process transactions or send
invoices.
The Company has taken actions to understand the nature and extent of
the work required to make its systems and operations Y2K compliant. A project
team is responsible for coordinating the assessment, remediation, testing and
implementation of the necessary modifications to its key applications (which
consist of third party software, hardware and embedded chip systems, as well as
internally developed computer applications). To date, the team has worked to
identify potential risks to the Company and has replaced the Company's major
legacy systems. An inventory of hardware and software and all peripheral systems
is complete and prioritized for upgrade or replacement. A testing plan has been
developed, and the Company expects to complete testing of its mission-critical
systems by the end of June, 1999.
The Company intends to monitor and compare the estimated costs
associated with its actions to actual costs. Estimated additional costs for
making the necessary changes (primarily installation of current releases of
operating systems and application software) to such systems, including
implementation and testing efforts, are expected to range from $250,000 to
$350,000 not including internal costs. This estimate is based on various factors
including availability of internal and external resources and complexity of the
software applications. Such estimate does not include costs of new systems for
which the principal justification is improved business functionality, rather
than Y2K compliance. While the Company has enlisted the guidance of various
industry experts in the project planning process, it does not rely on the
assistance of outside consultants to direct the project. Employees assigned to
the project have integrated their responsibilities into normal operations. The
Company does not separately track the internal costs incurred in connection with
the project. Such internal costs consist primarily of payroll costs for the
employees assigned to the project.
The Company's goal is to ensure that all of its critical systems and
processes remain functional. Since certain systems may be interrelated with
systems outside the Company's control, there can be no assurance that all
implementations will be successful. The Company has completed identification of
its critical relationships with outside vendors, customers and business partners
and has requested confirmation of Y2K compliance from such third parties. Among
these, special attention is being given to obtaining evidence of Y2K compliance
from third-party transporters of natural gas, deemed as a
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<PAGE> 30
critical element to the Company's uninterrupted business operations. The
Company is preparing contingency plans to minimize any disruptions resulting
from a vendor, supplier or customer not being Y2K compliant. Failure by the
Company and/or its vendors, suppliers, and customers to complete Y2K compliance
could have a material adverse effect on the Company's operations. Recognizing
this risk, formal contingency plans are being developed by the Company and are
expected to be finalized by the end of the second quarter of 1999.
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 future gas marketing activity,
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, the Company's
readiness for Y2K as well as potential adverse consequences related to third
party Y2K compliance and other factors detailed in the Company's filings with
the Securities and Exchange Commission. Actual results may differ materially
from forward-looking statements made in this report.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 manages 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
would be 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 derivative financial instruments for
managing interest rate risks in place as of December 31, 1998 and 1997. The
principal amount of the hedges totaled $140 million and $90 million at December
31, 1998 and 1997, respectively. If market interest rates for short-term
borrowings increased 1%, the increase in the Company's interest expense, after
considering the effects of its interest rate swap and cap agreements, would be
immaterial. This sensitivity analysis is based on the Company's financial
structure at December 31, 1998.
The commodity price risk relates to crude oil and natural gas 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 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 increased $.25 per Mcf, the Company's gas sales would increase $5
million, after considering the effects of the hedging contracts in place at
December 31, 1998. This sensitivity analysis is based on the Company's 1998 gas
sales volumes.
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<PAGE> 31
The information included in this Item is considered to constitute
"forward looking statements" for purposes of the statutory safe harbor provided
in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Forward-Looking
Information" in Item 7 of this Report.
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 generally accepted accounting principles. 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, are engaged to
audit the financial statements and to express an opinion thereon. Their audit is
conducted in accordance with generally accepted auditing standards 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
generally accepted accounting principles.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
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PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Executive officers and directors of the Company as of February 28, 1999
were as follows:
<TABLE>
<CAPTION>
Name Age Position
- ---- --- --------
<S> <C> <C>
Ronald L. Clements 56 Chief Executive Officer and Director
Ronald E. Huff 43 President, Chief Financial Officer and Director
Joseph M. Vitale 57 Senior Vice President Legal, General Counsel, Secretary and
Director
Tommy L. Knowles 48 Senior Vice President Exploration and Production
Leo A. Schrider 60 Senior Vice President Technical Development
Dennis D. Belden 53 Vice President Supply and Service
Duane D. Clark 43 Vice President Gas Marketing
James C. Ewing 56 Vice President Human Resources
Charles P. Faber 57 Vice President Corporate Development
Robert W. Peshek 44 Vice President Finance
Dean A. Swift 46 Vice President, Assistant General Counsel and Assistant Secretary
Henry S. Belden IV 59 Director
Lawrence W. Kellner 40 Director
Max L. Mardick 64 Director
William S. Price, III 43 Director
Gareth Roberts 46 Director
David M. Stanton 36 Director
</TABLE>
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, except that Henry S. Belden IV and
Dennis D. Belden are brothers. The Board of Directors consists of nine
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<PAGE> 33
members each of whom is elected annually to serve one year terms. The business
experience of each executive officer and director is summarized below.
RONALD L. CLEMENTS has been Chief Executive Officer and a Director of
the Company since the Acquisition on June 27, 1997. Previously he served as
Senior Vice President of Exploration and Production and managed the Company's
Exploration and Production Division from 1993 to 1997. He joined Belden & Blake
in 1990 and served as Vice President of Producing Operations. He has more than
30 years of petroleum engineering and production experience. Prior to joining
Belden & Blake he served as Vice President and District Manager of TXO
Production Corporation in Corpus Christi, Texas. From 1967 to 1982, Mr. Clements
held various operational management positions with Shell Oil Company.
Mr. Clements received a BS degree in Electrical Engineering from the
University of North Dakota and a MS degree in Petroleum Engineering from the
University of Tulsa. He is a member of the Society of Petroleum Engineers and
the Ohio Oil and Gas Association.
RONALD E. HUFF has been President and Chief Financial Officer of the
Company since the Acquisition, having previously served as its Senior Vice
President and Chief Financial Officer from 1989 to 1996 and Senior Controller
from 1986 to 1989. Mr. Huff has been a director of Belden & Blake since 1991. He
is a Certified Public Accountant with 20 years of experience in oil and gas
finance and accounting. From 1983 to 1986, Mr. Huff served as Vice President and
Chief Accounting Officer of Towner Petroleum Company. From 1980 to 1983 he
worked for Sonat Exploration Company as Manager of Financial Accounting; and
from 1977 to 1980 he served as Corporate Accounting Supervisor for Transco
Companies, Incorporated. Mr. Huff received a BS degree in Accounting from the
University of Wyoming.
JOSEPH M. VITALE has been Senior Vice President Legal of the Company
since 1989 and has served as its General Counsel since 1974. He has been a
director of the Company since 1991. Prior to joining Belden & Blake, Mr. Vitale
served for four years in the Army Judge Advocate General's Corps. He holds a BS
degree from John Carroll University and a JD degree from Case Western Reserve
Law School. He is a member of the Ohio Oil and Gas Association, the Stark
County, Ohio State and American Bar Associations, and the Interstate Oil Compact
Commission. Mr. Vitale is a past Chairman of the Natural Resources Law Committee
of the Ohio State Bar Association.
TOMMY L. KNOWLES has been Senior Vice President of Exploration and
Production of the Company since 1997. Previously he served as Vice President of
Production from 1996 to 1997. He has 25 years of petroleum engineering and
production experience. Prior to joining Belden & Blake, Mr. Knowles served as
President of FWA Drilling Company, a subsidiary of Texas Oil & Gas Corporation.
From 1982 to 1988 he worked for TXO Production Corporation in Sacramento,
California, serving in various management positions including Vice President;
from 1979 to 1982 he held the position of Drilling and Production Manager for
Texas Oil & Gas Corporation; and, from 1973 to 1979 he held various engineering,
supervisory and management positions with Exxon Corporation.
Mr. Knowles holds a BS degree in Mechanical Engineering from the
University of Texas at Austin where he graduated with honors. He is a member of
the Society of Petroleum Engineers, the American Petroleum Institute, and the
Independent Association of Drilling Contractors.
LEO A. SCHRIDER has been Senior Vice President of Technical Development
since 1993. He previously served as Senior Vice President of Exploration,
Drilling and Engineering for the Company
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since 1986. Mr. Schrider is a Petroleum Engineer with 35 years of experience in
oil and gas production, principally in the Appalachian Basin. Prior to joining
Belden & Blake in 1981, he served as Assistant and Deputy Director of
Morgantown Energy Technology Center from 1976 to 1980. From 1973 to 1976, Mr.
Schrider served as Project Manager of the Laramie Energy Research Center. He
has also held various research positions with the U.S. Department of Energy in
Wyoming and West Virginia.
Mr. Schrider received his BS degree from the University of Pittsburgh
in 1961 and did graduate work at West Virginia University. He has published more
than 35 technical papers on oil and gas production. He was an Adjunct Professor
at West Virginia University and also served as a member of the International
Board of Directors of the Society of Petroleum Engineers. In 1994, Mr. Schrider
was elected to the Board of Directors of the Petroleum Technology Transfer
Council and is chairman of the producer advisory group representing the
Appalachian region.
DENNIS D. BELDEN has served as Vice President of Supply and Service for
the Company since 1989 and has managed the Oilfield Supply and Service Division
since 1992. He joined Belden & Blake in 1980 and served as the Company's land
manager from 1980 to 1989. From 1976 to 1980 he was employed by Wilmot Mining
Company as Special Projects Manager; from 1974 to 1976 he was Treasurer and
General Manager of Cabbages & Kings Restaurant of Ohio; and from 1972 to 1974 he
was employed by T & M Fuel as General Supervisor. Mr. Belden attended Kent State
University. He is a member of the Ohio Oil and Gas Association.
DUANE D. CLARK has been Vice President of Gas Marketing for the Company
since 1997. Previously, he served as General Manager of Gas Marketing from 1996
to 1997. He joined the Company in 1995 as a Gas Marketing Analyst. Prior to
joining Belden & Blake, Mr. Clark held various management positions with Quaker
State Corporation from 1978 to 1995. He has 20 years of experience in the oil
and gas industry . Mr. Clark received his BA degree in Mathematics and Economics
from Ohio Wesleyan University. His professional affiliations include the Ohio
Oil and Gas Association, the Independent Oil and Gas Association of West
Virginia and the Pennsylvania Oil and Gas Association.
JAMES C. EWING has been Vice President of Human Resources for the
Company since 1997. He previously served as Human Resources Manager. Mr. Ewing
joined Belden & Blake in April of 1986 and has 12 years of experience in the oil
and gas industry and more than 20 years of experience in the Human Resource
field. Prior to joining Belden & Blake, he was the Director of Personnel for the
Union Metal Manufacturing Company from 1978 to 1986. Mr. Ewing holds a Bachelor
of Arts degree in Psychology from West Liberty State College. He is a member of
the Society for Human Resource Management. He is a founder and current member of
the Stark County Health Care Coalition; President of the Stark County Historical
Society; and, Chairman of the Business Advisory Board and adjunct faculty member
of Kent State University.
CHARLES P. FABER has been Vice President of Corporate Development for
the Company since 1993. He previously served as Senior Vice President of Capital
Markets from 1988 to 1993. Prior to joining Belden & Blake, Mr. Faber was
employed as Senior Vice President of Marketing for Heritage Asset Management
from 1986 to 1988. From 1983 to 1986 he served as President and Chief Executive
Officer of Samson Properties, Incorporated. Mr. Faber holds a BA degree in
Marketing and an MBA in Finance from the University of Wisconsin where he
graduated with honors. He is a member of the Independent Petroleum Association
of America and the Ohio Oil and Gas Association.
33
<PAGE> 35
ROBERT W. PESHEK has served as Vice President of Finance for the
Company since 1997. Previously, he served as Corporate Controller and Tax
Manager from 1994 to 1997. Prior to joining Belden & Blake, 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,
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.
DEAN A. SWIFT has served as Vice President, Assistant General Counsel
and Assistant Secretary of the Company since 1989. He served as Assistant
General Counsel of the Company from 1981 to 1989. From 1978 to 1981 he was
associated with the law firm of Hahn, Loeser and Parks in Cleveland, Ohio. Mr.
Swift received a BA degree from the University of the South and a JD degree from
the University of Virginia. He is a member of the Stark County, Ohio State and
American Bar Associations.
HENRY S. BELDEN IV served as Chairman and Chief Executive Officer of
the Company from 1982 to 1997. He resigned as Chairman and Chief Executive
Officer upon the Acquisition, and was appointed to serve on the Board of
Directors upon consummation of the Acquisition. Mr. Belden has been involved in
oil and gas production since 1955 and associated with Belden & Blake since 1967.
Prior to joining Belden & Blake, he was employed by Ashland Oil & Refining
Company and Halliburton Services, Incorporated. Mr. Belden attended Florida
State University and the University of Akron and is a member of the 25-Year Club
of the Petroleum Industry and the Board of Trustees of the Ohio Oil and Gas
Association. He is also a member of the Regional Advisory Board of the
Independent Petroleum Association of America and a director and a member of the
Executive Committee of the Pennsylvania Grade Crude Oil Association. He is a
member of the Interstate Oil Compact Commission. Other professional memberships
include the World Business Council and the Association of Ohio Commodores. He is
a director of KeyBank-Canton District and Phoenix Packaging Corporation.
LAWRENCE W. KELLNER has been Executive Vice President and Chief
Financial Officer of Continental Airlines, Inc. since November 1996.
Previously, he served as Senior Vice President and Chief Financial Officer at
Continental from June 1995 to November 1996. Prior to joining Continental, he
was Executive Vice President and Chief Financial Officer of American Savings
Bank, F.A. from November 1992 to May 1995. Mr. Kellner graduated magna cum
laude with a Bachelor of Science, Business Administration degree from the
University of South Carolina.
MAX L. MARDICK was President and Chief Operating Office of the Company
from 1990 to 1997, a director from 1992 to 1997 and a director of predecessor
companies from 1988 to 1992. He resigned as President and Chief Operating
Officer upon consummation of the Acquisition and was appointed to serve on the
Board of Directors upon consummation of the Acquisition. He previously served as
Executive Vice President and Chief Operating Officer from 1988 to 1990. Mr.
Mardick is a Petroleum Engineer with more than 35 years of experience in
domestic and international production, engineering, drilling operations and
property evaluation. Prior to joining Belden & Blake, he was employed for more
than 30 years by Shell Oil Company in various engineering, supervisory and
senior management positions, including: Manager, Property Acquisitions and
Business Development (1986-1988); Production Manager for Shell's Onshore and
Eastern Divisions (1981-1986); Production Manager of Shell's Rocky Mountain
Division (1980-1981); Operations Manager (1977-1980); and Engineering Manager
(1975-1977). Mr. Mardick holds a BS degree in Petroleum Engineering from the
University of Kansas. He is a member of the Society of Petroleum Engineers and
the Ohio Oil and Gas Association. He has served as Vice Chairman of the
Alabama-Mississippi section of the Mid-Continent Oil and Gas Association.
34
<PAGE> 36
WILLIAM S. PRICE, III, who became a director upon consummation of the
Acquisition, was a founding partner of Texas Pacific Group in 1993. Prior to
forming Texas Pacific Group, Mr. Price was Vice President of Strategic Planning
and Business Development for G.E. Capital, and from 1985 to 1991 he was employed
by the management consulting firm of Bain & Company, attaining partnership
status and acting as co-head of the Financial Services Practice. Mr. Price is a
1978 graduate of Stanford University and received a JD degree from the Boalt
Hall School of Law at the University of California, Berkeley. Mr. Price serves
on the Boards of Directors of AerFi Group plc, Beringer Wine Estates Holdings,
Inc., Continental Airlines, Inc., Denbury Resources, Inc., Favorite Brands
International, Inc., Vivra Specialty Partners, Inc. and Zilog, Inc.
GARETH ROBERTS is President, Chief Executive Officer and a Director of
Denbury Resources, Inc. ("Denbury"), and is the founder of the operating
subsidiary of Denbury, which was founded in April 1990. Mr. Roberts has 25
years of experience in the exploration and development of oil and natural 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 in Geology and
Geophysics from St. Edmund Hall, Oxford University.
DAVID M. STANTON, who became a director upon consummation of the
Acquisition, is a partner of Texas Pacific Group. From 1991 until he joined
Texas Pacific Group in 1994, Mr. Stanton was a venture capitalist with Trinity
Ventures, where he specialized in information technology, software and
telecommunications investing. Mr. Stanton earned a BS degree in Chemical
Engineering from Stanford University and received an MBA from the Stanford
Graduate School of Business. Mr. Stanton serves on the Boards of Directors of
Denbury Resources, Inc., Globespan Semiconductor, Inc., GT Com and Paradyne
Corp.
35
<PAGE> 37
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, 1998, 1997 and 1996 of the Company's Chief Executive Officer and its other
four most highly compensated executive officers.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
Long-Term
Compensation
Awards
Annual Compensation ----------------
---------------------------------------------- No. of Shares
Name and Other Annual Underlying All Other
Principal Position Year Salary Bonus Compensation Options/SARs (1) Compensation(2)
- ------------------ ---- ------ ----- ------------ ---------------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Ronald L. Clements 1998 $ 318,462 $ 11,354 $ -- -- $ 18,840
Chief Executive Officer 1997 239,154 84,390 -- 137,366 14,625
1996 171,173 66,303 4,000 20,000 11,342
Ronald E. Huff 1998 265,385 9,462 -- -- 17,662
President and Chief 1997 208,646 83,192 -- 137,366 13,767
Financial Officer 1996 166,462 66,175 -- 20,000 11,550
Joseph M. Vitale 1998 186,493 52,525 -- -- 14,248
Senior Vice President 1997 168,800 66,627 -- 54,946 11,863
Legal, General Counsel 1996 162,069 66,020 -- 20,000 10,078
and Secretary
Tommy L. Knowles 1998 175,158 6,244 -- -- 14,444
Senior Vice President 1997 167,154 46,563 -- 54,946 72,009 (3)
of Exploration and 1996 141,923 12,772 -- 20,000 57,041 (4)
Production
Leo A. Schrider 1998 137,962 12,719 -- -- 11,669
Senior Vice President 1997 128,504 20,065 -- 20,000 10,046
of Technical Development 1996 124,261 19,616 -- 12,500 8,416
</TABLE>
- ---------------------
(1) All awards prior to June 27, 1997 relate to options to purchase stock
in the predecessor company.
(2) Represents contributions of cash and Common Stock to the Company's
401(k) Profit Sharing Plan for the account of the named executive
officers.
(3) Includes stock grants amounting to $60,803.
(4) Includes stock grants amounting to $17,500 and moving expenses of
$34,269.
36
<PAGE> 38
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION/SAR VALUE
<TABLE>
<CAPTION>
Value of Unexercised
Number of Unexercised In-the Money
Options/SARs at FY-End Options/SARs at FY-End
Shares ---------------------------- ------------------------------
Acquired Value
Name on Exercise (1) Realized Exercisable Unexercisable Exercisable Unexercisable
---- --------------- -------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Ronald L. Clements -- -- 82,681 85,853 $128,724 --
Ronald E. Huff -- -- 82,681 85,853 128,724 --
Joseph M. Vitale -- -- 13,737 41,209 -- --
Tommy L. Knowles -- -- 13,737 41,209 -- --
Leo A. Schrider -- -- 5,000 15,000 -- --
</TABLE>
(1) There were no options exercised in 1998.
COMPENSATION OF DIRECTORS
The outside directors of the Company are compensated for their services
at $7,500 per quarter. Directors employed by the Company or TPG are not
compensated for their services.
EMPLOYMENT AND SEVERANCE AGREEMENTS
The Company has severance agreements with Messrs. Clements, Huff and
Vitale which entitle each of them to receive a lump sum severance payment equal
to 300% of the sum of (i) his respective annual base salary at the highest rate
in effect for any period prior to his employment termination plus (ii) his
highest annual bonus and incentive compensation during the three-year period
preceding a change in control, in the event of the termination of his employment
by the Company other than for "cause" (as defined therein) or his resignation in
response to a substantial reduction in responsibilities, authority, position,
compensation or location of his place of work prior to June 27, 2000. In
addition, each of them would be entitled to receive an additional payment
sufficient to cover any excise tax imposed by Section 4999 of the Code on the
severance payments or other payment considered "contingent on a change in
ownership or control" of the Company within the meaning of Section 280G of the
Code.
Messrs. Clements and Huff each entered into employment agreements dated
as of June 27, 1997 (the "Employment Agreements") providing for their employment
as Chief Executive Officer and President, respectively, of the Company. The
Employment Agreements provide for an annual base salary of not less than
$300,000 payable to Mr. Clements and $250,000 payable to Mr. Huff. Messrs.
Clements and Huff will each be entitled to earn an annual bonus of up to 50% of
his annual base salary based on the attainment of certain goals to be set by the
Company's Board of Directors. Each of Messrs. Clements and Huff agreed to
continue to hold, and not surrender, certain stock options previously granted to
him under the Company's Stock Option Plan, thereby foregoing the right to
receive $334,220 each in cash upon the surrender of such options on consummation
of the Acquisition. The Employment Agreements provide for the granting to each
of Messrs. Clements and Huff of additional options to purchase shares of common
stock of the Company constituting 1.25% of the outstanding common stock (on a
fully-diluted basis) at an option price equivalent to the price paid by TPG in
connection with the Acquisition. The options will vest over a four year period,
with one-fourth (1/4) vesting one year after the date of grant and
37
<PAGE> 39
the balance at the rate of one-twelfth (1/12) at the end of each quarter
thereafter during the continuation of employment with the Company. The
Employment Agreements provide for certain call options and rights of first
refusal in connection with the shares of common stock obtainable upon the
exercise of stock options.
The Employment Agreements provide that Messrs. Clements and Huff will
be entitled to employee welfare and retirement benefits substantially comparable
to those presently provided by the Company and to any other employee benefits
later made available to senior executive management of the Company.
The Employment Agreements further provide that the existing severance
agreements that Messrs. Clements and Huff have with the Company will remain in
force and upon the expiration thereof will be replaced by new severance
agreements providing substantially the same benefits.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During 1998, the Compensation and Organizational Committee of the Board
of Directors consisted of William S. Price, III, Henry S. Belden IV and Gareth
Roberts, all of whom are outside directors. No executive officer of the Company
was a director or member of the compensation committee of any entity of which a
member of the Company's board of directors or its Compensation and
Organizational Committee was or is an executive officer.
38
<PAGE> 40
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The following table sets forth certain information as of February 28,
1999 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:
<TABLE>
<CAPTION>
FIVE PERCENT SHAREHOLDERS NUMBER OF SHARES PERCENTAGE OF SHARES
------------------------- ---------------- --------------------
<S> <C> <C>
TPG Advisors II, Inc. 9,353,038(1) 88.2%
201 Main Street, Suite 2420
Fort Worth, Texas 76102
State Treasurer of the State of Michigan, 554,376 5.2%
Custodian of the Public School Employees'
Retirement System, State Employees Retirement
System, Michigan State Police Retirement System
and Michigan Judges Retirement System
OFFICERS AND DIRECTORS
----------------------
William S. Price, III 9,353,038(1) 88.2%
Henry S. Belden IV 63,360(2) *
Ronald L. Clements 91,265(2) *
Ronald E. Huff 91,265(2) *
Lawrence W. Kellner -0- -0-
Max L. Mardick 39,387(2) *
Tommy L. Knowles 13,737(2) *
Gareth Roberts -0- -0-
David M. Stanton -0- -0-
Leo A. Schrider 5,000(2) *
Joseph M. Vitale 13,737(2) *
All directors and executive
officers (17) as a group 9,702,039 91.4%
</TABLE>
*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 II, 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.
39
<PAGE> 41
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In connection with the Acquisition, 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 Acquisition as compensation for its services as financial
advisor in connection with the Acquisition. 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.
In management's opinion, the fees provided for under the Transaction Advisory
Agreement reasonably reflect the benefits received and to be received by the
Company.
Messrs. Belden and Mardick have each entered into non-competition
agreements with the Company dated March 27, 1997 (the "Non-Competition
Agreements"), which became effective contemporaneously with consummation of the
Acquisition. Pursuant to the terms of the Non-Competition Agreements, Messrs.
Belden and Mardick have each agreed, for a period of three (3) years from June
27, 1997 that he will not, in any county in the United States in which the
Company does business, directly or indirectly, either for himself or as a member
of a partnership or as a shareholder, investor, agent, associate or consultant
engage in any business in which the Company is engaged immediately prior to June
27, 1997. Messrs. Belden and Mardick have each further agreed that he will not,
directly or indirectly, make any misleading or untrue statement that disparages
or would have the effect of disparaging the Company or any of its affiliates or
employees or of adversely affecting the reputation, business or credit rating of
the Company or any of its affiliates or employees, and that, for a period of
three years from June 27, 1997, he will not, directly or indirectly, interfere
with, or take any action that would have the effect of interfering with, the
contractual and other relationships between the Company or any of its affiliates
and any of its or their employees, customers or suppliers. In consideration of
such agreements, Mr. Belden will receive $2,400,616.44 and Mr. Mardick will
receive $983,711.16 in each case payable in 36 monthly installments.
40
<PAGE> 42
PART IV
Item 14. 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
<TABLE>
<CAPTION>
No. Description
- --- -----------
<S> <C>
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)
</TABLE>
41
<PAGE> 43
<TABLE>
<S> <C>
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 Credit Agreement dated as of June 27, 1997 by and among the Company, each of
the Lenders named therein and The Chase Manhattan Bank, as Agent
--incorporated by reference to Exhibit 10.1 to the Company's Registration
Statement on Form S-4 (Registration No. 333-33407)
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 Employment Agreement dated as of June 27, 1997 by and between the Company and
Ronald L. Clements --incorporated by reference to Exhibit 10.3 to the
Company's Registration Statement on Form S-4 (Registration No. 333-33407)
10.4 Employment Agreement dated as of June 27, 1997 by and between the Company and
Ronald E. Huff --incorporated by reference to Exhibit 10.4 to the Company's
Registration Statement on Form S-4 (Registration No. 333-33407)
10.5 Belden & Blake Corporation 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)
10.6 Form of Severance Agreement between the Company and the following officers:
Ronald E. Huff, Ronald L. Clements and Joseph M. Vitale-- incorporated by
reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for
the quarter ended September 30, 1996
10.7 Form of Severance Agreement between the Company and the following officers
and managerial personnel: Dennis D. Belden, James C. Ewing, Charles P. Faber,
Tommy L. Knowles, Donald A. Rutishauser, L. H. Sawatsky, Leo A. Schrider and
Dean A. Swift--incorporated by reference to Exhibit 10.4 to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 1996
10.8 Severance Pay Plan for Key Employees of Belden & Blake
Corporation--incorporated by reference to Exhibit 10.5 to the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 1996
10.9(a) Stock Option Plan of the Company--incorporated by reference to Exhibit 10.7 to
the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
10.9(b) Stock Option Plan of the Company (as amended)--incorporated by reference to
Exhibit 4.1 to the Company's Registration Statement on Form S-8 (Registration
No. 33-62785)
21* Subsidiaries of the Registrant
23* Consent of Ernst & Young LLP
27* Financial Data Schedule
</TABLE>
*Filed herewith
42
<PAGE> 44
(b) Reports on Form 8-K
No reports on Form 8-K were filed by the Company during the last
quarter of the year covered by this report.
(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 14(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.
43
<PAGE> 45
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
April 14, 1999 By: /s/ Ronald L. Clements
- --------------------------------- --------------------------------
Date Ronald L. Clements
Chief Executive Officer
and Director
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.
<TABLE>
<S> <C> <C>
/s/ Ronald L. Clements Chief Executive Officer April 14, 1999
- ------------------------------ and Director --------------
Ronald L. Clements (Principal Executive Officer) Date
/s/ Ronald E. Huff President, Chief Financial April 14, 1999
- ------------------------------ Officer and Director --------------
Ronald E. Huff (Principal Financial and Date
Accounting Officer)
/s/ Joseph M. Vitale Senior Vice President Legal, April 14, 1999
- ------------------------------ General Counsel, Secretary --------------
Joseph M. Vitale and Director Date
/s/ Henry S. Belden IV * Director April 14, 1999
- ------------------------------ --------------
Henry S. Belden IV Date
/s/ Lawrence W. Kellner * Director April 14, 1999
- ------------------------------ --------------
Lawrence W. Kellner Date
/s/ Max L. Mardick * Director April 14, 1999
- ------------------------------ --------------
Max L. Mardick Date
/s/ William S. Price, III * Director April 14, 1999
- ------------------------------ --------------
William S. Price, III Date
</TABLE>
44
<PAGE> 46
<TABLE>
<S> <C> <C>
/s/ Gareth Roberts * Director April 14, 1999
- ------------------------------ --------------
Gareth Roberts Date
/s/ David M. Stanton * Director April 14, 1999
- ------------------------------ --------------
David M. Stanton Date
*By: /s/ Joseph M. Vitale April 14, 1999
-------------------------- --------------
Attorney-in-Fact Date
</TABLE>
45
<PAGE> 47
BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES
ITEM 14(a) (1) AND (2)
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Auditors ....................................................................... F-2
Consolidated Balance Sheets as of December 31, 1998 and 1997 (Successor Company) ..................... F-3
Consolidated Statements of Operations:
Year ended December 31, 1998 (Successor Company)
Six months ended December 31, 1997 (Successor Company)
Six months ended June 30, 1997 (Predecessor Company)
Year ended December 31, 1996 (Predecessor Company) ................................................ F-4
Consolidated Statements of Shareholders' Equity (Deficit):
Year ended December 31, 1998 (Successor Company)
Six months ended December 31, 1997 (Successor Company)
Six months ended June 30, 1997 (Predecessor Company)
Year ended December 31, 1996 (Predecessor Company) ................................................ F-5
Consolidated Statements of Cash Flows:
Year ended December 31, 1998 (Successor Company)
Six months ended December 31, 1997 (Successor Company)
Six months ended June 30, 1997 (Predecessor Company)
Year ended December 31, 1996 (Predecessor Company) ................................................ F-6
Notes to Consolidated Financial Statements ........................................................... F-7
</TABLE>
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
<PAGE> 48
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 ("Successor Company") as of December 31, 1998 and 1997, and the
related consolidated statements of operations, shareholders' equity (deficit)
and cash flows for the year ended December 31, 1998 and the six month period
ended December 31, 1997 ("Successor periods"). We have also audited the
accompanying consolidated statements of operations, shareholders' equity
(deficit) and cash flows of Belden & Blake Corporation ("Predecessor Company")
for the six month period ended June 30, 1997 and the year ended December 31,
1996 ("Predecessor periods"). These financial statements are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Belden & Blake
Corporation at December 31, 1998 and 1997 and the consolidated results of their
operations and their cash flows for the Successor periods and the Predecessor
periods in conformity with generally accepted accounting principles.
ERNST & YOUNG LLP
Cleveland, Ohio
April 13, 1999
F-2
<PAGE> 49
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1998 1997
--------- ---------
<S> <C> <C>
ASSETS
- ------
CURRENT ASSETS
Cash and cash equivalents $ 10,691 $ 6,552
Accounts receivable, net 33,204 35,743
Inventories 9,200 9,614
Deferred income taxes 2,449 2,702
Other current assets 3,384 4,052
--------- ---------
TOTAL CURRENT ASSETS 58,928 58,663
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 535,837 499,864
Gas gathering systems 22,008 20,713
Land, buildings, machinery and equipment 28,551 25,602
--------- ---------
586,396 546,179
Less accumulated depreciation, depletion and amortization 246,689 31,036
--------- ---------
PROPERTY AND EQUIPMENT, NET 339,707 515,143
OTHER ASSETS 19,970 25,514
--------- ---------
$ 418,605 $ 599,320
========= =========
LIABILITIES AND SHAREHOLDERS' (DEFICIT) EQUITY
- ----------------------------------------------
CURRENT LIABILITIES
Accounts payable $ 6,458 $ 9,078
Accrued expenses 29,373 28,442
Current portion of long-term liabilities 29,365 1,297
--------- ---------
TOTAL CURRENT LIABILITIES 65,196 38,817
LONG-TERM LIABILITIES
Bank and other long-term debt 126,178 126,269
Senior subordinated notes 225,000 225,000
Other 3,204 4,380
--------- ---------
354,382 355,649
DEFERRED INCOME TAXES 32,041 107,996
SHAREHOLDERS' (DEFICIT) EQUITY
Common stock without par value; $.10 stated value per share; authorized
58,000,000 shares; issued
and outstanding 10,110,915 and 10,000,000 shares 1,011 1,000
Paid in capital 107,897 107,230
Deficit (141,922) (11,372)
--------- ---------
TOTAL SHAREHOLDERS' (DEFICIT) EQUITY (33,014) 96,858
--------- ---------
$ 418,605 $ 599,320
========= =========
</TABLE>
See accompanying notes.
F-3
<PAGE> 50
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
<TABLE>
<CAPTION>
SUCCESSOR COMPANY | PREDECESSOR COMPANY
================================ | ==================================
YEAR SIX MONTHS | SIX MONTHS YEAR
ENDED ENDED | ENDED ENDED
DECEMBER 31, DECEMBER 31, | JUNE 30, DECEMBER 31,
1998 1997 | 1997 1996
------------- ------------- | ----------- ------------
<S> <C> <C> | <C> <C>
REVENUES |
Oil and gas sales $ 87,055 $ 44,165 | $ 41,591 $ 79,491
Gas marketing and gathering 40,025 22,714 | 21,657 44,527
Oilfield sales and service 23,333 15,541 | 14,665 25,517
Other 4,426 1,706 | 1,484 3,700
--------- --------- | ---------- ---------
154,839 84,126 | 79,397 153,235
EXPENSES |
Production expense 23,739 11,338 | 10,158 18,098
Production taxes 2,986 1,525 | 1,647 3,168
Cost of gas and gathering expense 33,588 19,444 | 18,340 37,556
Oilfield sales and service 23,225 14,085 | 13,936 23,142
Exploration expense 9,982 5,980 | 4,380 6,064
General and administrative expense 4,909 1,813 | 2,445 4,573
Depreciation, depletion and amortization 68,488 31,694 | 15,366 29,752
Impairment of oil and gas properties |
and other assets 160,690 |
Franchise, property and other taxes 1,084 967 | 908 1,739
--------- --------- | --------- ---------
328,691 86,846 | 67,180 124,092
--------- --------- | --------- ---------
OPERATING (LOSS) INCOME (173,852) (2,720) | 12,217 29,143
|
Interest expense 32,903 15,417 | 3,715 7,383
Transaction-related expenses | 16,758
--------- --------- | --------- ---------
32,903 15,417 | 20,473 7,383
--------- --------- | --------- ---------
(LOSS) INCOME FROM CONTINUING |
OPERATIONS BEFORE INCOME TAXES (206,755) (18,137) | (8,256) 21,760
(Benefit) provision for income taxes (76,205) (6,765) | 1,617 6,566
--------- --------- | --------- ---------
(LOSS) INCOME FROM CONTINUING OPERATIONS (130,550) (11,372) | (9,873) 15,194
LOSS FROM DISCONTINUED OPERATIONS | (439)
--------- --------- | --------- ---------
NET (LOSS) INCOME $(130,550) $ (11,372) | $ (9,873) $ 14,755
========= ========= | ========= =========
</TABLE>
See accompanying notes.
F-4
<PAGE> 51
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT)
(IN THOUSANDS)
<TABLE>
<CAPTION>
SUCCESSOR COMPANY PREDECESSOR COMPANY
------------------- -------------------
COMMON COMMON COMMON COMMON PREFERRED PAID IN
SHARES STOCK SHARES STOCK STOCK CAPITAL
------ -------- ------ ------- --------- -------
<S> <C> <C> <C> <C> <C> <C>
PREDECESSOR COMPANY:
JANUARY 1, 1996 -- $ -- 11,137 $ 1,114 $ 2,400 $ 126,063
Net income
Preferred stock dividend
Stock options exercised and
related tax benefit 3 -- 47
Employee stock bonus 26 3 418
Restricted stock activity 4 -- 263
Conversion of debentures 62 6 1,244
------ -------- ------ ------- ------- ---------
DECEMBER 31, 1996 -- -- 11,232 1,123 2,400 128,035
Net loss
Preferred stock redeemed (2,400)
Preferred stock dividend
Subordinated debentures
converted to common stock 275 27 5,523
Stock options exercised and surrendered
and related tax benefit 1 -- 1,596
Employee stock bonus 36 4 926
Restricted stock activity 17
Redemption of common stock (11,544) (1,154) (136,097)
Sale of common stock 10,000 1,000 107,230
SUCCESSOR COMPANY:
------ -------- ------ ------- ------- ---------
JUNE 30, 1997 10,000 1,000 -- -- -- 107,230
Net loss
------ -------- ------ ------- ------- ---------
DECEMBER 31, 1997 10,000 1,000 -- -- -- 107,230
Employee stock bonus 111 11 667
Net loss
------ -------- ------ ------- ------- ---------
DECEMBER 31, 1998 10,111 $ 1,011 -- $ -- $ -- $ 107,897
====== ======== ====== ======= ======= =========
<CAPTION>
RETAINED UNEARNED TOTAL
EARNINGS RESTRICTED EQUITY
(DEFICIT) STOCK (DEFICIT)
----------- ---------- ---------
<S> <C> <C> <C>
PREDECESSOR COMPANY:
JANUARY 1, 1996 $ 12,820 $ (106) $ 142,291
Net income 14,755 14,755
Preferred stock dividend (180) (180)
Stock options exercised and
related tax benefit 47
Employee stock bonus 421
Restricted stock activity 71 334
Conversion of debentures 1,250
----------- ---------- ---------
DECEMBER 31, 1996 27,395 (35) 158,918
Net loss (9,873) (9,873)
Preferred stock redeemed (2,400)
Preferred stock dividend (45) (45)
Subordinated debentures
converted to common stock 5,550
Stock options exercised and surrendered
and related tax benefit 1,596
Employee stock bonus 930
Restricted stock activity 35 52
Redemption of common stock (17,477) (154,728)
Sale of common stock 108,230
SUCCESSOR COMPANY:
----------- ---------- ---------
JUNE 30, 1997 -- -- 108,230
Net loss (11,372) (11,372)
----------- ---------- ---------
DECEMBER 31, 1997 (11,372) -- 96,858
Employee stock bonus 678
Net loss (130,550) (130,550)
----------- ---------- ---------
DECEMBER 31, 1998 $ (141,922) $ -- $ (33,014)
=========== ========== =========
</TABLE>
See accompanying notes.
F-5
<PAGE> 52
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
SUCCESSOR COMPANY | PREDECESSOR COMPANY
-------------------------- | ---------------------------
YEAR SIX MONTHS | SIX MONTHS YEAR
ENDED ENDED | ENDED ENDED
DECEMBER 31, DECEMBER 31, | JUNE 30, DECEMBER 31,
1998 1997 | 1997 1996
------------ ------------ | ---------- ------------
<S> <C> <C> | <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES: |
Net (loss) income $(130,550) $ (11,372) | $ (9,873) $ 14,755
Adjustments to reconcile net (loss) income to net cash |
provided by operating activities: |
Depreciation, depletion and amortization 68,488 31,694 | 15,366 29,752
Impairment of oil and gas properties and other assets 160,690 -- | -- --
Transaction-related expenses -- -- | 15,903 --
Loss on disposal of property and equipment 100 51 | 356 534
Deferred income taxes (75,702) (6,379) | 3,125 4,232
Deferred compensation and stock grants 993 380 | 1,756 1,311
Change in operating assets and liabilities, net of effects of |
purchases of businesses: |
Accounts receivable and other operating assets 3,203 (5,280) | 1,237 (4,385)
Inventories (261) 597 | 112 (144)
Accounts payable and accrued expenses (1,689) (4,064) | 4,800 476
--------- --------- | --------- ---------
NET CASH PROVIDED BY OPERATING ACTIVITIES 25,272 5,627 | 32,782 46,531
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
Acquisition of businesses, net of cash acquired (11,827) (14,276) | (9,263) (4,543)
Proceeds from property and equipment disposals 4,082 785 | 704 2,227
Additions to property and equipment (38,165) (23,663) | (18,419) (37,074)
Increase in other assets (1,294) (274) | (9,496) (705)
--------- --------- | --------- ---------
NET CASH USED IN INVESTING ACTIVITIES (47,204) (37,428) | (36,474) (40,095)
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
Proceeds from revolving line of credit and long-term debt -- -- | 46,000 16,105
Proceeds from new credit agreement 44,000 24,020 | 104,000 --
Proceeds from senior subordinated notes -- -- | 225,000 --
Sale of common stock -- -- | 108,230 --
Repayment of long-term debt and other obligations (17,929) (2,989) | (140,325) (26,117)
Payment to shareholders and optionholders -- -- | (312,164) --
Transaction-related expenses -- -- | (15,903) --
Preferred stock redeemed -- -- | (2,400) --
Preferred stock dividends -- -- | (45) (180)
Proceeds from sale of common stock and stock options -- -- | 15 40
--------- --------- | --------- ---------
NET CASH PROVIDED BY (USED IN) |
FINANCING ACTIVITIES 26,071 21,031 | 12,408 (10,152)
--------- --------- | --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 4,139 (10,770) | 8,716 (3,716)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 6,552 17,322 | 8,606 12,322
--------- --------- | --------- ---------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 10,691 $ 6,552 | $ 17,322 $ 8,606
========= ========= | ========= =========
</TABLE>
See accompanying notes.
F-6
<PAGE> 53
BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) MERGER
On March 27, 1997, the Company signed a definitive merger agreement
with TPG Partners II, L.P. ("TPG"), a private investment partnership, pursuant
to which TPG and certain other investors acquired the Company in an all-cash
transaction valued at $440 million. Under the terms of the agreement, TPG and
such investors paid $27 per share for all common shares outstanding plus an
additional amount to redeem certain stock options held by directors and
employees. The transaction was completed on June 27, 1997 and for financial
reporting purposes has been accounted for as a purchase effective June 30, 1997.
The acquisition resulted in a new basis of accounting reflecting estimated fair
values for assets and liabilities at that date. Accordingly, the financial
statements for the periods subsequent to June 30, 1997 are presented on the
Company's new basis of accounting, while the results of operations for the
periods ended June 30, 1997 and December 31, 1996 reflect the historical results
of the predecessor company. A vertical black line is presented to separate the
financial statements of the predecessor and successor companies.
The following table presents the actual results of operations for the
year ended December 31, 1998 and the unaudited pro forma results of operations
for the years ended December 31, 1997 and 1996 as if the merger occurred at the
beginning of 1996 (in thousands):
<TABLE>
<CAPTION>
Actual Pro Forma (unaudited)
--------- -----------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
Total revenues $ 154,839 $ 163,523 $ 153,235
Loss from continuing operations (130,550) (19,970) (14,701)
</TABLE>
The unaudited pro forma information presented above assumes the
transaction-related expenses were incurred prior to the period presented and
does not purport to be indicative of the results that actually would have been
obtained if the merger had been consummated at the beginning of 1996 and is not
intended to be a projection of future results or trends.
In connection with the merger, the Company entered into a Transaction
Advisory Agreement with TPG pursuant to which TPG received a cash financial
advisory fee of $5.0 million for services as financial advisor in connection
with the merger. The fee is included in the $16.8 million of transaction-related
expenses. TPG 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) entered into by
the successor company.
Certain former officers have entered into non-competition agreements
with the Company dated March 27, 1997, which became effective contemporaneously
with consummation of the merger. These agreements have a term of 36 months and
had a total value of $3.0 million at June 27, 1997. The obligation for these
agreements is included in the balance sheet.
(2) BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
BUSINESS
The Company operates primarily in the oil and gas industry. The
Company's principal business is natural gas marketing and gathering and the
production, acquisition and development of oil and gas
F-7
<PAGE> 54
reserves. Sales of oil are ultimately made to refineries. Sales of gas are
ultimately made to industrial and commercial consumers in Ohio, Michigan, West
Virginia, Pennsylvania, New York and Kentucky and to gas utilities. The Company
also provides oilfield services and is a distributor of a broad range of
oilfield equipment and supplies. Its customers include other independent oil and
gas companies, dealers and operators throughout Ohio, Michigan, West Virginia,
Pennsylvania and New York. The price of oil and 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.
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 debt instruments 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, dry holes, expired leases and delay rentals, 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. 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. During 1998, the Company recorded a $5.8 million impairment
which wrote-down unproved oil and gas properties to their estimated fair value.
F-8
<PAGE> 55
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 charged to income
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 carrying value of the asset. In performing the review
for long-lived asset recoverability during 1998, the Company recorded $148.0
million and $6.9 million of impairments which wrote-down producing properties
and other assets, respectively, 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.
INTANGIBLE ASSETS
Intangible assets totaling $16 million at December 31, 1998, include
deferred debt issuance costs, goodwill and other intangible assets and are being
amortized over 25 years or the shorter of their respective terms.
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 sales and service revenues are recognized when the goods or services
have been provided.
INCOME TAXES
The Company uses the liability method of accounting for income taxes.
Deferred income taxes are provided for temporary differences between the
carrying amounts of assets and liabilities for financial reporting purposes and
the amounts used for income tax purposes. Deferred income taxes also are
recognized for operating losses that are available to offset future taxable
income and tax credits that are available to offset future federal income taxes.
STOCK-BASED COMPENSATION
The Company measures expense associated with stock-based compensation
under the provisions of Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees."
Belden & Blake Corporation common stock held in the 401k plan is
subject to variable plan accounting. The changes in share value are reported as
adjustments to compensation expense. The reduction in share value in 1998
resulted in a reduction in compensation expense of $403,000.
(3) ACCOUNTING CHANGES
During 1998, the Company adopted Statement of Financial Accounting
Standards No. (SFAS) 130, "Reporting Comprehensive Income," Statement of
Financial Accounting Standards No. (SFAS) 131, "Disclosures about Segments of an
Enterprise and Related Information" and Statement of Position (SOP) 98-1,
"Accounting for the Costs of Computer Software Developed or Obtained for
Internal Use."
F-9
<PAGE> 56
SFAS 130 establishes standards for reporting and displaying
comprehensive income and its components in general-purpose financial statements.
This pronouncement had no effect on the Company's financial statements.
SFAS 131 establishes standards for public business enterprises for
reporting information about operating segments in annual financial statements
and requires that such enterprises report selected information about operating
segments in interim financial reports issued to shareholders. This Statement
also establishes standards for related disclosures about products and services,
geographic areas, and major customers. See Note 18.
SOP 98-1 requires companies to capitalize certain qualified costs
incurred in connection with internal-use software development projects. Adoption
of this standard was not material to the Company's financial position, operating
results or cash flows.
(4) NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
In June 1998, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. (SFAS) 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS 133 establishes accounting and
reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. SFAS 133 is
effective for fiscal years beginning after June 15, 1999. On adoption, the
provisions of SFAS 133 must be applied prospectively as the cumulative effect of
an accounting change. The Company has not determined the impact that SFAS 133
will have on its financial statements and has not determined the timing of or
method of adoption of SFAS 133.
(5) ACQUISITIONS
The following acquisitions were accounted for as purchase business
combinations. Accordingly, the results of operations of the acquired businesses
are included in the Company's consolidated statements of operations from the
date of the respective acquisitions.
During 1998, the Company acquired working interests in oil and gas
wells in Ohio, West Virginia, Michigan and New York for approximately
$7.6 million. Estimated proved developed reserves associated with the wells
totaled 8.8 Bcfe net to the Company's interest at the time of acquisition. The
Company also acquired undeveloped properties and other assets for $4.2 million.
On March 19, 1998, the Company entered into an agreement in principle
with FirstEnergy Corp. ("FirstEnergy") to form an equally-owned joint venture to
be named FE Holdings L.L.C. ("FE Holdings") to engage in the exploration,
development, production, transportation and marketing of natural gas. Formation
of the joint venture was subject to the negotiation and execution of a
definitive joint venture agreement. The Company was unable to reach agreement
with FirstEnergy regarding certain terms of the joint venture agreement and in
June 1998, the Company determined it would not participate in the proposed joint
venture. Costs of $372,000 related to the proposed formation of the joint
venture and to due diligence associated with a proposed acquisition by FE
Holdings were written-off to general and administrative expense in 1998.
During 1997, the Company acquired working interests in oil and gas
wells in Ohio, Pennsylvania, West Virginia and Michigan for approximately $13.5
million for the successor company's six months ended December 31, 1997 and $7.8
million for the predecessor company's six months ended June 30, 1997. Estimated
proved developed reserves associated with the wells totaled 32.8 Bcf of natural
gas and 101,000 Bbls of oil net to the Company's interest at the time of the
acquisitions.
F-10
<PAGE> 57
During 1996, the Company acquired for approximately $4.1 million
working interests in 323 oil and gas wells in Ohio and Kentucky. Estimated
proved developed reserves associated with the wells totaled 6.0 Bcf of natural
gas and 205,000 Bbls of oil net to the Company's interest at July 1, 1996.
The pro forma effects of the 1998, 1997 (predecessor and successor
periods) and the 1996 acquisitions were not material.
(6) EXPANSION OF GAS MARKETING CAPABILITY
In July 1998, the Company began development of a major expansion of its
gas marketing capability, with the objective of substantially increasing the
number of industrial and commercial customers served, the volumes of gas sold
and future net operating margins from gas sales. The expansion includes the
selection and installation of systems and technology to enhance the efficiency
of the gas marketing operation.
Through December 31, 1998, the Company expensed $731,000 related to
this expansion project, which was included in "Cost of gas and gathering
expense" in the Consolidated Statements of Operations. The Company has adopted
SOP 98-1, and has capitalized $46,000 of certain internal costs associated with
the development of the systems. The Company has also capitalized $878,000 of
other external costs related to this expansion project. The majority of these
expenditures relate to consulting services associated with the selection of the
systems.
F-11
<PAGE> 58
(7) DETAILS OF BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1998 1997
--------- ---------
ACCOUNTS RECEIVABLE (IN THOUSANDS)
<S> <C> <C>
Accounts receivable $ 17,859 $ 20,234
Allowance for doubtful accounts (1,430) (948)
Oil and gas production receivable 16,182 15,959
Current portion of notes receivable 593 498
--------- ---------
$ 33,204 $ 35,743
========= =========
INVENTORIES
Oil $ 1,710 $ 2,429
Natural gas 974 387
Material, pipe and supplies 6,516 6,798
--------- ---------
$ 9,200 $ 9,614
========= =========
PROPERTY AND EQUIPMENT, GROSS
OIL AND GAS PROPERTIES
Producing properties $ 507,652 $ 466,491
Non-producing properties 7,040 12,792
Other 21,145 20,581
--------- ---------
$ 535,837 $ 499,864
========= =========
LAND, BUILDINGS, MACHINERY AND EQUIPMENT
Land, buildings and improvements $ 8,540 $ 8,530
Machinery and equipment 20,011 17,072
--------- ---------
$ 28,551 $ 25,602
========= =========
ACCRUED EXPENSES
Accrued expenses $ 12,796 $ 11,126
Accrued drilling and completion costs 4,217 3,736
Accrued income taxes 241 --
Ad valorem and other taxes 3,570 4,020
Compensation and related benefits 2,752 3,524
Undistributed production revenue 5,797 6,036
--------- ---------
$ 29,373 $ 28,442
========= =========
</TABLE>
(8) LONG-TERM DEBT
Long-term debt consists of the following (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1998 1997
-------- --------
<S> <C> <C>
Revolving line of credit $154,000 $126,000
Senior subordinated notes 225,000 225,000
Other 276 418
-------- --------
379,276 351,418
Less current portion 28,098 149
-------- --------
Long-term debt $351,178 $351,269
======== ========
</TABLE>
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 were
F-12
<PAGE> 59
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 June 15, 2002, at the redemption prices set
forth below plus, in each case, accrued and unpaid interest, if any, thereon.
<TABLE>
<CAPTION>
YEAR PERCENTAGE
---- ----------
<S> <C>
2002............................................................ 104.938%
2003............................................................ 103.292%
2004............................................................ 101.646%
2005 and thereafter............................................. 100.000%
</TABLE>
Prior to June 15, 2000, the Company may, at its option, on any one or
more occasions, redeem up to 40% of the original aggregate principal amount of
the notes at a redemption price equal to 109.875% of the principal amount, plus
accrued and unpaid interest, if any, on the redemption date, with all or a
portion of net proceeds of public sales of common stock of the Company; provided
that at least 60% of the original aggregate principal amount of the notes
remains outstanding immediately after the occurrence of such redemption; and
provided, further, that such redemption shall occur within 60 days of the date
of the closing of the related sale of common stock of the Company.
The indenture under which the subordinated notes were issued contains
certain covenants that limit the ability of the Company and its subsidiaries to
incur additional indebtedness and issue stock, pay dividends, make
distributions, make investments, make certain other restricted payments, enter
into certain transactions with affiliates, dispose of certain assets, incur
liens securing indebtedness of any kind other than permitted liens, and engage
in mergers and consolidations.
On June 27, 1997, the Company also entered into a senior revolving
credit agreement with several lenders. These lenders committed, subject to
compliance with the borrowing base, to provide the Company with revolving credit
loans of up to $200 million, of which $25 million will be available for the
issuance of letters of credit. The credit agreement is a senior revolving credit
facility which is secured by substantially all of the Company's assets. The
borrowing base is the sum of the Company's proved developed reserves, proved
developed non-producing reserves, proved undeveloped reserves and related
processing and gathering assets and other assets of the Company, adjusted by the
engineering committee of the bank in accordance with their standard oil and gas
lending practices. If less than 75% of the borrowing base is utilized, the
borrowing base will be re-determined annually. If more than 75% of the borrowing
base is utilized, the borrowing base will be re-determined semi-annually. The
Company's borrowing base at December 31, 1998 was $170 million. On January 15,
1999 the Company's borrowing base was redetermined at $126 million. The Company
had $154 million outstanding under this agreement at December 31, 1998 which
resulted in the Company having a borrowing base deficiency of $28 million. The
Company has agreed with the lenders, to reduce this deficiency by $14 million on
March 22, 1999 and by the remaining $14 million on May 10, 1999.
On March 22, 1999 the Company made a $14 million payment to reduce the
outstanding amount under the credit agreement to $140 million. The funds for the
payment were provided by internally
F-13
<PAGE> 60
generated cash flow and a term loan provided by Chase Manhattan Bank. This term
loan provided borrowings of $9 million and is due on September 22, 1999.
Interest is payable monthly at LIBOR plus 1.5%. The Company is in the process of
renegotiating its revolving credit facility with its lenders and expects to have
a new facility in place prior to May 10, 1999, when the second payment of $14
million is due. Should the Company not be successful in renegotiating an
acceptable facility, the Company expects to be able to meet its 1999 debt
service requirements through internally generated cash flow, the sale of
non-strategic assets and/or the use of instruments in financial futures markets.
The Company borrowed $104 million under the credit agreement in 1997 to
partially finance the acquisition of the Company by TPG; to repay certain
existing outstanding indebtedness of the Company and to pay certain fees and
expenses related to the transaction. The credit agreement will mature on June
27, 2002. Outstanding balances under the agreement incur interest at the
Company's choice of several indexed rates, the most favorable being 6.566% at
December 31, 1998.
The credit agreement contains a number of covenants that, among other
things, restricts the ability of the Company and its subsidiaries to dispose of
assets, incur additional indebtedness, prepay other indebtedness or amend
certain debt instruments, pay dividends, create liens on assets, enter into sale
and leaseback transactions, make investments, loans or advances, make
acquisitions, engage in mergers or consolidations, change the business conducted
by the Company or its subsidiaries, make capital expenditures or engage in
certain transactions with affiliates and otherwise restrict certain corporate
activities. In addition, under the credit agreement, the Company is required to
maintain specified financial ratios and tests, including minimum interest
coverage ratios and maximum leverage ratios. The agreement requires a minimum
working capital ratio of 1.00 to 1.00. As of December 31, 1998 the Company's
working capital ratio was .90 to 1.00. The Company and its lenders have agreed
to exclude the $28 million required reduction in outstanding borrowings from the
covenant requiring a specific working capital ratio. The ratio after excluding
the $28 million results in a working capital ratio of 1.58 to 1.00.
In connection with the senior subordinated notes and the credit
agreement, the Company allocated $9.5 million of fees paid to investment bankers
to deferred debt issuance costs.
The Company may enter into interest rate swaps to hedge the interest
rate exposure associated with the credit agreement, whereby a portion of the
Company's floating rate exposure would be exchanged for a fixed interest rate.
During October 1997, the Company entered into two interest rate swap
arrangements with a major financial institution covering $90 million of debt.
The Company swapped $40 million of floating three-month LIBOR +1.5% for a fixed
rate of 7.485% for three years, extendible at the institution's option for an
additional two years. The Company also swapped $50 million of floating
three-month LIBOR +1.5% for a fixed rate of 7.649% for five years. In June 1998
the Company entered into a third interest rate swap covering $50 million of
debt. The Company swapped $50 million of floating rate three-month LIBOR + 1.50%
for a fixed rate of 7.2825% for three years. The Company had no such derivative
financial instruments at December 31, 1996. Under the deferral method, gains and
losses on these instruments are deferred on the balance sheet and the interest
rate differential to be received or paid is recognized as an adjustment to
interest expense for the month hedged.
On April 3, 1997, the Company gave notice of redemption of all of the
outstanding 9.25% convertible subordinated debentures for 104% of face value.
Redemption of these debentures occurred June 10, 1997 when holders of the
debentures elected to convert them into 275,425 shares of common stock in the
predecessor company.
F-14
<PAGE> 61
At December 31, 1998, the aggregate long-term debt maturing in the next
five years is as follows: $28,098,000 (1999); $18,000 (2000); $18,000 (2001);
$126,018,000 (2002); $19,000 (2003); and $225,105,000 (2004 and thereafter).
(9) LEASES
The Company leases certain computer equipment, vehicles and office
space under noncancelable agreements with lease periods of one to five years.
Rent expense amounted to $2.2 million and $1.0 million for the successor
company's year ended December 31, 1998 and six months ended December 31, 1997,
respectively, and $1.0 million and $1.6 million for the predecessor company's
six months ended June 30, 1997 and the year ended December 31, 1996,
respectively. Future commitments under leasing arrangements were not significant
at December 31, 1998.
(10) SHAREHOLDERS' EQUITY
In November 1998 and 1997, the Company awarded 118,274 and 110,915
shares of successor company common stock, respectively, to employees as profit
sharing and bonuses. These shares were issued in each subsequent year.
On December 31, 1992, the Company issued 24,000 shares of Class II
Serial Preferred Stock with a stated value of $100 per share. In preference to
shares of predecessor company common stock, each share was entitled to
cumulative cash dividends of $7.50 per year, payable quarterly. The Preferred
Stock was subject to redemption at $100 per share at any time by the Company and
was convertible into predecessor company common stock, at the holder's election,
at any time after five years from the date of issuance at a conversion price of
$15.00 per predecessor company common share. Holders of the Preferred Stock were
entitled to one vote per preferred share. On March 31, 1997, the Company
redeemed all of the outstanding Class II Series A preferred stock for $2.4
million in cash.
In December 1996 the Company awarded 36,077 shares of predecessor
company common stock to employees as profit sharing and bonuses. These shares
were issued in 1997.
In November 1996, $1,250,000 of convertible subordinated debentures
were converted by the debenture holders at the rate of one share of the
Company's predecessor company common stock for each $20.15 of principal into
62,034 shares of predecessor company common stock.
(11) STOCK OPTION PLANS
In connection with the merger, certain executives of the predecessor
company had agreed that they would not exercise or surrender certain stock
options having an aggregate value of $1.8 million at June 27, 1997, based on the
intrinsic value of the options (the difference between the exercise price of the
options and a purchase price of $27 per share). These options were exchanged for
165,083 in new stock options of the successor company based on the intrinsic
value of the predecessor company's options at the date of the transaction.
The Company has an employee stock option plan which is authorized to
issue up to 824,195 shares of common stock to officers and employees. The option
price per share is the fair value of a share of common stock on the date of
grant, as determined by the Company's board of directors. The expiration date of
each option is fixed by the board of directors at not more than ten years from
the date of grant. The options become exercisable from time to time over periods
and upon terms and conditions as the board of directors determines. Current
outstanding options become exercisable in 25% increments over a four-year period
beginning one year from date of grant. As of December 31, 1998, there were
171,571 shares available for grant under the Plan.
F-15
<PAGE> 62
The Company has an employee stock option plan which is authorized to
issue up to 1,070,000 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. The
options became exercisable in 25% increments over a four-year period beginning
one year from date of grant.
The Company has a Non-Employee Directors Stock Option Plan authorizing
the issuance of up to 120,000 shares of common stock. The exercise price of
options under the Plan is equal to the fair market value on the date of grant.
Options expire on the tenth anniversary of the grant date. The options become
exercisable on the anniversary of the grant date at a rate of one third of the
shares each year.
The Company has elected to follow Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees" (APB 25) and related
Interpretations in accounting for its employee stock options because, as
discussed below, the alternative fair value accounting provided for under SFAS
123, "Accounting for Stock-Based Compensation" requires use of option valuation
models that were not developed for use in valuing employee stock options. Under
APB 25, no compensation expense is recognized because the exercise price of the
Company's employee stock options equals the market price of the underlying stock
on the date of the grant.
Pro forma information regarding net income is required by Statement
123, and has been determined as if the Company had accounted for its employee
stock options under the fair value method of that Statement. The fair value for
these stock options was estimated at the date of grant using a Black-Scholes
option pricing model with the following weighted-average assumptions for 1996
and 1997 (predecessor and successor periods), respectively: risk-free interest
rates of 6.5% and 6.1%; volatility factors of the expected market price of the
Company's common stock of .36 and near zero; dividend yield of zero; and a
weighted-average expected life of the option of seven years. There were no
options issued in 1998.
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 pro forma disclosures, the estimated fair value of the
options is amortized to expense over the options' vesting period. The Company's
pro forma information for grants made after January 1, 1995, follows: net loss
of $130.8 million and $11.4 million for the successor company's year ended
December 31, 1998 and six months ended December 31, 1997, respectively, and net
loss of $12.4 million and net income of $14.3 million for the predecessor
company's six months ended June 30, 1997 and the year ended December 31, 1996,
respectively.
The effects of applying Statement 123 for providing pro forma
disclosures are not indicative of future amounts until the new rules are applied
to all outstanding, nonvested awards.
F-16
<PAGE> 63
Stock option activity under the three plans consisted of the following:
<TABLE>
<CAPTION>
SUCCESSOR COMPANY | PREDECESSOR COMPANY
---------------------- | -----------------------
WEIGHTED | WEIGHTED
NUMBER AVERAGE | NUMBER AVERAGE
OF EXERCISE | OF EXERCISE
SHARES PRICE | SHARES PRICE
-------- -------- | --------- --------
<S> <C> <C> | <C> <C>
BALANCE AT DECEMBER 31, 1995 | 544,750 $13.88
Granted | 292,000 20.74
Exercised | (3,250) 12.38
Forfeited | (30,000) 15.75
| --------
BALANCE AT DECEMBER 31, 1996 | 803,500 16.31
Exercised | (937) 16.38
Surrendered | (598,063) 15.61
Re-quantified and re-priced 165,083 $ .10 | (204,500) 18.34
Granted 652,624 10.82 | --
-------- | --------
BALANCE AT DECEMBER 31, 1997 817,707 8.66 | --
======== | ========
BALANCE AT DECEMBER 31, 1998 817,707 8.66 |
======== |
OPTIONS EXERCISABLE AT DECEMBER 31, 1998 362,586 $ 5.94 |
======== |
</TABLE>
No options were granted in 1998. The weighted average fair value of
options granted during the years 1997 and 1996 were $1.98 and $10.59 per share,
respectively. The exercise price for the options outstanding as of December 31,
1998 ranged from $.10 to $10.82 per share. At December 31, 1998 the weighted
average remaining contractual life of the outstanding options is 8.7 years.
12) TAXES
The (benefit) provision for income taxes on continuing operations
includes the following (in thousands):
<TABLE>
<CAPTION>
SUCCESSOR COMPANY | PREDECESSOR COMPANY
------------------------------- | --------------------------------
YEAR SIX MONTHS | SIX MONTHS YEAR
ENDED ENDED | ENDED ENDED
DECEMBER 31, DECEMBER 31, | JUNE 30, DECEMBER 31,
1998 1997 | 1997 1996
------------ ------------ | ---------- ------------
<S> <C> <C> | <C> <C>
CURRENT |
Federal $ (503) $ (345) | $ (1,397) $ 2,011
State -- (41) | (111) 217
-------- -------- | -------- --------
(503) (386) | (1,508) 2,228
DEFERRED |
Federal (69,976) (6,038) | 2,945 4,257
State (5,726) (341) | 180 81
-------- -------- | -------- --------
(75,702) (6,379) | 3,125 4,338
-------- -------- | -------- --------
TOTAL $(76,205) $ (6,765) | $ 1,617 $ 6,566
======== ======== | ======== ========
</TABLE>
F-17
<PAGE> 64
The effective tax rate for continuing operations differs from the U.S.
federal statutory tax rate as follows:
<TABLE>
<CAPTION>
SUCCESSOR COMPANY | PREDECESSOR COMPANY
---------------------------- | ----------------------------
YEAR SIX MONTHS | SIX MONTHS YEAR
ENDED ENDED | ENDED ENDED
DECEMBER 31, DECEMBER 31, | JUNE 30, DECEMBER 31,
1998 1997 | 1997 1996
------------ ------------ | ---------- ----------
<S> <C> <C> | <C> <C>
Statutory federal income tax rate 35.0% 35.0% | 35.0% 35.0%
Increases (reductions) in taxes resulting from: |
State income taxes, net of federal tax benefit 2.0 2.0 | (.8) 1.9
Nonconventional fuel source tax credits -- -- | (3.8) (5.9)
Transaction-related expenses -- -- | (49.9) --
Statutory depletion -- 0.5 | -- (0.6)
Other, net (0.1) (0.2) | -- (0.2)
----- ----- | ------ -----
Effective income tax rate for the period 36.9% 37.3% | (19.5)% 30.2%
===== ===== | ====== =====
</TABLE>
Significant components of deferred income tax liabilities and assets
are as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31, DECEMBER 31,
1998 1997
------------ ------------
<S> <C> <C>
Deferred income tax liabilities:
Property and equipment, net $ 55,017 $ 119,650
Other, net 534 433
--------- ---------
Total deferred income tax liabilities 55,551 120,083
Deferred income tax assets:
Accrued expenses 2,178 2,195
Inventories 15 80
Net operating loss carryforwards 24,515 12,019
Tax credit carryforwards 744 1,895
Other, net 483 463
Valuation allowance (1,976) (1,863)
--------- ---------
Total deferred income tax assets 25,959 14,789
--------- ---------
Net deferred income tax liability $ 29,592 $ 105,294
========= =========
Long-term liability $ 32,041 $ 107,996
Current asset (2,449) (2,702)
--------- ---------
Net deferred income tax liability $ 29,592 $ 105,294
========= =========
</TABLE>
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, 1998 relates principally to
certain net operating loss carryforwards which management estimates will expire
before they can be utilized.
At December 31, 1998, the Company had approximately $66 million of net
operating loss carryforwards available for federal income tax reporting
purposes. Approximately $1 million of the net operating loss carryforwards are
limited as to their annual utilization as a result of prior ownership changes.
These net operating loss carryforwards, if unused, will expire from 2001 to
2006. The remaining net operating loss carryforwards will expire in 2012 and
2018. The Company has alternative minimum tax credit carryforwards of
approximately $700,000 which have no expiration date. The
F-18
<PAGE> 65
Company has approximately $600,000 of statutory depletion carryforwards, which
have no expiration date.
(13) 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. Amounts are allocated to substantially all
employees based on relative compensation. The Company contributed $938,000 and
$749,500 for the successor company's year ended December 31, 1998 and six months
ended December 31, 1997, respectively, and $588,900 and $1.3 million for the
predecessor company's six months ended June 30, 1997 and year ended December 31,
1996, respectively, to the profit sharing plan of which one half was paid in
cash and one half was paid in shares of the Company's common stock contributed
into each eligible employee's 401(k) plan account. Additional discretionary
bonuses are also made.
The Company has a qualified defined contribution plan (a 401(k) plan)
covering substantially all of the employees of the Company. Under the plan, an
amount equal to 2% of participants' compensation is contributed by the Company
to the plan each year. Eligible employees may also make voluntary contributions
which the Company matches $.50 for every $1.00 contributed up to 6% of an
employee's annual compensation. Prior to January 1, 1998, the Company matched
$.25 for every $1.00 contributed up to 6% of an employee's annual compensation.
Retirement plan expense amounted to $867,000 and $285,000 for the successor
company's year ended December 31, 1998 and six months ended December 31, 1997,
respectively, and $266,000 and $457,000 for the predecessor company's six months
ended June 30, 1997 and year ended December 31, 1996, respectively.
The Company also has non-qualified deferred compensation plans which
permit certain key employees to elect to defer a portion of their compensation.
(14) COMMITMENTS AND CONTINGENCIES
The Company is involved in various legal actions arising in the normal
course of business. In the opinion of management, the ultimate disposition of
these matters will not have a material adverse effect on the financial position
of the Company.
(15) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
<TABLE>
<CAPTION>
SUCCESSOR COMPANY | PREDECESSOR COMPANY
------------------------------- | ------------------------------
YEAR SIX MONTHS | SIX MONTHS YEAR
ENDED ENDED | ENDED ENDED
DECEMBER 31, DECEMBER 31, | JUNE 30, DECEMBER 31,
(IN THOUSANDS) 1998 1997 | 1997 1996
------------ ------------ | ---------- ------------
<S> <C> <C> | <C> <C>
CASH PAID DURING THE PERIOD FOR: |
Interest $ 32,048 $ 13,867 | $ 4,153 $ 7,830
Income taxes, net of refunds (1,970) (1,517) | 288 1,222
|
NON-CASH INVESTING AND FINANCING ACTIVITIES: |
Acquisition of assets in exchange for |
long-term liabilities 415 -- | 792 --
Debentures converted to common stock -- -- | 5,550 1,250
</TABLE>
F-19
<PAGE> 66
(16) 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
maturaties 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 maturaties. The $225.0 million in
senior subordinated notes had an approximate fair value of $157.5 million at
December 31, 1998 based on rates available for similar instruments. The
estimated fair value of interest rate swaps was an unrealized loss of $4.2
million at December 31, 1998 based on current 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 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 or options. Under the deferral
method, gains and losses on these instruments are deferred on the balance sheet
and are included as an adjustment to gas revenue for the production being hedged
in the contract month. The Company incurred pre-tax gains on its hedging
activities of $1.5 million in 1998 and losses on its hedging activities of
$116,000 in 1997 and $258,000 in 1996.
During 1998, the Company hedged 6.2 Bcf of 1999 gas production at a
weighted average NYMEX price of $2.44 per Mcf which represented a net unrealized
gain of $2.8 million at December 31, 1998. At December 31, 1997, the Company
had a net unrealized gain of $422,000.
(17) 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.
<TABLE>
<CAPTION>
SUCCESSOR COMPANY | PREDECESSOR COMPANY
------------------------------ | -----------------------------
YEAR SIX MONTHS | SIX MONTHS YEAR
ENDED ENDED | ENDED ENDED
DECEMBER 31, DECEMBER 31, | JUNE 30, DECEMBER 31,
(IN THOUSANDS) 1998 1997 | 1997 1996
------------ ------------ | ---------- ------------
<S> <C> <C> | <C> <C>
Acquisition costs |
Proved properties $ 9,194 $13,501 | $ 9,249 $ 4,275
Unproved properties 1,857 1,342 | 1,267 2,320
Developmental costs 30,090 21,822 | 11,322 30,750
Exploratory costs 9,982 5,980 | 4,380 6,131
</TABLE>
The amounts reflected in the above table do not include the effects of
purchase accounting which resulted from the TPG merger. See Note 1.
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
F-20
<PAGE> 67
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 developed reserves have been reviewed by
independent petroleum engineers. The estimates of proved undeveloped reserves
were prepared by the Company's petroleum engineers and the December 31, 1998
proved undeveloped reserves have been reviewed by independent petroleum
engineers.
The following table sets forth changes in estimated proved and proved
developed reserves for the periods indicated:
<TABLE>
<CAPTION>
SUCCESSOR COMPANY PREDECESSOR COMPANY TOTAL
-------------------------- ---------------------------- --------------------------
OIL GAS OIL GAS OIL GAS
(Bbl) (Mcf) (Bbl) (Mcf) (Bbl) (Mcf)
----------- ------------ ----------- ------------ ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
DECEMBER 31, 1995 6,283,006 239,400,308 6,283,006 239,400,308
Extensions and discoveries 387,414 38,079,620 387,414 38,079,620
Purchase of reserves in place 336,279 8,182,402 336,279 8,182,402
Sale of reserves in place (7,664) (250,021) (7,664) (250,021)
Revisions of previous estimates 1,108,538 28,601,277 1,108,538 28,601,277
Production (718,667) (25,410,233) (718,667) (25,410,233)
----------- ------------ ----------- ------------
DECEMBER 31, 1996 7,388,906 288,603,353 7,388,906 288,603,353
Extensions and discoveries 244,242 26,550,917 282,999 12,142,158 527,241 38,693,075
Purchase of reserves in place 78,149 20,093,436 71,905 13,191,547 150,054 33,284,983
Sale of reserves in place (12,780) (400,196) (21,196) (337,814) (33,976) (738,010)
TPG merger 6,514,982 276,776,629 (6,514,982) (276,776,629)
Revisions of previous estimates (899,930) (16,909,297) (826,900) (24,075,426) (1,726,830) (40,984,723)
Production (372,651) (14,466,129) (380,732) (12,747,189) (753,383) (27,213,318)
----------- ------------ ----------- ------------ ----------- ------------
DECEMBER 31, 1997 5,552,012 291,645,360 -- -- 5,552,012 291,645,360
Extensions and discoveries 255,101 29,330,826 255,101 29,330,826
Purchase of reserves in place 33,899 20,295,868 33,899 20,295,868
Sale of reserves in place (21,209) (6,939,240) (21,209) (6,939,240)
Revisions of previous estimates (808,599) 11,066,042 (808,599) 11,066,042
Production (768,415) (30,139,996) (768,415) (30,139,996)
----------- ------------ ----------- ------------ ----------- ------------
DECEMBER 31, 1998 4,242,789 315,258,860 -- -- 4,242,789 315,258,860
=========== ============ =========== ============ =========== ============
PROVED DEVELOPED RESERVES
December 31, 1996 6,410,344 225,693,651 6,410,344 225,693,651
=========== ============ =========== ============
December 31, 1997 4,830,163 251,851,000 4,830,163 251,851,000
=========== ============ =========== ============
DECEMBER 31, 1998 3,973,772 280,668,600 3,973,772 280,668,600
=========== ============ =========== ============
</TABLE>
F-21
<PAGE> 68
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:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------------------------
1998 1997 1996
----------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Estimated future cash inflows (outflows)
Revenues from the sale of oil and gas $ 818,401 $ 876,464 $ 1,087,997
Production and development costs (340,321) (355,165) (419,504)
----------- ----------- -----------
Future net cash flows before income taxes 478,080 521,299 668,493
Future income taxes (102,358) (130,306) (185,768)
----------- ----------- -----------
Future net cash flows 375,722 390,993 482,725
10% timing discount (167,059) (171,273) (223,496)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows $ 208,663 $ 219,720 $ 259,229
=========== =========== ===========
</TABLE>
F-22
<PAGE> 69
The principal sources of changes in the standardized measure of future
net cash flows are as follows (the successor and predecessor periods are
combined in 1997 for purposes of this presentation):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1998 1997 1996
------------ ------------ --------------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning of year $ 219,720 $ 259,229 $ 170,917
Sale of oil and gas, net of
production costs (60,330) (61,088) (58,023)
Extensions and discoveries, less
related estimated future
development and production costs 30,821 54,979 60,738
Purchase of reserves in place less
estimated future production costs 10,528 33,233 10,694
Sale of reserves in place less
estimated future production costs (3,373) (588) (191)
Revisions of previous quantity estimates (673) (43,111) 38,204
Net changes in prices and production costs (30,512) (73,956) 83,530
Change in income taxes 24,977 19,618 (55,494)
Accretion of 10% timing discount 29,259 35,596 21,425
Changes in production rates (timing)
and other (11,754) (4,192) (12,571)
------------- ------------- ---------------
End of year $ 208,663 $ 219,720 $ 259,229
============= ============= ===============
</TABLE>
(18) INDUSTRY SEGMENT FINANCIAL INFORMATION
GENERAL INFORMATION
The Company's operations are conducted in the United States and are
managed along three reportable segments which include: (1) exploration and
production, (2) gas marketing and gathering, and (3) oilfield sales and service.
The Company's reportable segments were identified based on the nature of the
business activities of each component organized primarily by products or
services provided. The exploration and production segment derives its revenues
primarily through the production of oil and natural gas, acquiring and enhancing
the economic performance of producing oil and gas properties and exploring for
and developing natural gas and oil reserves. The gas marketing and gathering
segment derives its revenues primarily from gas marketed directly to commercial
and industrial customers and from its operation of natural gas gathering lines.
The oilfield sales and service segment derives its revenues primarily from
oilfield services provided and from the sale of a broad range of oilfield
supplies. The Company has no material operations in any individual foreign
country.
FINANCIAL INFORMATION AND RECONCILIATION
The following tables present certain financial information for the
successor company's year ended December 31, 1998 and six months ended December
31, 1997 and the predecessor company's six months ended June 30, 1997 and year
ended December 31, 1996 regarding the Company's reportable segments of its
continuing operations. The "all other" column in each of the following tables
includes unallocated corporate charges that support the segments and
eliminations of all intersegment transactions to reconcile the reportable
segment's revenues, income or loss, assets and other significant items to the
Company's consolidated totals. Segment information for the periods prior to the
year ended December 31, 1998 has been restated to reflect changes in the
composition of reportable segments. Income and expense items below operating
(loss) income are not allocated to the segments and are not disclosed.
F-23
<PAGE> 70
MEASUREMENT
The Company measures segment operating results based on earnings before
interest, taxes, depreciation, depletion, amortization and exploration expense
and results from continuing operations before income taxes. The accounting
policies of the reportable segments are the same as those described in the
summary of significant accounting policies. Intersegment sales are billed on an
intercompany basis at prices for comparable third party goods and services.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998 (SUCCESSOR COMPANY)
-----------------------------------------------------------------------------
EXPLORATION GAS MARKETING OILFIELD SALES
& PRODUCTION & GATHERING & SERVICE ALL OTHER TOTAL
------------ ------------- -------------- --------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
REVENUES FROM CUSTOMERS $ 91,131 $ 39,639 $ 23,809 $ 260 $ 154,839
INTERSEGMENT REVENUES -- 30,249 7,008 (37,257) --
LOSS FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES (174,634) (15,748) (9,236) (7,137) (206,755)
INTEREST EXPENSE 30,041 1,176 1,454 232 32,903
EXPLORATION EXPENSE 9,983 -- -- (1) 9,982
DEPRECIATION, DEPLETION, AND
AMORTIZATION 53,637 11,597 1,723 1,531 68,488
OTHER SIGNIFICANT NONCASH ITEM:
IMPAIRMENT OF OIL AND GAS
PROPERTIES AND OTHER ASSETS 144,670 9,155 6,865 -- 160,690
EBITDAX 63,697 6,180 806 (5,375) 65,308
ASSETS 342,646 37,058 17,834 21,067 418,605
<CAPTION>
SIX MONTHS ENDED DECEMBER 31, 1997 (SUCCESSOR COMPANY)
--------------------------------------------------------------------------
EXPLORATION GAS MARKETING OILFIELD SALES
& PRODUCTION & GATHERING & SERVICE ALL OTHER TOTAL
------------ ------------ -------------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
REVENUES FROM CUSTOMERS $ 46,116 $ 21,969 $ 15,623 $ 418 $ 84,126
INTERSEGMENT REVENUES -- 14,332 4,411 (18,743) --
(LOSS) INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME
TAXES (16,569) 1,328 468 (3,364) (18,137)
INTEREST EXPENSE 14,244 366 589 218 15,417
EXPLORATION EXPENSE 5,980 -- -- -- 5,980
DEPRECIATION, DEPLETION, AND
AMORTIZATION 28,636 1,476 771 811 31,694
EBITDAX 32,291 3,170 1,828 (2,335) 34,954
ASSETS 502,134 45,714 27,150 24,322 599,320
</TABLE>
F-24
<PAGE> 71
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1997 (PREDECESSOR COMPANY)
----------------------------------------------------------------------------
EXPLORATION GAS MARKETING OILFIELD SALES
& PRODUCTION & GATHERING & SERVICE ALL OTHER TOTAL
------------ ------------- -------------- --------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
REVENUES FROM CUSTOMERS $ 45,166 $ 19,392 $ 14,794 $ 45 $ 79,397
INTERSEGMENT REVENUES -- 14,387 4,081 (18,468) --
INCOME (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES 9,948 1,599 213 (20,016) (8,256)
INTEREST EXPENSE 3,413 103 204 (5) 3,715
EXPLORATION EXPENSE 4,380 -- -- -- 4,380
DEPRECIATION, DEPLETION, AND
AMORTIZATION 13,102 1,435 601 228 15,366
OTHER SIGNIFICANT ITEM:
Transaction expenses -- -- -- 16,758 16,758
EBITDAX 30,843 3,137 1,018 (3,035) 31,963
<CAPTION>
YEAR ENDED DECEMBER 31, 1996 (PREDECESSOR COMPANY)
----------------------------------------------------------------------------
EXPLORATION GAS MARKETING OILFIELD SALES
& PRODUCTION & GATHERING & SERVICE ALL OTHER TOTAL
------------ ------------- -------------- --------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
REVENUES FROM CUSTOMERS $ 85,621 $ 41,565 $ 25,477 $ 572 $ 153,235
INTERSEGMENT REVENUES -- 22,605 7,450 (30,055) --
INCOME (LOSS) FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES 22,626 3,523 1,368 (5,757) 21,760
INTEREST EXPENSE 6,798 229 421 (65) 7,383
EXPLORATION EXPENSE 6,064 -- -- -- 6,064
DEPRECIATION, DEPLETION, AND
AMORTIZATION 25,225 2,888 1,154 485 29,752
EBITDAX 60,713 6,640 2,943 (5,337) 64,959
</TABLE>
MAJOR CUSTOMERS
No customer exceeded 10% of consolidated revenue during the year ended
December 31, 1998, the six months ended June 30, 1997 and December 31, 1997 and
the year ended December 31, 1996.
F-25
<PAGE> 72
(19) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The results of operations for the four quarters of 1998 and 1997 are
shown below (in thousands).
<TABLE>
<CAPTION>
SUCCESSOR COMPANY
---------------------------------------------------------------------
FIRST SECOND THIRD FOURTH
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
1998
- ----
Sales and other operating revenues $ 39,126 $ 37,614 $ 34,803 $ 38,870
Gross loss (680) (3,773) (3,646) (4,092)
Net loss (6,271) (8,230) (8,086) (107,963)(1)
</TABLE>
(1) The net loss in the fourth quarter of 1998 includes pre-tax impairment
losses of $160.7 million. See note 2.
<TABLE>
<CAPTION>
PREDECESSOR COMPANY | SUCCESSOR COMPANY
-------------------------- | ---------------------------
FIRST SECOND | THIRD FOURTH
-------- -------- | -------- --------
<S> <C> <C> | <C> <C>
1997 |
- ---- |
Sales and other operating revenues $ 41,546 $ 36,367 | $ 38,382 $ 44,038
Gross profit (loss) 9,512 4,135 | (1,346) (591)
Net income (loss) 4,847 (14,720) | (5,810) (5,562)
</TABLE>
(20) DISCONTINUED OPERATIONS
In September 1995, the Company announced plans to sell Engine Power
Systems, Inc. ("EPS"), its wholly-owned subsidiary engaged in engine, parts and
service sales. The Company was unable to identify an acceptable buyer for EPS by
the end of 1996. A substantial portion of the workforce was eliminated and
substantial assets were sold and the Company recognized an additional charge in
1996 to reduce the remaining assets to net realizable value. The remaining
assets were sold in 1997. Net revenues generated by EPS were approximately $3.9
million in 1996 and $4.2 million in 1995. Loss from operations of discontinued
business was $180,000 ($117,000 net of tax benefit) in 1996 and $760,000
($492,000 net of tax benefit) in 1995. Estimated loss on disposal was $495,000
($322,000 net of tax benefit) in 1996 and $1.0 million ($647,000 net of tax
benefit) in 1995. The results of operations of EPS are presented as discontinued
operations in the accompanying financial statements for all periods presented.
(21) SALE OF TAX CREDIT PROPERTIES
In March 1998, the Company sold certain interests that qualify for the
nonconventional fuel source tax credit. The interests were sold for
approximately $730,000 in cash and a volumetric production payment under which
100% of the cash flow from the properties will go to the Company until
approximately 10.8 Bcf (billion cubic feet) of gas has been produced and sold.
In addition to receiving 100% of the cash flow from the properties, the Company
will receive quarterly incentive payments based on production from the
interests. The Company has the option to repurchase the interests at a future
date.
In February and March 1996, the Company sold certain interests that
qualify for the nonconventional fuel source tax credit. The interests were sold
in two separate transactions for approximately $750,000 and $100,000,
respectively, in cash and a volumetric production payment under which 100% of
the cash flow from the properties will go to the Company until approximately
11.7 Bcf and 3.4 Bcf, respectively, of gas has been produced and sold. In
addition to receiving 100% of the cash flow from the properties, the Company
will receive quarterly incentive payments based on production from the
interests. The Company has the option to repurchase the interests at a future
date.
F-26
<PAGE> 1
<TABLE>
<CAPTION>
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
SUBSIDIARY STATE OF INCORPORATION
- -------------------------------------- ------------------------------------------
<S> <C>
The Canton Oil & Gas Company Ohio
Target Oilfield Pipe & Supply Company Ohio
Ward Lake Drilling, Inc. Michigan
Peake Energy, Inc. Delaware
Belden Energy Services Company Ohio
</TABLE>
As of December 31, 1998, the other subsidiaries included in the registrant's
consolidated financial statements, and all other subsidiaries considered in the
aggregate as a single subsidiary, did not constitute a significant subsidiary.
<PAGE> 1
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference of our report dated April 13,
1999, with respect to the consolidated financial statements of Belden & Blake
Corporation included in this Annual Report (Form 10-K) for the year ended
December 31, 1998, in the following Registration Statements and related
Prospectuses:
<TABLE>
<CAPTION>
REGISTRATION
NUMBER DESCRIPTION OF REGISTRATION STATEMENTS
<S> <C>
33-62785 Stock Option Plan; Non-Employee Director Stock Option
Plan--Form S-8
33-69802 Employees' 401(K) Profit Sharing Plan--Form S-8
</TABLE>
ERNST & YOUNG LLP
Cleveland, Ohio
April 13, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000880114
<NAME> BELDEN & BLAKE CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 10,691
<SECURITIES> 0
<RECEIVABLES> 33,204
<ALLOWANCES> 0
<INVENTORY> 9,200
<CURRENT-ASSETS> 58,928
<PP&E> 586,396
<DEPRECIATION> 246,689
<TOTAL-ASSETS> 418,605
<CURRENT-LIABILITIES> 65,196
<BONDS> 354,382
0
0
<COMMON> 1,011
<OTHER-SE> (34,025)
<TOTAL-LIABILITY-AND-EQUITY> 418,605
<SALES> 150,413
<TOTAL-REVENUES> 154,839
<CGS> 83,538
<TOTAL-COSTS> 83,538
<OTHER-EXPENSES> 245,153
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 32,903
<INCOME-PRETAX> (206,755)
<INCOME-TAX> (76,205)
<INCOME-CONTINUING> (130,550)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (130,550)
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
