<PAGE> 1
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, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No. 0-20100
BELDEN & BLAKE CORPORATION
(Exact name of registrant as specified in its charter)
OHIO 34-1686642
(State or other jurisdiction of (I.R.S. Employer Identification
incorporation or organization) Number)
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, 1998 was $8,200,229.
The number of shares outstanding of registrant's common stock,
without par value, as of February 28, 1998 was 10,110,915.
DOCUMENTS INCORPORATED BY REFERENCE
None.
<PAGE> 2
PART I
- ------
Item 1. BUSINESS
--------
Throughout this report, the "Company" refers to Belden & Blake
Corporation ("Successor Company") and its predecessor which were acquired by TPG
Partners II L.P. on March 27, 1997 (see Significant Events under this Item). 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 has been presented on a combined basis because such
information is comparable to the historical data of the predecessor.
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
primarily engaged in producing oil and natural gas, acquiring and enhancing the
economic performance of producing oil and gas properties, exploring for and
developing natural gas and oil reserves and gathering and marketing natural gas.
Until 1995, the Company conducted business exclusively in the Appalachian Basin
where it has operated since 1942 through several predecessor entities. It is now
one of the largest exploration and production companies operating in the
Appalachian Basin in terms of reserves, acreage held and wells operated. In
early 1995, the Company commenced operations in the Michigan Basin through the
acquisition of Ward Lake Drilling, Inc. ("Ward Lake"), an exploration and
production company, which owns and operates oil and gas properties in Michigan's
lower peninsula. In September 1996, the Company entered the Illinois Basin by
acquiring the Shrewsbury Field in northwestern Kentucky.
At December 31, 1997, the Company owned interests in 8,070 gross (7,232
net) productive gas and oil wells in Ohio, West Virginia, Pennsylvania, New
York, Michigan and Kentucky with proved reserves totaling 291.6 Bcf (billion
cubic feet) of gas and 5.6 Mmbbl (million barrels) of oil. The estimated future
net revenues from these reserves had a present value before income taxes of
approximately $292.6 million at December 31, 1997. At that date, the Company
held leases on 1,250,226 gross (1,081,558 net) acres, including 625,450 gross
(520,691 net) undeveloped acres.
At December 31, 1997, the Company operated more than 7,900 wells,
including wells operated for third parties. The Company owned and operated
approximately 3,000 miles of gas gathering systems with access to the commercial
and industrial gas markets of the northeastern United States at December 31,
1997. At December 31, 1997, the Company's net production was approximately 83
Mmcf (million cubic feet) of gas and 1,980 Bbls (barrels) of oil per day. At
that date, the Company was marketing approximately 141 Mmcf of gas per day,
consisting of its own production and gas purchased from third parties.
The Company has 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 1992 through December 31, 1997, the
Company has acquired for $150.7 million producing properties with 226.4 Bcfe
(billion cubic feet of natural gas equivalent) of proved developed reserves at
an average cost of $.67 per Mcfe (thousand cubic feet of natural gas equivalent)
and spent $20.5 million to acquire and develop additional gas gathering
facilities. During the period from 1992 through 1997, the Company
1
<PAGE> 3
drilled 808 gross (609.5 net) wells at an aggregate cost of approximately $115.2
million for the net wells. This drilling added 124.0 Bcfe to the Company's
proved reserves. During 1997, the Company drilled 261 gross (199.6 net) wells at
a direct cost of approximately $40.5 million for the net wells. The 1997
drilling activity added 41.9 Bcfe of proved reserves at an average cost of $.97
per Mcfe. Reserves added through drilling in 1997 represent approximately 132%
of 1997 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
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 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.
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 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 new 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.
RECENT DEVELOPMENTS
SUBSEQUENT EVENTS
On March 19, 1998, the Company entered into an agreement 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 for,
development, production, transportation and marketing of natural gas. Under the
agreement, the Company proposes to contribute its gas marketing division to FE
Holdings and provide FE Holdings with its gas marketing, operational and
management expertise.
FirstEnergy, a diversified energy services holding company
headquartered in Akron, Ohio, comprises the nation's twelfth largest
investor-owned electric utility system. Its electric utility operating companies
- -- Ohio Edison Company and its subsidiary, Pennsylvania Power Company; The
Illuminating Company; and Toledo Edison Company -- serve 2.2 million customers
within 13,200 square miles of northern and central Ohio and western
Pennsylvania. FirstEnergy produces approximately $5 billion in annual revenues
and owns more than $18 billion in assets, including ownership in 18 power
plants. In an expansion of its energy-related products and services, FirstEnergy
in December 1997 acquired Roth Bros.,
2
<PAGE> 4
Inc., and RPC Mechanical, Inc., which form one of the nation's largest providers
of engineered heating, ventilating and air-conditioning equipment and energy
management and control systems.
The joint venture is expected to substantially expand the Company's
market outlet for its production of natural gas and more fully utilize the
capabilities and capacity of the Company's Gas Marketing Division. The venture
will allow FirstEnergy to offer its customers total energy services, including
natural gas, electricity and related energy products and services.
The Company and FirstEnergy have also agreed to have FE Holdings
acquire Marbel Energy Corporation ("Marbel"), a privately-held, fully integrated
natural gas company headquartered in Canton, Ohio. Marbel owns interests in more
than 1,800 gas and oil wells and holds interests in more than 200,000
undeveloped acres in eastern and central Ohio. Marbel's subsidiaries include MB
Operating Company, Inc., a natural gas exploration and production company, and
Northeast Ohio Operating Companies, Inc. ("NOOC"), a public utility holding
company based in Lancaster, Ohio. NOOC owns and operates over 1,300 miles of gas
gathering lines and a local gas distribution company with more than 3,000
customers in eastern and central Ohio.
The acquisition of Marbel will provide FE Holdings with a base of
exploration, development and production capability, along with utility
transportation and distribution capability. Marbel's net production in 1997 was
approximately 6.3 Bcfe. At September 30, 1997, Marbel had estimated proved
developed oil and gas reserves of 55.7 Bcfe.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The Company operates in two industry segments: (1) oil and gas
production and distribution and (2) oilfield sales and service. Oilfield sales
are generated by its wholly-owned subsidiary, Target Oilfield Pipe and Supply
Company ("TOPS") and oilfield services are provided by its Arrow Oilfield
Service division ("Arrow"). The financial information with respect to the
industry segments is shown in Note 16 to the Consolidated Financial Statements.
DESCRIPTION OF BUSINESS
OVERVIEW
The Company, founded in 1942, is actively engaged in the acquisition,
exploration, development, production, gathering and marketing of oil and gas in
the Appalachian, Michigan and Illinois Basins. The Company operates principally
in the Appalachian and Michigan Basins where it is now one of the largest oil
and gas companies in terms of reserves, acreage held and wells operated. It
commenced operations in the Illinois Basin in September 1996.
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
3
<PAGE> 5
Appalachian Basin. As of December 31, 1997, there were over 10,000 independent
operators of record and approximately 180,000 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 2,000 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 that there are significant exploration and development
opportunities in these less developed formations for those operators with the
capital, technical expertise and ability to assemble the large acreage positions
needed to justify the use of advanced exploration and production technologies.
In January 1995, the Company purchased Ward Lake Drilling, Inc., a
privately-held exploration and production 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 in
Michigan's lower peninsula. The Company's primary objective in acquiring Ward
Lake was to allow the Company to pursue opportunities in the Michigan Basin with
an established operating company that provided the critical mass to operate
efficiently. Ward Lake currently operates approximately 600 wells 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 Field located in northwestern
Kentucky.
The Company's rationale for entering the Michigan and Illinois Basins
was based on their geologic and operational similarities to the Appalachian
Basin and their geographic proximity to the Company's operations in the
Appalachian Basin. 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 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 300 operators of record, most of which are private companies, and
more than 8,000 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.
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
4
<PAGE> 6
to $1.30 per Mcf (thousand cubic feet) above national wellhead prices. The
Company's average wellhead gas price in 1997 was $0.42 per Mcf above the
estimated average national wellhead price.
BUSINESS STRATEGY
The Company seeks to increase reserves, production and cash flow
through a balanced program of exploration and development drilling and strategic
acquisitions. The key elements of the Company's strategy are as follows:
- - 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 the Appalachian and Michigan Basins. The Company's drilling
budget in 1998 is approximately $38 million, which will fund the drilling
of approximately 274 wells.
- - 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, the size of average
discovery, production rates, reserve recovery rates and total economics in
its operating areas.
- - 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) 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, (iii) provide development and exploratory drilling
opportunities or opportunities to improve the Company's acreage position,
(iv) have the potential for increased revenues resulting from the Company's
gas marketing capabilities, or (v) are of sufficient size to allow the
Company to operate efficiently in new areas.
- - EXPAND GAS GATHERING AND MARKETING. The Company's extensive gas gathering
systems and regional natural gas marketing operation are 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
further improve the rate of return on the Company's drilling and
development activities. The Company has excellent relationships with a
large number of utilities and industrial end users located within the
Company's operating areas. The Company's gas marketing operation provides a
ready market for increased production, allowing the Company to shift sales
from third-party gas to its own production. See: RECENT DEVELOPMENTS and
SUBSEQUENT EVENTS.
5
<PAGE> 7
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, 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 1997.
<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
--------------- --------------------- ----------- ----------- --------------
Total 43 $ 150,676 2,964 208,589 226,373
=============== ===================== =========== =========== ==============
- ------------
</TABLE>
(1) Represents the portion of the purchase price allocated to proved developed
reserves.
(2) Mbbl - thousand barrels Mmcf - million Mmcfe - million cubic
cubic feet feet equivalent
During 1997, the Company acquired for approximately $21.3 million
working interests in 2,365 oil and gas wells in Ohio, Pennsylvania, Michigan and
West Virginia. Estimated proved developed reserves associated with the wells
total 32.8 Bcf of natural gas and 101,000 Bbls of oil net to the Company's
interest at the time of the acquisitions.
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 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 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.
6
<PAGE> 8
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 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
-----------------------------------------------------------
1993 1994 1995 1996 1997
---------- --------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Production:
Oil (thousands of Bbls) 453 496 556 719 753
Gas (Bcf) 7.4 9.6 17.0 25.4 27.2
Average sales price:
Oil (per Bbl) $ 17.15 $ 15.98 $ 16.78 $ 20.24 $18.10
Gas (per Mcf) 2.55 2.58 2.21 2.56 2.65
Average production costs per Mcfe
(including production taxes) 0.71 0.73 0.68 0.72 0.78
Total oil and gas revenues
(in thousands) 26,631 32,574 46,853 79,491 85,756
Total production expenses
(in thousands) 7,119 9,184 13,816 21,266 24,668
</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 1997, the Company drilled 194 gross (162.8 net) wells to highly
developed or shallow blanket formations in its six state operating area at a
direct cost of approximately $31.2 million for the net wells. The Company also
drilled 67 gross (36.8 net) wells to less developed and deeper formations in
1997 at a direct cost of approximately $9.3 million for the net wells. The
result of this drilling activity is shown in the tables on page 11.
The Company believes that its diversified portfolio approach to its
drilling activities results in more consistent and predictable economic results
than might be experienced with a less diversified or higher risk drilling
program profile.
Highly Developed 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
7
<PAGE> 9
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.
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.
Certain typical characteristics of the highly developed or blanket
formations drilled by the Company in 1997 are described below:
<TABLE>
<CAPTION>
Range of Range of
Average Drilling Average Gross
Range of and Completion Reserves
Well Depths Costs per Well per 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>
The Company plans to drill approximately 208 wells to highly developed
or blanket formations in 1998.
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.
8
<PAGE> 10
The less developed formations in the Appalachian Basin include the Knox
sequence of sandstones and dolomites which includes the Rose Run, Beekmantown
and Trempeleau 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.
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
Reserves per
Wells Drilled Wells Completed (1) 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
- ------------
</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 25 years.
9
<PAGE> 11
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
--------------------------------------------------------------------
1993 1994 1995 1996 1997
---------- ----------- ------------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Number of wells in production:
Gross 23 41 66 82 112
Net 20.6 29.7 41.5 58.9 75.6
Percent of total net wells 0.7 % 0.8 % 0.7 % 0.9 % 1.0 %
Annual production (net):
Oil (Mbbl) 13.9 67.1 74.9 78.2 111.2
Gas (Mmcf) 731 1,041 1,624 2,788 3,600
Combined (Mmcfe) 814 1,444 2,074 3,257 4,267
Percent of total combined
production 8 % 11 % 10 % 11 % 13 %
</TABLE>
Productive Knox wells represented approximately 1% of the Company's
total productive wells at December 31, 1997. Production from Knox wells in 1997,
however, equaled 13% 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, 1997, it held leases on
approximately 598,000 net acres overlying potential Knox drilling locations. The
Company plans to drill or participate in joint ventures to drill 48 gross (28.2
net) wells to the Knox formations in 1998.
In addition, the Company has also tested the Niagaran Carbonate, Dundee
Carbonate, Onondaga Limestone, Oriskany Sandstone and Newburg Sandstone
formations. The Company plans to drill approximately 18 gross (16 net) wells to
these formations in 1998. Certain typical characteristics of the less developed
or deeper formations drilled by the Company in 1997 are described below:
<TABLE>
<CAPTION>
Average
Drilling Costs Average
-------------------------- Gross
Range of Dry Completed Reserves
Formation Location Well Depths Hole Well per Well
-------------------------- ------------ ---------------- -------- --------------- ---------------
(in feet) (in thousands) (in Mmcfe)
<S> <C> <C> <C> <C> <C>
Knox formations OH, NY 2,500-8,000 $130 $240 450
Niagaran Carbonate MI 4,500-5,500 275 525 1,200
Dundee Carbonate MI 3,000-3,500 330 500 750
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>
10
<PAGE> 12
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)
-------------------------------------------- ------------------------------------------
1993 1994 1995 1996 1997 1993 1994 1995 1996 1997
---- ---- ---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Productive:
Gross 42 58 106 153 187 16(3) 22(4) 23(5) 34 39(6)
Net 31.4 45.6 92.5 126.3 156.5 8.8 12.7 11.5 22.2 24.5
Dry:
Gross 2 2 4 2 7 14 10 22 18 28
Net 0.7 0.4 3.2 2.0 6.3 11.4 4.8 10.7 10.2 12.3
Reserves discovered-
net (Mmcfe) 3,019 4,813 18,474 32,664 32,840 3,173 5,196 5,194 7,740 9,017
Approximate cost (in
thousands) $4,847 $5,762 $15,079 $22,198 $31,242 $3,413 $5,509 $5,284 $9,029 $9,277
</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 and 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 and the Oriskany
Sandstone and Onondaga Limestone formations in Pennsylvania and the
Oriskany Sandstone, Onondaga Limestone and Knox formations in New York.
(3) Two additional wells which were dry in the Knox formations were
subsequently completed in the shallower Clinton formation.
(4) One additional well which was dry in the Knox formations was subsequently
completed in the shallower Clinton formation.
(5) Two additional wells which were dry in the Knox formations were
subsequently completed in the shallower Clinton formation. One additional
well which was dry in the Oriskany formation was subsequently completed in
the shallower Berea/Shale formations.
(6) Three additional wells which were dry in the Knox formations were
subsequently completed in shallower formations.
GAS GATHERING AND MARKETING
Gas Gathering. The Company operates approximately 3,000 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 earned gathering revenues of $6.7 million in 1997. Direct costs
associated with gas gathering in 1997 totaled approximately $1.7 million.
Gas Marketing. The major industrial centers of Akron, Buffalo, Canton,
Chicago, Cleveland, Detroit and Pittsburgh are all located in close proximity to
the Company's operations and provide a large potential market for direct natural
gas sales. At present, the Company markets directly to approximately 225
customers in a six-state area. The Company focuses its gas marketing efforts on
small to mid-sized industrial customers that require more service and have the
potential to generate higher margins per Mcf than large industrial users.
11
<PAGE> 13
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, 1997, the Company marketed approximately 141
Mmcf of gas per day of which approximately 53% 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,
1997, approximately 50% of the gas marketed by the Company was at fixed prices
and 50% 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
Merchantile 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, 1997, the Company had 310 open
futures contracts covering 1998, at an average price of $2.37 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. On
February 6, 1998 the Company entered into an identical arrangement as above for
144 futures contracts covering June 1998 through May 1999, at an average NYMEX
price of $2.44.
The following table shows the type of buyer for gas marketed by the
Company at December 31, 1997:
<TABLE>
<CAPTION>
Marketed Gas
-------------------------
Mmcf per Percent
Purchaser Day of Total
--------------------------------- ----------- -----------
<S> <C> <C>
End users 59.2 42%
Local distribution companies 53.6 38%
Spot markets 28.2 20%
----------- -----------
Total 141.0 100%
=========== ===========
</TABLE>
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, 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 1997,
approximately 54% of Arrow's revenues were generated by sales to third parties.
Target Oilfield Pipe & Supply Company, 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 oilfield
12
<PAGE> 14
supply business to ensure the quality and availability of supplies for its own
operations. In 1997, approximately 70% of TOPS' revenues were generated by sales
to third parties.
The Company plans to expand its oilfield sales and service business
through continued growth in its six-state market area.
EMPLOYEES
As of February 27, 1998, the Company had 625 full-time employees,
including 220 oilfield sales and service employees, 321 oil and gas production
employees, 19 petroleum engineers, 9 geologists and 3 geophysicists.
COMPETITION AND CUSTOMERS
The oil and gas industry is highly competitive. Competition is
particularly intense with respect to the acquisition of producing properties and
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
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.
During the years ended December 31, 1996 and 1997 there was no customer
which accounted for 10% or more of the Company's consolidated revenues. The only
customer which accounted for 10% or more of the Company's consolidated revenues
during the year ended December 31, 1995 was The East Ohio Gas Company with
purchases of $11.1 million.
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
13
<PAGE> 15
environment in connection with drilling and production activities, limit or
prohibit drilling activities on certain lands lying within wilderness, wetlands
and other protected areas, and impose substantial liabilities for pollution
resulting from the Company's operations. Management believes the Company is in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse impact on the Company.
Regulation of Sales and Transportation. The Federal Energy Regulatory
Commission (the "FERC") 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, 1995, 1996 and 1997 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
---------------------------------------
1995 1996 1997
----------- ----------- -----------
<S> <C> <C> <C>
Estimated proved reserves
Gas (Bcf) 239.4 288.6 291.6
Oil (thousands of barrels) 6,283 7,389 5,552
</TABLE>
See Note 15 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,
1997 determined in accordance with the rules and regulations of the Securities
and Exchange Commission.
14
<PAGE> 16
Estimated future net cash flows (before income taxes) (in thousands)
attributable to estimated production during
[S] [C]
1998 $ 51,955
1999 56,954
2000 52,408
2001 and thereafter 359,982
-----------------
Total $ 521,299
=================
Present value before income taxes
(discounted at 10% per annum) $ 292,591
=================
Present value after income taxes
(discounted at 10% per annum) $ 219,720
=================
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
and development costs). Estimated future net cash flows were calculated on the
basis of prices and costs estimated to be in effect at December 31, 1997 without
escalation, except where changes in prices were fixed and readily determinable
under existing contracts. The weighted average prices for oil and gas at
December 31, 1997 were $14.59 per barrel and $2.73 per Mcf, respectively.
PRODUCING WELL DATA
The following table summarizes by state the Company's productive wells
at December 31, 1997:
<TABLE>
<CAPTION>
December 31, 1997
-------------------------------------------------------------------------------------
Oil Wells Gas Wells Total
---------------------- ----------------------- -----------------------
State Gross Net Gross Net Gross Net
------------------------ --------- -------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Ohio 2,067 1,913 1,642 1,473 3,709 3,386
West Virginia 381 378 1,276 1,289 1,657 1,667
Pennsylvania 318 314 656 519 974 833
New York 7 7 1,018 998 1,025 1,005
Michigan 7 3 595 235 602 238
Kentucky -- -- 103 103 103 103
--------- -------- --------- --------- --------- ---------
2,780 2,615 5,290 4,617 8,070 7,232
========= ======== ========= ========= ========= =========
</TABLE>
15
<PAGE> 17
ACREAGE DATA
The following table summarizes by state the Company's gross and net
developed and undeveloped leasehold acreage at December 31, 1997:
<TABLE>
<CAPTION>
December 31, 1997
------------------------------------------------------------------------------------
Developed Acreage Undeveloped Acreage Total Acreage
------------------------ ------------------------- ----------------------------
State Gross Net Gross Net Gross Net
----------------- ---------- ---------- ------------ ---------- ------------ -------------
<S> <C> <C> <C> <C> <C> <C>
Ohio 318,695 286,544 228,148 190,101 546,843 476,645
West Virginia 80,236 74,013 135,151 81,245 215,387 155,258
Pennsylvania 58,880 46,418 180,353 174,015 239,233 220,433
New York 130,844 118,054 39,163 36,827 170,007 154,881
Michigan 24,538 24,255 37,725 33,593 62,263 57,848
Kentucky 11,583 11,583 4,910 4,910 16,493 16,493
---------- ---------- ------------ ---------- ------------ -------------
624,776 560,867 625,450 520,691 1,250,226 1,081,558
========== ========== ============ ========== ============ =============
</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, 1998 was as follows:
Number of
Title of Class Record Holders
--------------------------------------- --------------------
Common Stock 7
DIVIDENDS
16
<PAGE> 18
No dividends have been paid on the Company's Common Stock.
Item 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
BELDEN & BLAKE CORPORATION
| SUCCESSOR
PREDECESSOR COMPANY | COMPANY
------------------------------------------------------------------- | -------------
SIX MONTHS | SIX MONTHS
ENDED | ENDED
AS OF OR FOR THE YEAR ENDED DECEMBER 31, JUNE 30, | DECEMBER 31,
--------------------------------------------------- |
(IN THOUSANDS) 1993 1994 1995 1996 1997 | 1997
---------- ---------- ---------- ---------- ----------- | -------------
<S> <C> <C> <C> <C> <C> | <C>
OPERATIONS: |
Revenues $ 72,874 $ 79,365 $110,067 $153,235 $79,397 | $84,126
Depreciation, |
depletion |
and amortization 9,693 11,886 19,717 29,752 15,366 | 31,694
Income (loss) from |
continuing |
operations 3,265 4,180 6,260 15,194 (9,873) | (11,372)
Preferred dividends |
paid 180 180 180 180 45 | --
|
BALANCE SHEET DATA: | AS OF
| 12/31/97
| -------------
Working capital 28,850 13,612 17,359 22,110 | 19,846
Oil and gas |
properties and |
gathering systems, |
net 86,192 106,710 216,848 222,127 | 491,183
Total assets 135,174 148,173 297,298 303,763 | 599,320
|
Long-term liabilities, |
less current portion 43,516 47,858 110,523 97,642 | 355,649
|
Preferred stock 2,400 2,400 2,400 2,400 | --
|
Total shareholders' |
equity 76,857 81,142 142,291 158,918 | 96,858
</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 merger 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 sheet at
December 31, 1997 includes the application of purchase accounting to measure the
Company's assets and liabilities at fair value and is not comparable to the
historical balance sheet as of December 31, 1996. Debt incurred to finance the
acquisition and related transaction costs are reflected in the December 31, 1997
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. These higher charges are
expected to continue in subsequent accounting periods.
The Company incurred transaction costs associated with the acquisition
by TPG of $16.8 million. These costs were expensed in the second quarter of
1997. As a result of the acquisition by TPG, the
17
<PAGE> 19
Company is highly leveraged, resulting in materially higher interest charges in
the second half of 1997. These higher interest charges are expected to continue
in subsequent accounting periods.
The Company's principal business is the acquisition, development and
production of, and exploration for, oil and gas reserves, principally in Ohio,
West Virginia, Pennsylvania, Michigan, New York and Kentucky, and the gathering
and marketing of natural gas.
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's gas gathering and marketing operations consist of
purchasing gas at the wellhead and from interstate pipelines and selling gas to
industrial customers and local gas distribution companies.
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.
18
<PAGE> 20
RESULTS OF OPERATIONS
As a result of the merger with TPG, 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
-----------------------------------------------------------
1997 1996 1995
------------------ ------------------- -------------------
<S> <C> <C> <C> <C> <C> <C>
REVENUES
Oil and gas sales $ 85,756 52.4% $ 79,491 51.9% $ 46,853 42.6%
Gas marketing and gathering 44,371 27.1 44,527 29.0 40,436 36.7
Oilfield sales and service 30,206 18.5 25,517 16.7 20,066 18.2
Interest and other 3,190 2.0 3,700 2.4 2,712 2.5
------------------ ------------------- -------------------
163,523 100.0 153,235 100.0 110,067 100.0
EXPENSES
Production expense 21,496 13.2 18,098 11.8 11,756 10.7
Production taxes 3,172 1.9 3,168 2.1 2,060 1.9
Cost of gas and gathering expense 37,784 23.1 37,556 24.5 33,831 30.7
Oilfield sales and service 28,021 17.1 23,142 15.1 18,266 16.6
Exploration expense 10,360 6.3 6,064 4.0 4,924 4.5
General and administrative expense 4,258 2.6 4,573 3.0 3,802 3.4
Depreciation, depletion and
amortization 47,060 28.8 29,752 19.4 19,717 17.9
Franchise, property and other taxes 1,875 1.2 1,739 1.1 1,228 1.1
------------------ ------------------- -------------------
154,026 94.2 124,092 81.0 95,584 86.8
------------------ ------------------- -------------------
OPERATING INCOME 9,497 5.8 29,143 19.0 14,483 13.2
Interest expense 19,132 11.7 7,383 4.8 6,073 5.5
Transaction-related expenses 16,758 10.3
------------------ ------------------- -------------------
35,890 22.0 7,383 4.8 6,073 5.5
------------------ ------------------- -------------------
(LOSS) INCOME FROM CONTINUING
OPERATIONS BEFORE INCOME TAXES (26,393) (16.2) 21,760 14.2 8,410 7.7
(Benefit) provision for income taxes (5,148) (3.2) 6,566 4.3 2,150 2.0
------------------ ------------------- -------------------
(LOSS) INCOME FROM CONTINUING
OPERATIONS (21,245) (13.0) 15,194 9.9 6,260 5.7
LOSS FROM DISCONTINUED OPERATIONS (439) (0.3) (1,139) (1.0)
------------------ ------------------- -------------------
NET (LOSS) INCOME $ (21,245) (13.0)% $ 14,755 9.6% $ 5,121 4.7%
================== =================== ===================
EBITDAX $ 66,917 40.9% $ 64,959 42.4% $ 39,124 35.5%
</TABLE>
1997 COMPARED TO 1996
Operating income decreased $19.6 million (67%) from $29.1 million in
1996 to $9.5 million in 1997. The operating income from the oil and gas
operations segment decreased $18.9 million (76%) from $24.8 million in 1996 to
$5.9 million in 1997. The operating income from the oilfield sales and service
segment decreased $462,000 from $963,000 in 1996 to $501,000 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 merger 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
19
<PAGE> 21
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 ("EBITDAX") 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 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 merger 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 merger.
1996 COMPARED TO 1995
Operating income increased $14.6 million (101%) from $14.5 million in
1995 to $29.1 million in 1996. The operating income from the oil and gas
operations segment increased $12.4 million (99%) from $12.4 million in 1995 to
$24.8 million in 1996. The operating income from the oilfield sales and service
segment increased $290,000 (43%) from $673,000 in 1995 to $963,000 in 1996. The
increase in operating income was due primarily to a $25.2 million increase in
gross margin on oil and gas sales offset by a $10.0 million increase in
depreciation, depletion and amortization expense.
Income from continuing operations increased $8.9 million from $6.3
million in 1995 to $15.2 million in 1996. This increase was the result of the
increases in operating income above offset by an
20
<PAGE> 22
increase in the provision for income taxes of $4.4 million. This increase in the
provision for income taxes was attributable to the increase in income from
continuing operations before income taxes and an increase in the effective tax
rate. The increase in the effective tax rate was primarily due to the decrease
of nonconventional fuel source tax credits as a percentage of income from
continuing operations.
EBITDAX was $65.0 million in 1996 compared to $39.1 million in 1995.
Total revenues increased $43.2 million (39%) in 1996 compared to 1995.
Gross operating margins increased $26.1 million (63%) in 1996 when compared to
1995. The increase in operating income was due primarily to a $25.2 million
increase in gross margin on oil and gas sales.
Oil volumes increased 163,000 Bbls (29%) from 556,000 Bbls in 1995 to
719,000 Bbls in 1996 resulting in an increase in oil sales of approximately $2.7
million. Gas volumes increased 8.4 Bcf (50%) from 17.0 Bcf in 1995 to 25.4 Bcf
in 1996 resulting in an increase in gas sales of approximately $18.7 million.
These volume increases were primarily due to increased production from
properties acquired in 1995 and wells drilled in 1995 and 1996.
The average price paid for the Company's oil increased from $16.78 per
barrel in 1995 to $20.24 per barrel in 1996 which increased oil sales by
approximately $2.5 million. The average price paid for the Company's natural gas
increased $.35 per Mcf to $2.56 per Mcf in 1996 compared to 1995 which increased
gas sales in 1996 by approximately $8.9 million.
Production expense increased $6.3 million (54%) from $11.8 million in
1995 to $18.1 million in 1996. The average production cost increased from $.58
per Mcfe in 1995 to $.61 per Mcfe in 1996. This increase was primarily due to
the increased production volumes discussed above and a reduction in operating
fees charged to third parties. Such fees are recorded as a reduction of
production expense. Production taxes increased $1.1 million (54%) from $2.1
million in 1995 to $3.2 million in 1996. This increase was primarily due to the
increased production volumes discussed above.
Depreciation, depletion and amortization increased by $10.1 million
(51%) from $19.7 million in 1995 to $29.8 million in 1996. Depletion expense
increased $7.9 million (53%) from $15.1 million in 1995 to $23.0 million in
1996. This increase was primarily due to additional depletion expense associated
with the increased production volumes discussed above. Depletion per Mcfe
increased from $.74 per Mcfe in 1995 to $.77 per Mcfe in 1996. This increase was
primarily the result of proved reserves added through acquisitions and drilling
at a higher cost per Mcfe.
Interest expense increased $1.3 million (22%) from $6.1 million in 1995
to $7.4 million in 1996. This increase was primarily due to higher average debt
balances incurred to finance the 1995 acquisitions (Note 4 "Acquisitions").
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, 1997 was 1.51 to 1.00.
During 1997, working capital decreased $2.3 million from $22.1 million to $19.8
million. The decrease was primarily due to an increase in accrued expenses of
$7.5 million offset by an increase in accounts receivable and a decrease in the
current portion of long-term debt. The Company's operating activities provided
cash flows of $38.4
21
<PAGE> 23
million in 1997.
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 initial borrowing base has been set at $180
million. 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 borrowed $104 million under the new credit agreement 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 new 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 7.219% at December 31,
1997.
The new credit agreement contains a number of covenants that, among
other things, restrict 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 new credit agreement, the Company is required
to maintain specified financial ratios and tests, including minimum interest
coverage ratios and maximum leverage ratios.
The Company issued $225 million of 9.875% Senior Subordinated Notes on
June 27, 1997. The notes mature June 15, 2007. Interest will be 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.
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
22
<PAGE> 24
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 $94.0 million.
The Company currently expects to spend approximately $38 million during
1998 on its drilling activities and approximately $13 million for other capital
expenditures. The Company's acquisition program may be financed with 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. The Company intends to finance such activities
principally through its available cash flow and through additional borrowings
under its new credit agreement.
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.
INFLATION AND CHANGES IN PRICES
During 1995, the price paid for the Company's crude oil increased from
$15.50 per barrel to a high of $17.50 per barrel, then decreased to $16.50 per
barrel at year-end, with an average price for the year of $16.78 per barrel.
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, then decreased to a low of $14.25 at year-end 1997,
with an average price of $18.10 per barrel. The average price of the Company's
natural gas increased from $2.21 per Mcf in 1995 to $2.56 per Mcf in 1996, then
increased to $2.65 per Mcf in 1997.
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 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.
23
<PAGE> 25
READINESS FOR YEAR 2000
The Company has taken actions to understand the nature and extent of
the work required to make its systems and operations Year 2000 compliant. The
Company has prepared or is in the process of preparing its operations and its
financial, information and other computer-based systems for the Year 2000,
including the replacing or updating of its legacy systems. The Company will
continue to evaluate the estimated costs associated with these actions compared
with actual experience. While this may involve additional costs, the Company
currently believes that it will manage the Year 2000 conversion without any
material effect on its operations or results of operations.
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 production and costs of
operation, the market demand for, and prices of, oil and natural gas, results of
the Company's future drilling and gas marketing activity, the uncertainties of
reserve estimates, environmental risks, 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 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.
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
24
<PAGE> 26
Executive officers and directors of the Company as of February 28, 1998
were as follows:
<TABLE>
<CAPTION>
Name Age Position
- ---- --- --------
<S> <C> <C>
Ronald L. Clements 55 Chief Executive Officer and Director
Ronald E. Huff 42 President, Chief Financial Officer and Director
Joseph M. Vitale 56 Senior Vice President Legal, General Counsel, Secretary and
Director
Tommy L. Knowles 47 Senior Vice President Exploration and Production
Leo A. Schrider 59 Senior Vice President Technical Development
Dennis D. Belden 52 Vice President Supply and Service
Duane D. Clark 42 Vice President Gas Marketing
James C. Ewing 55 Vice President Human Resources
Charles P. Faber 56 Vice President Corporate Development
Robert W. Peshek 43 Vice President Finance
Dean A. Swift 45 Vice President, Assistant General Counsel and Assistant Secretary
Henry S. Belden, IV 58 Director
Lawrence W. Kellner 39 Director
Max L. Mardick 63 Director
William S. Price, III 42 Director
Gareth Roberts 45 Director
David M. Stanton 35 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 members
each of whom is elected annually to serve one year terms. The business
experience of each executive officer and director is summarized below.
25
<PAGE> 27
RONALD L. CLEMENTS has been Chief Executive Officer and a Director of
the Company since 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 1997, 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. He is a member of the Ohio Petroleum Accountants Society and the
Financial Executives Institute-Northeast Ohio Chapter.
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 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.
26
<PAGE> 28
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. He is a member
of the Independent Petroleum Association of America, the National Investor
Relations Institute and the Petroleum Investor Relations Association.
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
27
<PAGE> 29
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 Company's acquisition by TPG (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 is Executive Vice President and Chief Financial
Officer of Continental Airlines, Inc. In this position, Mr. Kellner is
responsible for Treasury activities, Fleet Management, Financial Planning,
Information Technology, Fuel Purchasing, Accounting and Risk Management. Most
recently, he was Executive Vice President and Chief Financial Officer for
American Savings Bank, with approximately $20 billion in assets, where he was
responsible for all financial operations and strategic planning. Prior to
joining American Savings Bank, Mr. Kellner was Executive Vice President and
Chief Financial Officer for The Koll Company. While at The Koll Company, he
managed the $5 billion domestic and international real estate portfolio of both
the company and its 250 affiliated partnerships. Mr. Kellner began his career at
Ernst & Young LLP where he was responsible for the operation and administration
of the company's real estate consulting and accounting division in Southern
California. Mr. Kellner graduated magna cum laude with a Bachelor of Science,
Business Administration degree from the University of South Carolina. He is a
Certified Public Accountant and has been active in numerous community and civic
organizations including past positions on several boards of directors.
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.
28
<PAGE> 30
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 is
Chairman of the Board of Favorite Brands International, Inc. and Co-Chairman of
the Board of Beringer Wine Estates. He also serves on the Boards of Directors of
Continental Airlines, Inc., Continental Micronesia, Inc., Denbury Resources,
Inc. and Vivra Specialty Partners, 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., TPG Communications, Inc. and Paradyne Partners, L.P.
29
<PAGE> 31
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, 1997, 1996 and 1995 of the Company's Chief Executive Officer and its other
four most highly compensated executive officers.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
Long-Term
Compensation All Other
Annual Compensation Award Compensation(2)
------------------------------------------------- ---------------- ---------------
No. of Shares
Name and Other Annual Underlying
Principal Position Year Salary Bonus Compensation Options/SARs (1)
- ------------------- ---- ------ ----- ------------ ----------------
<S> <C> <C> <C> <C> <C> <C>
Henry S. Belden IV 1997 $180,600 -- -- -- $20,568(4)
Chairman of the Board 1996 $322,038 $ 161,962 -- 40,000 $25,869(4)
and Chief Executive 1995 $310,994 $ 145,765 -- 40,000 $18,720(4)
Officer (3)
Max L. Mardick 1997 $146,892 -- -- -- $ 5,575
President and Chief 1996 $236,731 $ 83,793 -- 25,000 $13,439
Operating Officer (5) 1995 $229,808 $ 72,445 -- 25,000 $ 7,042
Ronald L. Clements 1997 $239,154 $ 84,390 -- 137,366 $14,625
Chief Executive Officer 1996 $171,173 $ 66,303 $4,000 20,000 $11,342
1995 $161,373 $ 62,568 $5,000 20,000 $ 7,629
Ronald E. Huff 1997 $208,646 $ 83,192 -- 137,366 $13,767
President and Chief 1996 $166,462 $ 66,175 -- 20,000 $11,550
Financial Officer 1995 $168,466 $ 32,706 -- 20,000 $ 8,016
Joseph M. Vitale 1997 $168,800 $ 66,627 -- 54,946 $11,863
Senior Vice President 1996 $162,069 $ 66,020 -- 20,000 $10,078
Legal, General Counsel 1995 $156,066 $ 52,810 -- 20,000 $ 8,768
and Secretary
Tommy L. Knowles 1997 $167,154 $ 46,563 -- 54,946 $72,009(6)
Senior Vice President 1996 $141,923 $ 12,772 -- 20,000 $57,041(7)
of Exploration and
Production
Leo A. Schrider 1997 $128,504 $ 20,065 -- 20,000 $10,046
Senior Vice President 1996 $124,261 $ 19,616 -- 12,500 $ 8,416
of Technical Development 1995 $120,954 $ 14,078 -- 12,500 $ 6,194
- ---------------------
</TABLE>
(1) All awards prior to June 27, 1997 relate to options to purchase stock
in the predecessor company.
30
<PAGE> 32
(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) Mr. Belden served as Chairman and Chief Executive Officer until
his resignation on June 27, 1997.
(4) Includes $9,012, $8,316 and $7,641 as the portion of the total premium
paid by the Company in 1997, 1996 and 1995, respectively, under a
split-dollar insurance plan that is attributable to term life insurance
coverage for Mr. Belden.
(5) Mr. Mardick served as President and Chief Operating Officer until his
resignation on June 27, 1997.
(6) Includes stock grants amounting to $60,803.
(7) Includes stock grants amounting to $17,500 and moving expenses of
$34,269.
OPTION/SAR GRANTS IN LAST FISCAL YEAR
Individual Grants
- --------------------------------------------------------------
<TABLE>
<CAPTION>
% of Total
Options/SARs
Options/ Granted to
SARs Employees in Exercise or Expiration Grant Date
Name Granted(1) Fiscal Year Base Price Date Present Value(3)
---- ---------- ----------- ---------- ---------- ----------------
<S> <C> <C> <C> <C> <C> <C>
Ronald L. Clements 137,366(1) 21.0% $10.82 6/26/07 $243,138
Ronald E. Huff 137,366(1) 21.0% 10.82 6/26/07 243,138
Joseph M. Vitale 54,946 (2) 8.4% 10.82 11/30/07 117,035
Tommy L. Knowles 54,946 (2) 8.4% 10.82 11/30/07 117,035
Leo A. Schrider 20,000 (2) 3.1% 10.82 11/30/07 42,600
</TABLE>
(1) These options are exercisable starting 12 months after the date of
grant, with 25% of the shares covered thereby becoming exercisable at
that time and the balance becoming exercisable at the rate of 8.33% at
the end of each quarter thereafter.
(2) These options are exercisable starting 12 months after the date of
grant, with 25% of the shares covered thereby becoming exercisable at
that time and an additional 25% becoming exercisable on each successive
anniversary date. The options were granted for a term of ten years,
subject to earlier termination on cessation of employment.
(3) This is a hypothetical valuation using the Black-Scholes valuation
method. The Company's use of this model should not be considered as an
endorsement of its accuracy at valuing options. All stock option
valuation methods, including the Black-Scholes model, require a
prediction about the future movement of the stock price. Since all
options are granted at an exercise price equal to the market value of
the Company's Common Stock on the date of grant, no value will be
realized if there is no appreciation in the market price of the stock.
31
<PAGE> 33
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(2) Exercisable Unexercisable Exercisable Unexercisable
---- ------------ --------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Henry S. Belden IV 69,750 $1,063,219 63,360 -- $567,706 $ --
Max L. Mardick 41,250 625,781 39,387 -- 352,908 --
Ronald L. Clements 16,250 217,656 31,168 137,366 279,265 --
Ronald E. Huff 31,250 472,656 31,168 137,366 279,265 --
Joseph M. Vitale 70,000 806,875 -- 54,946 -- --
Tommy L. Knowles 20,000 155,000 -- 54,946 -- --
Leo A. Schrider 35,000 354,063 -- 20,000 -- --
</TABLE>
(1) There were no options exercised in 1997. The amounts shown represent
the number of shares related to options which were surrendered in
connection with the merger.
(2) Represents cash received on surrender of options equal to the amount by
which the per share amount received by shareholders in exchange for
their shares of common stock in the merger exceeded the option price.
COMPENSATION OF DIRECTORS
Directors of the Company are not compensated for their services as such
nor for their participation on any committees of the Board of Directors.
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 within three years following a
change in control. 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. 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
32
<PAGE> 34
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 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
Until June 27, 1997, the Compensation Committee of the Board of
Directors consisted of George M. Smart, Raymond D. Saunders and Gary R.
Petersen, all of whom are outside directors. Henry S. Belden IV, who was the
Chairman of and Chief Executive Officer of the Company until completion of the
merger on June 27, 1997, is a director of Phoenix Packaging Corporation of which
Mr. Smart is President and Chief Executive Officer.
33
<PAGE> 35
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
---------------------------------------------------
MANAGEMENT
----------
The following table sets forth certain information as of February 28,
1998 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.
201 Main Street, Suite 2420
Fort Worth, Texas 76102 9,353,038(1) 92.5%
State Treasurer of the State of Michigan,
Custodian of the Public School Employees'
Retirement System, State Employees Retirement
System, Michigan State Police Retirement System
and Michigan Judges Retirement System 554,376 5.5%
OFFICERS AND DIRECTORS
----------------------
William S. Price, III 9,353,038 (1) 92.5%
Henry S. Belden IV 63,360 (2) *
Ronald L. Clements 31,168 (2) *
Ronald E. Huff 31,168 (2) *
Lawrence W. Kellner -0- -0-
Max L. Mardick 39,387 (2) *
Tommy L. Knowles -0- -0-
Gareth Roberts -0- -0-
David M. Stanton -0- -0-
Leo A. Schrider -0- -0-
Joseph M. Vitale -0- -0-
All directors and executive 9,518,121 94.1%
officers as a group
</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.
34
<PAGE> 36
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.
35
<PAGE> 37
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)
</TABLE>
36
<PAGE> 38
<TABLE>
<CAPTION>
<S> <C>
4.1 Indenture dated as of June 27, 1997 between the Company, the
Subsidiary Guarantors and LaSalle National Bank, as trustee,
relating to the Notes--incorporated by reference to Exhibit
4.1 to the Company's Registration Statement on Form S-4
(Registration No. 333-33407)
4.2 Registration Rights Agreement dated as of June 27, 1997
between the Company, the Guarantors and Chase Securities, Inc.
--incorporated by reference to Exhibit 4.2 to the Company's
Registration Statement on Form S-4 (Registration No.
333-33407)
4.3 Form of 9 7/8% Senior Subordinated Notes due 2007, Original
Notes (included in Exhibit 4.1)--incorporated by reference to
Exhibit 4.3 to the Company's Registration Statement on Form
S-4 (Registration No. 333-33407)
4.4 Form of 9 7/8% Senior Subordinated Notes due 2007, Exchange
Notes (included in Exhibit 4.1)--incorporated by reference
to Exhibit 4.4 to the Company's Registration Statement on Form
S-4 (Registration No. 333-33407)
10.1 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, Independent Auditors
27* Financial Data Schedule
*Filed herewith
</TABLE>
37
<PAGE> 39
(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.
38
<PAGE> 40
SIGNATURES
----------
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
BELDEN & BLAKE CORPORATION
March 25, 1998 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.
/s/ Ronald L. Clements Chief Executive Officer March 25, 1998
- -------------------------- and Director --------------
Ronald L. Clements (Principal Executive Officer) Date
/s/ Ronald E. Huff President, Chief Financial March 25, 1998
- -------------------------- Officer and Direct --------------
Ronald E. Huff (Principal Financial and Date
Accounting Officer)
/s/ Joseph M. Vitale Senior Vice President Legal, March 25, 1998
- -------------------------- General Counsel, --------------
Joseph M. Vitale Secretary and Director Date
Director March 25, 1998
- -------------------------- --------------
Henry S. Belden IV Date
/s/ Lawrence W. Kellner Director March 25, 1998
- -------------------------- --------------
Lawrence W. Kellner Date
/s/ Max L. Mardick Director March 25, 1998
- -------------------------- --------------
Max L. Mardick Date
Director March 25, 1998
- -------------------------- --------------
William S. Price Date
39
<PAGE> 41
Director March 25, 1998
- ---------------------- ---------------------
Gareth Roberts Date
/s/ David M. Stanton Director March 25, 1998
- ---------------------- ---------------------
David M. Stanton Date
40
<PAGE> 42
<TABLE>
<CAPTION>
BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES
ITEM 14(a) (1) AND (2)
PAGE
----
CONSOLIDATED FINANCIAL STATEMENTS
- ---------------------------------
<S> <C>
Report of Independent Auditors....................................................................... F-2
Consolidated Balance Sheet as of December 31, 1997 (Successor Company) .............................. F-3
Consolidated Statements of Operations:
Six months ended December 31, 1997 (Successor Company)
Six months ended June 30, 1997 (Predecessor Company)
Years ended December 31, 1996 and 1995 (Predecessor Company) ..................................... F-4
Consolidated Statements of Shareholders' Equity:
Six months ended December 31, 1997 (Successor Company)
Six months ended June 30, 1997 (Predecessor Company)
Years ended December 31, 1996 and 1995 (Predecessor Company) ..................................... F-5
Consolidated Statements of Cash Flows:
Six months ended December 31, 1997 (Successor Company)
Six months ended June 30, 1997 (Predecessor Company)
Years ended December 31, 1996 and 1995 (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> 43
REPORT OF INDEPENDENT AUDITORS
To the Shareholders and Board of Directors
Belden & Blake Corporation
We have audited the accompanying consolidated balance sheet of Belden & Blake
Corporation ("Successor Company") as of December 31, 1997, and the related
consolidated statements of operations, shareholders' equity and cash flows for
the six month period ended December 31, 1997 ("Successor period"). We have also
audited the accompanying consolidated statements of operations, shareholders'
equity and cash flows of Belden & Blake Corporation ("Predecessor Company") for
the six month period ended June 30, 1997 and each of the two years in the period
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, 1997 and the consolidated results of their
operations and their cash flows for the Successor period and the Predecessor
periods in conformity with generally accepted accounting principles.
ERNST & YOUNG LLP
Cleveland, Ohio
March 5, 1998
F-2
<PAGE> 44
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEET
December 31, 1997
(in thousands)
<TABLE>
<CAPTION>
ASSETS
- ------
CURRENT ASSETS
<S> <C>
Cash and cash equivalents $ 6,552
Accounts receivable, net 35,743
Inventories 9,614
Deferred income taxes 2,702
Other current assets 4,052
---------------
TOTAL CURRENT ASSETS 58,663
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 499,864
Gas gathering systems 20,713
Land, buildings, machinery and equipment 25,602
---------------
546,179
Less accumulated depreciation, depletion and amortization 31,036
---------------
PROPERTY AND EQUIPMENT, NET 515,143
OTHER ASSETS 25,514
---------------
$ 599,320
===============
LIABILITIES AND SHAREHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES
Accounts payable $ 9,078
Accrued expenses 28,442
Current portion of long-term liabilities 1,297
---------------
TOTAL CURRENT LIABILITIES 38,817
LONG-TERM LIABILITIES
Bank and other long-term debt 126,269
Senior subordinated notes 225,000
Other 4,380
---------------
355,649
DEFERRED INCOME TAXES 107,996
SHAREHOLDERS' EQUITY
Common stock without par value; $.10 stated
value per share; authorized 58,000,000 shares;
issued and outstanding 10,000,000 shares 1,000
Paid in capital 107,230
Deficit (11,372)
---------------
TOTAL SHAREHOLDERS' EQUITY 96,858
---------------
$ 599,320
===============
</TABLE>
See accompanying notes.
F-3
<PAGE> 45
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
<TABLE>
<CAPTION>
Successor |
Company | Predecessor Company
-------------- | ----------------------------------------------
Six months | Six months Year Year
ended | ended ended ended
December 31, | June 30, December 31, December 31,
1997 | 1997 1996 1995
============== | ============== ============== ==============
REVENUES |
<S> <C> | <C> <C> <C>
Oil and gas sales $ 44,165 | $ 41,591 $ 79,491 $ 46,853
Gas marketing and gathering 22,714 | 21,657 44,527 40,436
Oilfield sales and service 15,541 | 14,665 25,517 20,066
Interest and other 1,706 | 1,484 3,700 2,712
-------------- | -------------- -------------- --------------
84,126 | 79,397 153,235 110,067
EXPENSES |
Production expense 11,338 | 10,158 18,098 11,756
Production taxes 1,525 | 1,647 3,168 2,060
Cost of gas and gathering expense 19,444 | 18,340 37,556 33,831
Oilfield sales and service 14,085 | 13,936 23,142 18,266
Exploration expense 5,980 | 4,380 6,064 4,924
General and administrative expense 1,813 | 2,445 4,573 3,802
Depreciation, depletion and amortization 31,694 | 15,366 29,752 19,717
Franchise, property and other taxes 967 | 908 1,739 1,228
-------------- | -------------- -------------- --------------
86,846 | 67,180 124,092 95,584
-------------- | -------------- -------------- --------------
OPERATING (LOSS) INCOME (2,720) | 12,217 29,143 14,483
|
Interest expense 15,417 | 3,715 7,383 6,073
Transaction-related expenses | 16,758
-------------- | -------------- -------------- --------------
15,417 | 20,473 7,383 6,073
-------------- | -------------- -------------- --------------
(LOSS) INCOME FROM CONTINUING |
OPERATIONS BEFORE INCOME TAXES (18,137) | (8,256) 21,760 8,410
(Benefit) provision for income taxes (6,765) | 1,617 6,566 2,150
-------------- | -------------- -------------- --------------
(LOSS) INCOME FROM |
CONTINUING OPERATIONS (11,372) | (9,873) 15,194 6,260
LOSS FROM DISCONTINUED OPERATIONS | (439) (1,139)
-------------- | -------------- -------------- --------------
NET (LOSS) INCOME $ (11,372) | $ (9,873) $ 14,755 $ 5,121
============== | ============== ============== ==============
</TABLE>
See accompanying notes.
F-4
<PAGE> 46
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(in thousands)
<TABLE>
<CAPTION>
Successor Company Predecessor Company
=================== =======================
Common Common Common Common Preferred
Shares Stock Shares Stock Stock
========= ======== ========= ============= ==========
Predecessor Company:
<S> <C> <C> <C> <C> <C>
JANUARY 1, 1995 -- $ -- 7,085 $ 709 $ 2,400
Stock issued 4,028 403
Net income
Preferred stock dividend
Stock options exercised 2 --
Employee stock bonus 22 2
Restricted stock vested
- -------------------------------------------------------------------------------------------
DECEMBER 31, 1995 -- -- 11,137 1,114 2,400
Net income
Preferred stock dividend
Stock options exercised and
related tax benefit 3 --
Employee stock bonus 26 3
Restricted stock activity 4 --
Conversion of debentures 62 6
- -------------------------------------------------------------------------------------------
DECEMBER 31, 1996 -- -- 11,232 1,123 2,400
Net loss
Preferred stock redeemed (2,400)
Preferred stock dividend
Subordinated debentures
converted to common stock 275 27
Stock options exercised and surrendered
and related tax benefit 1 --
Employee stock bonus 36 4
Restricted stock activity
Redemption of common stock (11,544) (1,154)
Sale of common stock 10,000 1,000
SUCCESSOR COMPANY:
- -------------------------------------------------------------------------------------------
JUNE 30, 1997 10,000 1,000 -- -- --
Net loss
- -------------------------------------------------------------------------------------------
DECEMBER 31, 1997 10,000 $ 1,000 -- $ -- $ --
===========================================================================================
<CAPTION>
Retained Unearned
Paid in Earnings Restricted
Capital (Deficit) Stock Total
============ ============ ========== ============
Predecessor Company:
<S> <C> <C> <C> <C>
January 1, 1995 $ 70,379 $ 7,879 $ (225) $ 81,142
Stock issued 55,264 55,667
Net income 5,121 5,121
Preferred stock dividend (180) (180)
Stock options exercised 25 25
Employee stock bonus 251 253
Restricted stock vested 144 119 263
- --------------------------------------------------------------------------------------
December 31, 1995 126,063 12,820 (106) 142,291
Net income 14,755 14,755
Preferred stock dividend (180) (180)
Stock options exercised and
related tax benefit 47 47
Employee stock bonus 418 421
Restricted stock activity 263 71 334
Conversion of debentures 1,244 1,250
- --------------------------------------------------------------------------------------
December 31, 1996 128,035 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 5,523 5,550
Stock options exercised and
surrendered and related
tax benefit 1,596 1,596
Employee stock bonus 926 930
Restricted stock activity 17 35 52
Redemption of common stock (136,097) (17,477) (154,728)
Sale of common stock 107,230 108,230
Successor Company:
- --------------------------------------------------------------------------------------
June 30, 1997 107,230 -- -- 108,230
Net loss (11,372) (11,372)
- --------------------------------------------------------------------------------------
December 31, 1997 $ 107,230 $ (11,372) $ -- $ 96,858
======================================================================================
</TABLE>
See accompanying notes.
F-5
<PAGE> 47
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
<TABLE>
<CAPTION>
Successor |
Company | Predecessor Company
-------------------- | --------------------------------------------------
Six months | Six months Year Year
ended | ended ended ended
December 31, | June 30, December 31, December 31,
1997 | 1997 1996 1995
==================== | ================ ================ ===============
CASH FLOWS FROM OPERATING ACTIVITIES: |
<S> <C> | <C> <C> <C>
Net (loss) income $ (11,372) | $ (9,873) $ 14,755 $ 5,121
Adjustments to reconcile net (loss) income to net cash |
provided by operating activities: |
Depreciation, depletion and amortization 31,694 | 15,366 29,752 20,154
Transaction-related expenses | 15,903
Loss on disposal of property and equipment 51 | 356 534 177
Deferred income taxes (6,379) | 3,125 4,232 488
Deferred compensation and stock grants 380 | 1,756 1,311 1,067
Change in operating assets and liabilities, net of |
effects of purchases of businesses: |
Accounts receivable and other operating assets (5,280) | 1,237 (4,385) (14,485)
Inventories 597 | 112 (144) 469
Accounts payable and accrued expenses (4,064) | 4,800 476 8,958
-------------------- | ---------------- ---------------- ---------------
NET CASH PROVIDED BY OPERATING ACTIVITIES 5,627 | 32,782 46,531 21,949
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
Acquisition of businesses, net of cash acquired (14,276) | (9,263) (4,543) (99,837)
Proceeds from property and equipment disposals 785 | 704 2,227 589
Additions to property and equipment (23,663) | (18,419) (37,074) (23,855)
Increase in other assets (274) | (9,496) (705) (867)
-------------------- | ---------------- ---------------- ---------------
NET CASH USED IN INVESTING ACTIVITIES (37,428) | (36,474) (40,095) (123,970)
|
CASH FLOW FROM FINANCING ACTIVITIES: |
Proceeds from revolving line of credit and long-term debt | 46,000 16,105 73,000
Proceeds from new credit agreement 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 (2,989) | (140,325) (26,117) (17,818)
Payment to shareholders and optionholders | (312,164)
Transaction-related expenses | (15,903)
Preferred stock redeemed | (2,400)
Preferred stock dividends | (45) (180) (180)
Proceeds from sale of common stock and stock options | 15 40 59,438
Common stock placement cost | (3,746)
-------------------- | ---------------- ---------------- ---------------
NET CASH PROVIDED BY (USED IN) |
FINANCING ACTIVITIES 21,031 | 12,408 (10,152) 110,694
-------------------- | ---------------- ---------------- ---------------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (10,770) | 8,716 (3,716) 8,673
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 17,322 | 8,606 12,322 3,649
-------------------- | ---------------- ---------------- ---------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 6,552 | $ 17,322 $ 8,606 $ 12,322
==================== | ================ ================ ===============
</TABLE>
See accompanying notes.
F-6
<PAGE> 48
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 period 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 and 1995 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.
Following are unaudited pro forma results of operations as if the
merger occurred at the beginning of 1996 (in thousands):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------------
1997 1996
-------------- -------------
<S> <C> <C>
Total revenues $ 163,523 $ 153,235
Loss from continuing operations (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 a
total value of $3.0 million. 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 the acquisition, exploration, development and
production of oil and gas reserves, and the gathering and marketing of natural
gas. Sales of oil are ultimately made to refineries. Sales of gas are ultimately
made to industrial 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
F-7
<PAGE> 49
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 average cost.
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.
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
F-8
<PAGE> 50
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.
INTANGIBLE ASSETS
These costs ($22,611,000) 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."
(3) NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. (SFAS) 130, "Reporting Comprehensive
Income" and Statement of Financial Accounting Standards No. (SFAS) 131,
"Disclosures about Segments of an Enterprise and Related Information." The
Company will adopt these statements in 1998.
SFAS 130 establishes standards for reporting and displaying
comprehensive income and its components in general-purpose financial statements.
The Company does not believe this pronouncement will have a material impact on
its 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. The Company will begin presenting any
additional information required by the Statement in its financial statements for
the year ended December 31, 1998.
(4) ACQUISITIONS
F-9
<PAGE> 51
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 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 time of the
acquisitions.
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.
Effective July 1995, the Company purchased from Quaker State
Corporation most of its oil and gas properties and related assets in the
Appalachian Basin (the "Quaker State Properties") for approximately $50 million.
The Quaker State Properties included approximately 1,460 gross (1,100 net) wells
with estimated proved reserves of 2.2 Mmbbl of oil and 46.8 Bcf of gas at
December 31, 1994, approximately 250 miles of gas gathering systems, undeveloped
oil and gas leases and fee mineral interests covering approximately 250,000
acres, an extensive geologic and geophysical database and other assets.
In January 1995, the Company purchased Ward Lake Drilling, Inc. ("Ward
Lake"), a privately-held exploration and production company headquartered in
Gaylord, Michigan, for $15.1 million. At the time of acquisition Ward Lake
operated and held a production payment interest and working interests averaging
13.6% in approximately 500 Antrim Shale gas wells located in Michigan's lower
peninsula. The purchase also included approximately 5,500 undeveloped leasehold
acres that Ward Lake owns in Michigan. At December 31, 1994, the wells had
estimated proved developed natural gas reserves totaling 98 Bcf (14 Bcf net to
the Company's interest). Approximately one half of the purchase price
represented payment for the proved reserves, with the balance associated with
other oil and gas and corporate assets. Through the end of 1996, the Company
purchased additional working interests averaging 24% in the wells operated by
Ward Lake for approximately $12 million. The interests acquired had estimated
proved developed reserves of 16 Bcf at December 31, 1994.
In addition, during 1995 the Company, in four separate transactions,
acquired for approximately $29.2 million working interests in oil and gas wells
in Michigan, Ohio, Pennsylvania and New York and drilling rights on more than
250,000 acres in Ohio. Estimated proved developed reserves associated with the
wells totaled 35 Bcfe of natural gas net to the Company's interest at December
31, 1994.
The unaudited pro forma results of operations for the year ended
December 31, 1995 as if the acquisitions above occurred at the beginning of the
period are as follows: revenues of $124.9 million and net income of $8.5
million. The pro forma effects of the 1997 (predecessor and successor periods)
and the 1996 acquisitions were not material.
F-10
<PAGE> 52
<TABLE>
<CAPTION>
(5) DETAILS OF BALANCE SHEET
DECEMBER 31,
1997
-----------------
ACCOUNTS RECEIVABLE (IN THOUSANDS)
<S> <C>
Accounts receivable $ 20,234
Allowance for doubtful accounts (948)
Oil and gas production receivable 15,959
Current portion of notes receivable 498
-----------------
$ 35,743
=================
INVENTORIES
Oil $ 2,429
Natural gas 387
Material, pipe and supplies 6,798
-----------------
$ 9,614
=================
PROPERTY AND EQUIPMENT, GROSS
OIL AND GAS PROPERTIES
Producing properties $ 466,491
Non-producing properties 12,792
Other 20,581
-----------------
$ 499,864
=================
LAND, BUILDINGS, MACHINERY AND EQUIPMENT
Land, buildings and improvements $ 8,530
Machinery and equipment 17,072
-----------------
$ 25,602
=================
ACCRUED EXPENSES
Accrued expenses $ 11,126
Accrued drilling and completion costs 3,736
Ad valorem and other taxes 4,020
Compensation and related benefits 3,524
Undistributed production revenue 6,036
-----------------
$ 28,442
=================
(6) LONG-TERM DEBT
Long-term debt consists of the following (in thousands):
DECEMBER 31,
1997
-----------------
New credit agreement $ 126,000
Senior subordinated notes 225,000
Other 418
-----------------
351,418
Less current portion 149
-----------------
Long-term debt $ 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 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 new 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
F-11
<PAGE> 53
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>
<S> <C>
YEAR PERCENTAGE
---- ----------
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 new 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 new credit agreement is a senior revolving credit facility which
is secured by substantially all of the Company's assets. The initial borrowing
base has been set at $180 million. 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 borrowed $104 million under the
new credit agreement 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 new 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 7.219% at December 31, 1997.
The new credit agreement contains a number of covenants that, among
other things, restrict 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
F-12
<PAGE> 54
activities. In addition, under the new credit agreement, the Company is required
to maintain specified financial ratios and tests, including minimum interest
coverage ratios and maximum leverage ratios.
In connection with the senior subordinated notes and the new 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. The Company
had no such derivative financial instruments at December 31, 1996 or 1995. 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.
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 $94.0 million.
At December 31, 1997, the aggregate long-term debt maturing in the next
five years is as follows: $149,000 (1998); $99,000 (1999); $18,000 (2000);
$18,000 (2001); $126,019,000 (2002); and $225,115,000 (2003 and thereafter).
(7) 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 $1.0 million for the successor company's six months
ended December 31, 1997, $1.0 million, $1.6 million and $1.4 million for the
predecessor company's six months ended June 30, 1997 and the years ended
December 31, 1996 and 1995, respectively. Future commitments under leasing
arrangements were not significant at December 31, 1997.
(8) SHAREHOLDERS' EQUITY
In November 1997, the Company awarded 110,915 shares of successor
company common stock to employees as profit sharing and bonuses. These shares
were issued in February 1998.
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
F-13
<PAGE> 55
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 and 1995, the Company awarded 36,077 and 26,085 shares
of predecessor company common stock, respectively, to employees as profit
sharing and bonuses. These shares were issued in each subsequent year.
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.
(9) 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, 1997, there were
171,571 shares available for grant under the Plan.
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. Options for 2,000 shares
will be granted each year to each non-employee director. 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. Currently, non-employee directors of the Company are not
compensated for their services.
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.
F-14
<PAGE> 56
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 1995,
1996 and 1997 (predecessor and successor periods), respectively: risk-free
interest rates of 6.4%, 6.5% and 6.1%; volatility factors of the expected market
price of the Company's common stock of .36, .36 and near zero; dividend yield of
zero; and a weighted-average expected life of the option of seven years.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its stock options.
For purposes of 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 $11,432,000 for the successor company's six months ended December 31, 1997,
net loss of $12,387,000, net income of $14,286,000 and $5,016,000 for the
predecessor company's six months ended June 30, 1997 and the years ended
December 31, 1996 and 1995, 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.
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>
BALANCE AT DECEMBER 31, 1994 | 288,000 $ 11.59
Granted | 260,000 16.37
Exercised | (2,250) 11.32
Forfeited | (1,000) 10.00
| ------------
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 | --
============ | ============
OPTIONS EXERCISABLE AT DECEMBER 31, 1997 165,083 $ .10 |
============ |
</TABLE>
The weighted average fair value of options granted during the years
1997, 1996 and 1995 were $1.98, $10.59 and $8.27 per share, respectively. The
exercise price for the options outstanding as of
F-15
<PAGE> 57
December 31, 1997 ranged from $.10 to $10.82 per share. At December 31, 1997 the
weighted average remaining contractual life of the outstanding options is 9.4
years.
(10) TAXES
The provision (benefit) for income taxes on continuing operations
includes the following (in thousands):
<TABLE>
<CAPTION>
<S> <C> | <C> <C> <C>
SUCCESSOR |
COMPANY | PREDECESSOR COMPANY
------------- | -----------------------------------------
SIX MONTHS | SIX MONTHS
ENDED | ENDED YEAR ENDED
DECEMBER 31 | JUNE 30 DECEMBER 31
1997 | 1997 1996 1995
------------- | --------------- ------------ -----------
CURRENT |
Federal $ (345) | $ (1,397) $ 2,011 $ 1,103
State (41) | (111) 217 111
------------- | --------------- ------------ -----------
(386) | (1,508) 2,228 1,214
DEFERRED |
Federal (6,038) | 2,945 4,257 826
State (341) | 180 81 110
------------- | --------------- ------------ -----------
(6,379) | 3,125 4,338 936
------------- | --------------- ------------ -----------
TOTAL $ (6,765) | $ 1,617 $ 6,566 $ 2,150
============= | =============== ============ ===========
</TABLE>
The effective tax rate for continuing operations differs from the U.S.
federal statutory tax rate as follows:
<TABLE>
<CAPTION>
<S> <C> | <C> <C> <C>
SUCCESSOR |
COMPANY | PREDECESSOR COMPANY
------------ | ----------------------------------------
SIX MONTHS | SIX MONTHS
ENDED | ENDED YEAR ENDED
DECEMBER 31 | JUNE 30 DECEMBER 31
1997 | 1997 1996 1995
------------ | ------------ ------------ ------------
Statutory federal income tax rate 35.0 % | 35.0 % 35.0 % 34.0 %
Increases (reductions) in taxes resulting from: |
State income taxes, net of federal tax |
benefit 2.0 | (.8) 1.9 1.7
Nonconventional fuel source tax credits -- | (3.8) (5.9) (10.0)
Transaction-related expenses -- | (49.9) -- --
Statutory depletion 0.5 | -- (0.6) (0.3)
Other, net (0.2) | -- (0.2) 0.2
|
------------ | ------------ ------------ ------------
Effective income tax rate for the period 37.3 % | (19.5) % 30.2 % 25.6 %
============ | ============ ============ ============
</TABLE>
F-16
<PAGE> 58
Significant components of deferred income tax liabilities and assets
are as follows (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31
1997
--------------
Deferred income tax liabilities:
<S> <C>
Property and equipment, net $ 119,650
Other, net 433
--------------
Total deferred income tax liabilities 120,083
Deferred income tax assets:
Accrued expenses 2,195
Inventories 80
Net operating loss carryforwards 12,019
Tax credit carryforwards 1,895
Other, net 463
Valuation allowance (1,863)
--------------
Total deferred income tax assets 14,789
--------------
Net deferred income tax liability $ 105,294
==============
Long-term liability $ 107,996
Current asset (2,702)
--------------
Net deferred income tax liability $ 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, 1997 relates principally to
certain net operating loss carryforwards of the predecessor which management
estimates will expire before they can be utilized.
At December 31, 1997, the Company had approximately $33 million of net
operating loss carryforwards available for federal income tax reporting
purposes. Approximately $4 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. The
Company has alternative minimum tax credit carryforwards of approximately $1.8
million which have no expiration date. The Company has approximately $500,000 of
statutory depletion carryforwards, which have no expiration date.
(11) 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 $749,500 for
the successor company's six months ended December 31, 1997, $588,900, $1,256,600
and $458,000 for the predecessor company's six months ended June 30, 1997 and
the years ended December 31, 1996 and 1995, 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 $.25 for every $1.00 contributed up to 6% of an
employee's annual compensation. Effective January 1, 1998, the Company increased
its match to $.50 for every $1.00
F-17
<PAGE> 59
contributed up to 6% of an employee's annual compensation. Retirement plan
expense amounted to $285,000 for the successor company's six months ended
December 31, 1997, $266,000, $457,000 and $372,000 for the predecessor company's
six months ended June 30, 1997 and the years ended December 31, 1996 and 1995,
respectively.
The Company also has non-qualified deferred compensation plans which
permit certain key employees to elect to defer a portion of their compensation.
(12) 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.
(13) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
<TABLE>
<CAPTION>
<S> <C> |<C> <C> <C>
SUCCESSOR |
COMPANY | PREDECESSOR COMPANY
------------- | -----------------------------------
SIX MONTHS | SIX MONTHS YEAR ENDED
ENDED | ENDED DECEMBER 31
DECEMBER 31 | JUNE 30 ----------------------
(IN THOUSANDS) 1997 | 1997 1996 1995
------------- | ---------- ---------- ---------
CASH PAID DURING THE PERIOD FOR: |
Interest $ 13,867 | $ 4,153 $ 7,830 $ 5,592
Income taxes (1,517) | 288 1,222 1,296
NON-CASH INVESTING AND FINANCING ACTIVITIES: |
Acquisition of assets in exchange for |
long-term liabilities -- | 792 -- 8,460
Debentures converted to common stock -- | 5,550 1,250 --
</TABLE>
(14) FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of the financial instruments disclosed herein is not
representative of the amount that could be realized or settled, nor does the
fair value amount consider the tax consequences, if any, of realization or
settlement. The amounts in the financial statements for cash equivalents,
accounts receivable and notes receivable approximate fair value due to the short
maturities of these instruments. The recorded amounts of outstanding bank and
other long term debt approximate fair value because interest rates are based on
LIBOR or the prime rate or due to the short maturities. The $225,000,000 in
senior subordinated notes had an approximate fair value of $228,375,000 at
December 31, 1997 based on rates available for similar instruments. The fair
value of interest rate swaps was not material at December 31, 1997.
F-18
<PAGE> 60
(15) 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
--------------- | --------------------------------------------------
SIX MONTHS | SIX MONTHS
|
ENDED | ENDED YEAR ENDED
|
DECEMBER 31 | JUNE 30 DECEMBER 31
| ---------------------------------
(IN THOUSANDS) 1997 | 1997 1996 1995
--------------- | --------------- --------------- ---------------
Acquisition costs |
<S> <C> |<C> <C> <C>
Proved properties $ 13,501 | $ 9,249 $ 4,275 $ 79,464
Unproved properties 1,342 | 1,267 2,320 4,705
Developmental costs 21,822 | 11,322 30,750 19,906
Exploratory costs 5,980 | 4,380 6,131 4,968
</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 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, 1997
proved undeveloped reserves have been reviewed by independent petroleum
engineers.
F-19
<PAGE> 61
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, 1994 4,113,470 122,991,609 4,113,470 122,991,609
Extensions and discoveries 229,957 22,287,564 229,957 22,287,564
Purchase of reserves in place 2,197,414 111,360,991 2,197,414 111,360,991
Sale of reserves in place (28,693) (278,013) (28,693) (278,013)
Revisions of previous estimates 326,771 (419) 326,771 (419)
Production (555,913) (16,961,424) (555,913) (16,961,424)
------------ ------------ ------------ ------------
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
============ ============ ============ ============ ============ ============
PROVED DEVELOPED RESERVES
December 31, 1995 5,592,579 206,998,924 5,592,579 206,998,924
============ ============ ============ ============
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
============ ============ ============ ============
</TABLE>
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.
F-20
<PAGE> 62
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves is presented below:
<TABLE>
<CAPTION>
DECEMBER 31
------------------------------------------------
1997 1996 1995
-------------- -------------- --------------
(IN THOUSANDS)
Estimated future cash inflows (outflows)
<S> <C> <C> <C>
Revenues from the sale of oil and gas $ 876,464 $ 1,087,997 $ 679,286
Production and development costs (355,165) (419,504) (293,601)
-------------- -------------- --------------
Future net cash flows before income taxes 521,299 668,493 385,685
Future income taxes (130,306) (185,768) (80,715)
-------------- -------------- --------------
Future net cash flows 390,993 482,725 304,970
10% timing discount (171,273) (223,496) (134,053)
-------------- -------------- --------------
Standardized measure of discounted
future net cash flows $ 219,720 $ 259,229 $ 170,917
============== ============== ==============
</TABLE>
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
-----------------------------------------------
1997 1996 1995
------------- ------------- ---------------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning of year $ 259,229 $ 170,917 $ 89,854
Sale of oil and gas, net of
production costs (61,088) (58,023) (32,874)
Extensions and discoveries, less
related estimated future
development and production costs 54,979 60,738 24,441
Purchase of reserves in place less
estimated future production costs 33,233 10,694 104,270
Sale of reserves in place less
estimated future production costs (588) (191) (329)
Revisions of previous quantity estimates (43,111) 38,204 1,129
Net changes in prices and production costs (73,956) 83,530 (4,723)
Change in income taxes 19,618 (55,494) (17,756)
Accretion of 10% timing discount 35,596 21,425 11,647
Changes in production rates (timing)
and other (4,192) (12,571) (4,742)
------------- ------------- ---------------
End of year $ 219,720 $ 259,229 $ 170,917
============= ============= ===============
</TABLE>
F-21
<PAGE> 63
(16) INDUSTRY SEGMENT FINANCIAL INFORMATION
The table below presents certain financial information regarding the
Company's industry segments of its continuing operations. Intersegment sales are
billed on an intercompany basis at prices for comparable third party goods and
services.
<TABLE>
<CAPTION>
SUCCESSOR |
COMPANY | PREDECESSOR COMPANY
---------- | ------------------------------------
SIX MONTHS | SIX MONTHS
ENDED | ENDED YEAR ENDED DECEMBER 31
DECEMBER 31| JUNE 30 -----------------------
(IN THOUSANDS) 1997 | 1997 1996 1995
---------- | ---------- ---------- ----------
REVENUES |
<S> <C> | <C> <C> <C>
Oil and gas operations $ 66,958 | $ 63,248 $ 124,294 $ 88,632
Oilfield sales and service 19,929 | 18,698 32,827 25,178
Intersegment sales (4,388) | (4,033) (7,310) (5,112)
|
--------- | --------- --------- ---------
$ 82,499 | $ 77,913 $ 149,811 $ 108,698
========= | ========= ========= =========
OPERATING INCOME |
Oil and gas operations $ (4,872) | $ 10,757 $ 24,756 $ 12,444
Oilfield sales and service 525 | (24) 963 673
--------- | --------- --------- ---------
$ (4,347) | $ 10,733 $ 25,719 $ 13,117
========= | ========= ========= =========
IDENTIFIABLE ASSETS |
Oil and gas operations $ 572,170 | $ 281,761 $ 274,021
Oilfield sales and service 27,150 | 20,492 20,348
--------- | --------- ---------
$ 599,320 | $ 302,253 $ 294,369
========= | ========= =========
DEPRECIATION, DEPLETION AND |
AMORTIZATION EXPENSE |
Oil and gas operations $ 30,923 | $ 14,777 $ 28,598 $ 18,729
Oilfield sales and service 771 | 589 1,154 988
--------- | --------- --------- ---------
$ 31,694 | $ 15,366 $ 29,752 $ 19,717
========= | ========= ========= =========
CAPITAL EXPENDITURES |
Oil and gas operations $ 37,235 | $ 27,184 $ 35,486 $ 129,219
Oilfield sales and service 541 | 1,428 1,240 4,735
--------- | --------- --------- ---------
$ 37,776 | $ 28,612 $ 36,726 $ 133,954
========= | ========= ========= =========
</TABLE>
No customer exceeded 10% of consolidated revenue during the periods
ended June 30, 1997 and December 31, 1997 and the year ended December 31, 1996.
One customer exceeded 10% of consolidated revenue during the year ended December
31, 1995 which amounted to $11.1 million.
F-22
<PAGE> 64
(17) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The results of operations for the four quarters of 1997 and 1996 are
shown below (in thousands).
<TABLE>
<CAPTION>
PREDECESSOR COMPANY | SUCCESSOR COMPANY
---------------------------- | --------------------------
FIRST SECOND | THIRD FOURTH
------------ ------------ | ----------- ------------
1997 |
---- |
<S> <C> <C> | <C> <C>
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)
PREDECESSOR COMPANY
----------------------------------------------------------
FIRST SECOND THIRD FOURTH
------------ ------------ ----------- ------------
1996
----
Sales and other operating revenues $ 38,359 $ 32,542 $ 36,571 $ 42,339
Gross profit 7,965 7,087 7,270 8,966
Net income 3,425 3,402 3,186 4,742
</TABLE>
(18) 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 $1,001,000 ($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.
(19) SALE OF TAX CREDIT PROPERTIES
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.
(20) HEDGING ACTIVITIES
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 pretax losses on its hedging
activities of $116,000 in 1997 and $258,000 in 1996.
During October 1997, the Company hedged 3.1 Bcf of 1998 gas production
at a weighted average NYMEX price of $2.37 per Mcf which represented a net
unrealized gain of $422,000 at December 31, 1997. At December 31, 1996, the
Company did not have any open futures contracts. During February
F-23
<PAGE> 65
1998, the Company hedged 1.4 Bcf of 1998 and 1999 gas production at a weighted
average NYMEX price of $2.44 per Mcf.
(21) SUBSEQUENT EVENTS (UNAUDITED)
On March 19, 1998, the Company entered into an agreement 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 for,
development, production, transportation and marketing of natural gas. Under the
agreement, the Company will provide FE Holdings with its gas marketing,
operational and management expertise.
FirstEnergy, a diversified energy services holding company
headquartered in Akron, Ohio, comprises the nation's twelfth largest
investor-owned electric utility system. Its electric utility operating companies
- -- Ohio Edison Company and its subsidiary, Pennsylvania Power Company; The
Illuminating Company; and Toledo Edison Company -- serve 2.2 million customers
within 13,200 square miles of northern and central Ohio and western
Pennsylvania. FirstEnergy produces approximately $5 billion in annual revenues
and owns more than $18 billion in assets, including ownership in 18 power
plants. In an expansion of its energy-related products and services, FirstEnergy
in December 1997 acquired Roth Bros., Inc., and RPC Mechanical, Inc., which form
one of the nation's largest providers of engineered heating, ventilating and
air-conditioning equipment and energy management and control systems.
The joint venture is expected to substantially expand the Company's
market outlet for its production of natural gas and more fully utilize the
capabilities and capacity of the Company's Gas Marketing Division. The venture
will allow FirstEnergy to offer its customers total energy services, including
natural gas, electricity and related energy products and services.
The Company and FirstEnergy have also agreed to have FE Holdings
acquire Marbel Energy Corporation ("Marbel"), a privately-held, fully integrated
natural gas company headquartered in Canton, Ohio. Marbel owns interests in more
than 1,800 gas and oil wells and holds interests in more than 200,000
undeveloped acres in eastern and central Ohio. Marbel's subsidiaries include MB
Operating Company, Inc., a natural gas exploration and production company, and
Northeast Ohio Operating Companies, Inc. ("NOOC"), a public utility holding
company based in Lancaster, Ohio. NOOC owns and operates over 1,300 miles of gas
gathering lines and a local gas distribution company with more than 3,000
customers in eastern and central Ohio.
The acquisition of Marbel will provide FE Holdings with a base of
exploration, development and production capability, along with utility
transportation and distribution capability. Marbel's net production in 1997 was
approximately 6.3 Bcfe. At September 30, 1997, Marbel had estimated proved
developed oil and gas reserves of 55.7 Bcfe.
F-24
<PAGE> 1
Exhibit 21
SUBSIDIARIES OF THE REGISTRANT
SUBSIDIARY STATE OF INCORPORATION
The Canton Oil & Gas Company Ohio
Target Oilfield Pipe & Supply Company Ohio
Ward Lake Drilling, Inc. Michigan
Peake Energy, Inc. Delaware
As of December 31, 1997, 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
Exhibit 23
CONSENT OF INDEPENDENT AUDITORS
To the Shareholders and Board of Directors
Belden & Blake Corporation
We consent to the incorporation by reference of our report dated March 5,
1998, with respect to the consolidated financial statements of Belden & Blake
Corporation included in the Annual Report (Form 10-K) for the year ended
December 31, 1997, in the following Registration Statements and related
Prospectuses.
REGISTRATION
NUMBER DESCRIPTION OF REGISTRATION STATEMENT
- ----------------------- ----------------------------------------------------
33-62785 Stock Option Plan; Non-Employee Director Stock
Option Plan -- Form S-8
33-69802 Employee's 401(K) Profit Sharing Plan -- Form S-8
ERNST & YOUNG LLP
Cleveland, Ohio
March 23, 1998
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 0000880114
<NAME> BELDEN & BLAKE CORPORATION
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<EXCHANGE-RATE> 1
<CASH> 6,552
<SECURITIES> 0
<RECEIVABLES> 35,743
<ALLOWANCES> 0
<INVENTORY> 9,614
<CURRENT-ASSETS> 58,663
<PP&E> 546,179
<DEPRECIATION> 31,036
<TOTAL-ASSETS> 599,320
<CURRENT-LIABILITIES> 38,817
<BONDS> 355,649
0
0
<COMMON> 1,000
<OTHER-SE> 95,858
<TOTAL-LIABILITY-AND-EQUITY> 599,320
<SALES> 160,333
<TOTAL-REVENUES> 163,523
<CGS> 90,473
<TOTAL-COSTS> 90,473
<OTHER-EXPENSES> 80,311
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 19,132
<INCOME-PRETAX> (26,393)
<INCOME-TAX> (5,148)
<INCOME-CONTINUING> (21,245)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (21,245)
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
