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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
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 (I.R.S. Employer Identification Number)
of incorporation or organization)
5200 STONEHAM ROAD
NORTH CANTON, OHIO 44720
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (330) 499-1660
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act:
COMMON STOCK, WITHOUT PAR VALUE
(Title of Class)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. ________
The aggregate market value of the voting stock held by non-affiliates
of the registrant as of February 28, 1997 was $235,633,612.
The number of shares outstanding of registrant's common stock,
without par value, as of February 28, 1997 was 11,268,879.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant's Proxy Statement to be filed pursuant to
Regulation 14A with respect to the Annual Meeting of Shareholders to be held on
or about May 22, 1997 are incorporated in Part III of this Form.
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PART I
------
Item 1. BUSINESS
--------
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., 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, 1996, the Company owned interests in 7,721 gross (6,462
net) productive gas and oil wells in Ohio, West Virginia, Pennsylvania, New
York, Michigan and Kentucky with proved reserves totaling 288.6 Bcf (billion
cubic feet) of gas and 7.4 MMBbl (million barrels) of oil. The estimated future
net revenues from these reserves had a present value before income taxes of
approximately $356.0 million at December 31, 1996. At that date, the Company
held leases on 1,153,800 gross (1,019,100 net) acres, including 565,900 gross
(504,800 net) undeveloped acres.
At December 31, 1996, the Company operated more than 7,600 wells,
including wells operated for third parties. The Company owned and operated
approximately 2,760 miles of gas gathering systems with access to the commercial
and industrial gas markets of the northeastern United States at December 31,
1996. At December 31, 1996, the Company's net production was approximately 72
MMcf (million cubic feet) of gas and 1,850 Bbls (barrels) of oil per day. At
that date, the Company was marketing approximately 137 MMcf of gas per day,
consisting of its own production and gas purchased from third parties.
The Company was formed through the combination of a group of companies
and assets owned by Henry S. Belden IV with Belden & Blake Energy Company, a
master limited partnership listed on the American Stock Exchange, and Belden &
Blake International Limited, a Bermuda corporation listed on the Luxembourg
Stock Exchange. The transactions combining these entities were effected on March
31, 1992.
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, 1996, the
Company has acquired for $129.4 million producing properties with 192.9 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 $19.9 million to acquire and develop additional gas gathering
facilities. During the period from 1992 through 1996, the Company drilled 547
gross (409.9 net) wells at an aggregate cost of approximately $74.6 million for
the net wells. This drilling added 82.2 Bcfe to the Company's proved reserves.
During 1996, the Company drilled 207 gross (160.7 net) wells at a direct cost of
approximately $31.2 million for the net wells. The 1996 drilling activity added
40.4 Bcfe of proved reserves, which represents approximately 136% of 1996
production at an average cost of $.77 per Mcfe.
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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.
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 and oilfield services are provided by its Arrow Oilfield Service
division. The financial information with respect to the industry segments is
shown in Note 15 to the Consolidated Financial Statements.
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.
Since September 1995, a substantial portion of the work force was eliminated and
substantial assets were sold. The financial information with respect to
discontinued operations is presented in Note 17 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, and it
recently commenced operations in the Illinois Basin.
The Appalachian Basin is the oldest and geographically one of the
largest oil and gas producing regions in the United States. Although the
Appalachian Basin has sedimentary formations indicating the potential for oil
and gas reservoirs to depths of 30,000 feet or more, oil and gas is currently
produced primarily from shallow, highly developed blanket formations at depths
of 1,000 to 5,500 feet. Drilling success rates of the Company and others
drilling in these formations historically have exceeded 90% with production
generally lasting longer than 20 years.
The combination of long-lived production and high drilling success
rates at these shallower depths has resulted in a highly fragmented, extensively
drilled, low technology operating environment in the Appalachian Basin. As of
December 31, 1996, 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.
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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 and commenced operations in the Michigan
Basin. Ward Lake held production payment and working interests averaging 13.6%
in approximately 500 Antrim Shale gas wells operated by Ward Lake in Michigan's
lower peninsula. The purchase also included approximately 5,500 undeveloped
leasehold acres that Ward Lake owned in Michigan. Through December 31, 1996, the
Company purchased additional working interests averaging 24% in these wells. 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.
In September 1995, the Company purchased an average working interest of
78% in 24 Antrim Shale wells and a 100% working interest in undeveloped Antrim
Shale locations on approximately 17,000 leasehold acres. The wells acquired had
extended the Antrim Shale productive area to northwestern Michigan and the
undeveloped locations were in proximity to the producing wells.
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 100 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 to $1.30 per Mcf
(thousand cubic feet) above national wellhead prices. The Company's
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average wellhead gas price in 1996 was $0.31 per Mcf above the estimated average
national wellhead price.
BUSINESS STRATEGY
The Company's primary operating objective is to utilize its sizable
acreage position, technical capability and financial resources to become a
dominant oil and gas producer and natural gas marketer in its operating areas.
To accomplish this objective, the Company's specific business strategy is to:
- expand production and reserves through a balanced portfolio of
developmental and exploratory drilling;
- make strategic acquisitions of producing oil and gas properties;
- improve profitability on the production from existing and acquired
properties; and
- expand its gas gathering and marketing activities.
This strategy is intended to enable the Company to take advantage of
(i) the significant exploration and development opportunities in the deeper and
potentially more productive formations in the Appalachian, Michigan and Illinois
Basins, (ii) the Company's technical knowledge and experience in those areas,
and (iii) the availability of producing properties for sale in the Appalachian,
Michigan and Illinois Basins.
ACQUISITION OF PRODUCING PROPERTIES
The Company's acquisition strategy focuses on producing properties that
(i) the Company already owns an interest in and operates or that are
strategically located in relation to its existing operations, (ii) can be
increased in value through operating cost reductions, advanced production
technology, mechanical improvements, recompleting or reworking wells and/or the
use of enhanced and secondary recovery techniques, (iii) provide development
drilling opportunities or enhance the Company's acreage position, (iv) have the
potential for increased revenues from gas production through the Company's gas
marketing capabilities or (v) are of sufficient size to allow the Company to
operate efficiently in new areas. Using these criteria, 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
1996.
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Proved Developed Reserves (2)
-------------------------------------------------
Number of Purchase Oil Gas Combined
Period Transactions Price (1) (MBbl) (MMcf) (MMcfe)
- ------------ ---------------- ------------------ ---------- ----------- --------------
(In thousands)
1992 5 $ 23,733 466 41,477 44,241
1993 8 3,883 119 4,121 4,835
1994 11 20,274 223 26,877 28,215
1995 6 77,388 1,850 97,314 108,416
1996 3 4,103 205 6,000 7,230
---------------- ------------------ ---------- ----------- --------------
Total 33 $ 129,381 2,863 175,789 192,937
================ ================== ========== =========== ==============
- ------------
(1) Represents the portion of the purchase price allocated to proved developed reserves.
(2) MBbl - thousand barrels
MMcf - million cubic feet
MMcfe - million cubic feet equivalent
During 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 total 6.0 Bcf of natural gas
and 205,000 Bbls of oil net to the Company's interest at July 1, 1996.
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, 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.
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
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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.
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:
Year Ended December 31
--------------------------------------------------------------------
1992 1993 1994 1995 1996
---------- --------- ---------- --------- ----------
Production
Oil (thousands of Bbls) 351 453 496 556 719
Gas (Bcf) 3.7 7.4 9.6 17.0 25.4
Average sales price
Oil (per Bbl) $ 19.27 $ 17.15 $ 15.98 $ 16.78 $ 20.24
Gas (per Mcf) 2.22 2.55 2.58 2.21 2.56
Average production costs per Mcfe
(including production taxes) 0.92 0.71 0.74 0.69 0.72
Total oil and gas revenues
(in thousands) 15,046 26,631 32,574 46,853 79,491
Total production expenses
(in thousands) 5,362 7,190 9,292 13,979 21,469
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 1996, the Company drilled 155 gross (128.3 net) wells to highly
developed or shallow blanket formations in its six state operating area at a
direct cost of approximately $22.2 million for the net wells. The Company also
drilled 52 gross (32.4 net) wells to less developed and deeper formations in
1996 at a direct cost of approximately $9.0 million for the net wells. The
result of this drilling activity is shown in the tables on page 10.
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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 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 highly developed or 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 1996 are described below:
Average Drilling Average Gross
Range of and Completion Reserves
Well Depths Costs per Well per Well
--------------------- ---------------------- ---------------------
(In feet) (In thousands) (In MMcfe)
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
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The Company plans to drill approximately 200 wells to highly developed
or blanket formations in 1997.
Less Developed Formations. The Appalachian Basin has productive and
potentially productive sedimentary formations to depths of 30,000 feet or more,
but the combination of long-lived production and high drilling success rates in
the shallow formations has curbed the development of the deeper formations in
the basin. The Company believes it possesses the technological expertise and the
acreage position needed to explore the deeper formations in a cost effective
manner.
The less developed formations in the Appalachian Basin include the Knox
sequence of sandstones and dolomites which includes the Rose Run, Beekmantown
and 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. 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:
Drilling Results in the Knox Formations
--------------------------------------------------------------------------------------
Average Gross
Reserves per
Wells Drilled Wells Completed (1) Completed Well
---------------------- -----------------------
Period Gross Net Gross Net (MMcfe)
- ------------------ -------- -------- -------- ------- ---------------------
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
- ------------
(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 15 to 25 years.
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As shown in the following table, the Company's production from Knox
formation wells has increased steadily as additional wells have been drilled.
Producing Wells and Production from Knox Formations
-----------------------------------------------------------------------------
1992 1993 1994 1995 1996
----------- ------------ ------------ ------------- -------------
Number of wells in production:
Gross 16 23 41 66 82
Net 13.7 20.6 29.7 41.5 58.9
Percent of total net wells 0.4% 0.7% 0.8% 0.7% 0.9%
Annual production (net):
Oil (MBbl) 4.7 13.9 67.1 74.9 78.2
Gas (MMcf) 340 731 1,041 1,624 2,788
Combined (MMcfe) 368 814 1,444 2,074 3,257
Percent of total combined 6% 8% 11% 10% 11%
production
Productive Knox wells represented less than 1% of the Company's total
productive wells at December 31, 1996. Production from Knox wells in 1996,
however, equaled 11% 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, 1996, it held leases on
approximately 598,200 net acres overlying potential Knox drilling locations. The
Company plans to drill or participate in joint ventures to drill 39 gross (22.1
net) wells to the Knox formations in 1997.
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 25 gross (21.7 net) wells
to these formations in 1997. Certain typical characteristics of the less
developed or deeper formations drilled by the Company in 1996 are described
below:
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Average
Drilling Costs Average
------------------------- Gross
Range of Dry Completed Reserves
Formation Location Well Depths Hole Well per Well
- --------------------------- ----------- --------------- ------- ------------- --------------
(In feet) (In thousands) (In MMcfe)
Knox formations OH, NY 2,500-8,000 $130 $220 375
Niagaran Carbonate MI 4,500-5,500 275 525 1,200
Dundee Carbonate MI 3,000-3,500 330 500 900
Onondaga Limestone PA 4,000-5,500 100 175 400
Oriskany Sandstone PA, NY 5,500-7,000 150 225 500
Newburg Sandstone WV 5,500-6,000 175 275 1,000
Drilling Results. The following table sets forth drilling results with
respect to wells drilled during the past five years:
Highly Developed or Blanket Formations (1) Less Developed or Deeper Formations (2)
-------------------------------------------- --------------------------------------------
1992 1993 1994 1995 1996 1992 1993 1994 1995 1996
---- ---- ---- ---- ---- ---- ---- ---- ---- ----
Productive
Gross 4 42 58 106 153 8(4) 16(3) 22(4) 23(5) 34
Net 4.0 31.4 45.6 92.5 126.3 6.4 8.8 12.7 11.5 22.2
Dry
Gross 0 2 2 4 2 7 14 10 22 18
Net 0.0 0.7 0.4 3.2 2.0 5.1 11.4 4.8 10.7 10.2
Reserves 97 3,019 4,813 18,474 32,664 1,821 3,173 5,196 5,194 7,740
discovered-
net (MMcfe)
Approximate $170 $4,847 $5,762 $15,079 $22,198 $3,343 $3,413 $5,509 $5,284 $9,029
cost (in
thousands)
- ---------------
(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, Coalbed
Methane and Medina formations in Pennsylvania, the Medina Sandstone
formation in New York and the New Albany Shale formation in Kentucky.
(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.
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GAS GATHERING AND MARKETING
Gas Gathering. The Company operates approximately 2,760 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 $6.3 million in 1996. Direct costs
associated with gas gathering in 1996 totaled approximately $2.1 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 200
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.
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, 1996, the Company marketed approximately 137
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,
1996, 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 contract prices by selling futures contracts on the New York Merchantile
Exchange ("NYMEX"). At December 31, 1996, the Company did not have any open
futures contracts. The Company has entered into a number of market sensitive
contracts which allow it to select the price at which future months' deliveries
will be sold, based on a regional index or a negotiated positive basis above the
relevant NYMEX price. These "triggering" contracts allow the Company to
effectively hedge contract prices without selling futures contracts and take
advantage of periodic price spikes on the NYMEX.
The following table shows the type of buyer for gas marketed by the
Company at December 31, 1996:
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Marketed Gas
-----------------------------------
MMcf Percent
PURCHASER per Day of Total
- --------- ----------- ------------
End users 41.9 30.7%
Local distribution companies 54.8 40.1%
Spot markets 39.8 29.2%
----------- ------------
Total 136.5 100.0%
=========== ============
OILFIELD SALES AND SERVICE
The Company has provided its own oilfield services for more than 30
years in order to assure quality control and operational and administrative
support to its exploration and production operations. In 1992, Arrow Oilfield
Service Company ("Arrow"), a separate service division, was organized. Arrow
provides the Company and third party customers with necessary oilfield services
such as well workovers, well completions, brine hauling and disposal and oil
trucking. Arrow is currently the largest oilfield service company in Ohio. In
June 1995, the Company acquired the assets and assumed the operations of Antrim
Services, Inc., an oilfield service company headquartered in Gaylord, Michigan,
in order to provide adequate oilfield services to its expanding Michigan
operations. In 1996, approximately 55% of Arrow's revenues were generated by
sales to third parties.
Target Oilfield Pipe & Supply Company ("TOPS"), a wholly-owned
subsidiary of the Company, operates retail sales outlets in the Appalachian and
Michigan Basins from which it sells a broad range of equipment, including pipe,
tanks, fittings, valves and pumping units. The Company originally entered the
oilfield supply business to ensure the quality and availability of supplies for
its own operations. In 1996, approximately 67% 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 28, 1997, the Company had 602 full-time employees,
including 236 oilfield sales and service employees, 287 oil and gas production
employees, 19 petroleum engineers, 10 geologists and 2 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
12
14
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 year ended December 31, 1996 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.
The only customer which accounted for 10% or more of the Company's
consolidated revenues during the year ended December 31, 1994 was Ravenswood
Aluminum Corporation ("RAC"), sales to which totaled $9.6 million. The Company's
contract with RAC, its principal gas purchaser in West Virginia, requires it to
deliver 10 billion Btus (approximately 8.9 MMcf) of gas per day through 1998. At
present, the Company is supplying this contract requirement by delivering
approximately 4.9 billion Btus of its own gas production, 3.8 billion Btus of
production from royalty and joint working interest owners in wells in which the
Company holds an interest and 1.3 billion Btus of gas purchased from third
parties.
The contract price at which gas is delivered to RAC for 1997 is $3.83
per MMBtu. The RAC contract also provides for a discount from the contract price
if gas is available under the same terms and conditions from an arms-length
third party at a price of less than 70% of the contract price. The discount is
equal to one-half of the difference between the lower available price and the
contract price and applies to volumes of gas for plant requirements in excess of
6,000 MMBtus per day. RAC unilaterally took discounts totaling $397,000,
$863,000 and $897,000 in 1994, 1995 and 1996, respectively. The Company has
contested RAC's interpretation of the contract and may initiate legal action to
recover part or all of the discounts taken.
To protect itself against an interruption or reduction in the income
stream under the RAC contract, the Company required the seller of the properties
subject to the RAC contract to partially secure the delivered gas price the
Company would receive under the contract with a declining letter of credit
initially issued by Citibank, N.A. (Citibank, N.A. was replaced by Nationsbank,
N.A. in August, 1996) and Chase Manhattan Bank, N.A. in the original amount of
$10.7 million, approximately $3.3 million of which is available for drawing in
1997. The Company is entitled to draw against the letter of credit annually if
it receives less than a specified minimum average delivered price on gas
delivered to RAC under the contract. Consistent with the terms of the letter of
credit, the Company was reimbursed directly by the seller of the RAC properties
for the discounts taken by RAC in 1994 and 1995 in the amount of $165,000 and
$323,000, respectively, and expects to be reimbursed for a portion of the
discount taken in 1996.
Regulation
Regulation of Production. In all states in which the Company is engaged
in oil and gas exploration and production, its activities are subject to
regulation. Such regulations may extend to requiring drilling permits, spacing
of wells, the prevention of waste and pollution, the conservation of natural gas
and oil, and other matters. Such regulations may impose restrictions on the
production of natural gas and oil by reducing the rate of flow from individual
wells below their actual capacity to
13
15
produce which could adversely affect the amount or timing of the Company's
revenues from such wells. Moreover, future changes in local, state or federal
laws and regulations could adversely affect the operations of the Company.
Environmental Regulation. The Company's operations are subject to
numerous laws and regulations governing the discharge of materials into the
environment or otherwise relating to environmental protection. These laws and
regulations may require the acquisition of a permit before drilling commences,
restrict the types, quantities and concentration of various substances that can
be released into the environment in connection with drilling and production
activities, limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas, and impose substantial
liabilities for pollution resulting from the Company's operations. Management
believes the Company is in substantial compliance with current applicable
environmental laws and regulations and 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, 1994, 1995 and 1996 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.
December 31
-----------------------------------------------
1994 1995 1996
---------- ---------- ---------
Estimated proved reserves
Gas (Bcf) 123.0 239.4 288.6
Oil (thousands of barrels) 4,113 6,283 7,389
See Note 14 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,
1996 determined in accordance with the rules and regulations of the Securities
and Exchange Commission.
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16
Estimated future net cash flows (before income taxes)
attributable to estimated production during
1997 $ 59,171,000
1998 56,219,000
1999 52,215,000
2000 and thereafter 500,887,000
---------------
Total $ 668,492,000
===============
Present value before income taxes
(discounted at 10% per annum) $ 355,959,000
===============
Present value after income taxes
(discounted at 10% per annum) $ 259,229,000
===============
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, 1996 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, 1996 were $23.00 per barrel and $3.02 per Mcf, respectively.
PRODUCING WELL DATA
The following table summarizes by state the Company's productive wells
at December 31, 1996:
December 31, 1996
-------------------------------------------------------------------------------------
Oil Wells Gas Wells Total
---------------------- ----------------------- -----------------------
State Gross Net Gross Net Gross Net
- ------------------------- --------- -------- --------- --------- --------- ---------
Ohio 2,242 2,035 1,666 1,478 3,908 3,513
West Virginia 381 377 873 633 1,254 1,010
Pennsylvania 296 291 521 339 817 630
New York 7 7 1,051 998 1,058 1,005
Michigan 12 8 571 197 583 205
Kentucky 0 0 101 99 101 99
--------- -------- --------- --------- --------- ---------
2,938 2,718 4,783 3,744 7,721 6,462
========= ======== ========= ========= ========= =========
ACREAGE DATA
The following table summarizes by state the Company's gross and net
developed and undeveloped leasehold acreage at December 31, 1996:
15
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December 31, 1996
---------------------------------------------------------------------------------------------
Developed Acreage Undeveloped Acreage Total Acreage
------------------------- -------------------------- ----------------------------
State Gross Net Gross Net Gross Net
- ------------------ ---------- ---------- ----------- ---------- ------------ ------------
Ohio 317,300 285,400 255,800 214,400 573,100 499,800
West Virginia 55,800 39,300 23,400 19,400 79,200 58,700
Pennsylvania 41,900 31,300 209,700 199,500 251,600 230,800
New York 130,800 118,100 28,900 26,200 159,700 144,300
Michigan 31,000 29,400 47,300 44,500 78,300 73,900
Kentucky 11,100 10,800 800 800 11,900 11,600
---------- ---------- ----------- ---------- ------------ ------------
587,900 514,300 565,900 504,800 1,153,800 1,019,100
========== ========== =========== ========== ============ ============
Item 3. LEGAL PROCEEDINGS
-----------------
On January 2, 1996, Karen J. Volgstadt, individually and as
administrator of the Estate of George A. Volgstadt, filed a complaint in the
Supreme Court of Chautauqua County, New York against the Company and a
subsidiary of the Company seeking the recovery of $6,000,000 in compensatory
damages for the death of George A. Volgstadt in an accident which occurred
during the course of his employment with the subsidiary. A Stipulation of
Discontinuance with prejudice has been entered by Mrs. Volgstadt with respect to
claims against the subsidiary. Accordingly, the remaining claims against the
Company relate to the Company's ownership of the real property where the
accident occurred. The Company believes that it has valid defenses to each of
the claims asserted and that any liability of the Company with respect to this
action would be covered by insurance.
The Company is involved in several other 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.
EXECUTIVE OFFICERS OF THE REGISTRANT
Executive officers of the Company as of February 28, 1997 were as
follows:
Name Age Position
- ---- --- --------
Henry S. Belden, IV 57 Chairman of the Board and Chief Executive Officer
Max L. Mardick 62 President and Chief Operating Officer and Director
Ronald E. Huff 41 Senior Vice President and Chief Financial Officer and Director
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Joseph M. Vitale 55 Senior Vice President Legal, General Counsel, Secretary and
Director
Ronald L. Clements 54 Senior Vice President Exploration and Production
Leo A. Schrider 58 Senior Vice President Technical Development
Dennis D. Belden 51 Vice President Supply and Service
Charles P. Faber 55 Vice President Corporate Development
Tommy L. Knowles 46 Vice President Production
Donald A. Rutishauser 40 Vice President and Treasurer
Dean A. Swift 44 Vice President, Assistant General Counsel and Assistant Secretary
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 business experience of each executive officer
is summarized below.
HENRY S. BELDEN, IV has been Chairman and Chief Executive Officer of
the Company since 1982. 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 member of the board of directors of
KeyBank-Canton District and Phoenix Packaging Corporation.
MAX L. MARDICK has been President and Chief Operating Officer of the
Company since 1990, a director since 1992 and a director of predecessor
companies from 1988 to 1992. 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.
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RONALD E. HUFF has been Senior Vice President and Chief Financial
Officer of the Company since 1989, having previously served as its Senior
Controller from 1986 to 1989. Mr. Huff has been a director of Belden & Blake
since 1991. He is a Certified Public Accountant with nearly 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.
RONALD L. CLEMENTS has been Senior Vice President of Exploration and
Production of the Company since 1993 and manages the Company's Exploration and
Production Division. He joined Belden & Blake in 1990 and served as Vice
President of Producing Operations until appointment to his current position in
1993. 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.
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. 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
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20
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.
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.
TOMMY L. KNOWLES has been Vice President of Production of the Company
since January of 1996. He has 24 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.
DONALD A. RUTISHAUSER has been Vice President and Treasurer of the
Company since 1989, having previously served as Senior Financial Analyst from
1987 to 1989. Prior to joining Belden & Blake, he was employed by Grace Energy
Corporation as Financial Project Manager. Mr. Rutishauser received a BA degree
in Economics from Dartmouth College and an MBA in Accounting and Finance from
the University of Michigan.
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.
PART II
-------
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
-----------------------------------------------------
STOCKHOLDER MATTERS
-------------------
The Company's Common Stock trades on the Nasdaq National Market tier of
The Nasdaq Stock Market under the Symbol: "BELD."
The following table sets forth the high and low sales prices for the
Common Stock of the Company for the periods indicated as reported by the Nasdaq
National Market:
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21
Sale Price
--------------------------
High Low Average Daily Volume
--------- --------- ---------------------------
1994
- -----------------------------
First Quarter $13.25 $ 9.75 22,567
Second Quarter 13.00 12.00 14,376
Third Quarter 14.75 11.50 18,909
Fourth Quarter 15.00 13.25 26,388
1995
- -----------------------------
First Quarter $14.25 $11.50 16,892
Second Quarter 17.00 13.75 16,316
Third Quarter 19.25 14.50 46,982
Fourth Quarter 19.25 14.50 74,242
1996
- -----------------------------
First Quarter $18.75 $15.75 40,953
Second Quarter 21.25 17.88 46,486
Third Quarter 24.00 20.00 54,598
Fourth Quarter 27.50 22.12 72,866
1997
- -----------------------------
First Quarter (through $28.75 $20.25 94,659
February 28, 1997)
The approximate number of record holders of the Company's equity
securities at February 28, 1997 was as follows:
Number of
Title of Class Record Holders
- --------------------------------------- ---------------------
Common Stock 1,818
Class II Serial Preferred Stock
$7.50 Series A 1
Dividends
No dividends have been paid on the Company's Common Stock and none are
expected to be paid in the foreseeable future. The Class II Serial Preferred
Stock $7.50 Series A is entitled to cumulative quarterly dividends at the annual
rate of $7.50 per share.
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22
Item 6. SELECTED FINANCIAL DATA
-----------------------
BELDEN & BLAKE CORPORATION
As of or for the Year Ended December 31,
-------------------------------------------------------------------------------
1992 (1) 1993 1994 1995 1996
----------- --------- ----------- ------------ ------------
(In thousands, except per share data)
Operations
Revenues $52,550 $72,874 $79,365 $110,067 $153,235
Depreciation, depletion 4,853 9,693 11,886 19,717 29,752
and amortization
Income from continuing 1,139 3,265 4,180 6,260 15,194
operations
Income from continuing 0.48 0.55 0.57 0.69 1.34
operations per common
share
Preferred dividends paid -- 180 180 180 180
Balance sheet data
Working capital 1,465 28,850 13,612 17,359 22,110
Oil and gas properties and 82,751 86,192 106,710 211,142 216,468
gathering systems, net
Total assets 102,253 135,174 148,173 297,298 303,763
Long-term liabilities, 59,311 43,516 47,858 110,523 97,642
less current portion
Preferred stock 2,400 2,400 2,400 2,400 2,400
Total shareholders' equity 29,023 76,857 81,142 142,291 158,918
- -------------
(1) Operating data for the period prior to March 31, 1992 are for a group of
companies and assets owned by Henry S. Belden IV (the "Belden Interests"), the
acquisition of which was accounted for in a manner similar to a pooling of
interests.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
-------------------------------------------------
CONDITION AND RESULTS OF OPERATIONS
-----------------------------------
The following discussion should be read in conjunction with the
Company's Consolidated Financial Statements and Notes thereto and the Selected
Financial Information included elsewhere in this report.
GENERAL
On March 31, 1992, the Company succeeded to the Belden Interests. The
transaction was accounted for on the basis of historical cost in a manner
similar to a pooling of interests. As a result,
21
23
the consolidated financial statements of the Company reflect the combined
historical results of operations of only the Belden Interests prior to March 31,
1992.
Also on March 31, 1992, the Company acquired the assets and assumed the
liabilities of Belden & Blake Energy Company (the "Partnership") and Belden &
Blake International Limited ("BBI") in exchange for shares of common stock
pursuant to the consolidation of the Partnership and BBI (the "Consolidation").
The Consolidation was accounted for as a purchase, and the results of operations
of the Partnership and BBI have been included from that date.
Prior to March 31, 1992, the Company was engaged principally in
managing the assets and business activities of the Partnership, BBI and
non-affiliated entities and in gas gathering and marketing. Accordingly, a
significant portion of the Company's income was derived from transactions with
the Partnership and BBI, including well operating fees, sales of oilfield
supplies and services at fixed mark-ups over cost and fees for accounting and
related services. Since March 31, 1992, the Company's principal business has
been 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.
Consequently, the historical statements of operations prior to the Consolidation
do not reflect the Company's current or planned business activities.
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 cost of gas
purchased from the Company is the wellhead price stipulated by the well
operating agreements and is included in "Cost of gas and gathering expense."
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. Prior to the Consolidation, revenues from oilfield
sales and service provided to the Partnership and BBI were accounted for as
third-party revenues.
RESULTS OF OPERATIONS
1996 COMPARED TO 1995
OIL AND GAS SALES. Oil and gas sales increased $32.6 million (70%) in
1996 compared to 1995 due to an increase in oil and gas volumes sold and a
higher average price paid for the Company's oil and gas.
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%)
22
24
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
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 resulting in
increased gas sales of approximately $8.9 million.
GAS MARKETING AND GATHERING REVENUE. Gas marketing and gathering
revenue increased $4.1 million (10%) from $40.4 million in 1995 to $44.5 million
in 1996 primarily due to an increase in the volume of gas purchased from third
parties and resold and an increase in the average selling price of gas.
OILFIELD SALES AND SERVICE REVENUE. Oilfield sales and service revenue
increased $5.4 million (27%) from $20.1 million in 1995 to $25.5 million in
1996. This increase was primarily due to the sales generated by the three
oilfield sales and service companies acquired by the Company in 1995 and
increased third party oilfield sales and service revenue.
INTEREST AND OTHER REVENUE. Interest and other revenue increased $1.0
million (36%) from $2.7 million in 1995 to $3.7 million in 1996 primarily due to
the recognition of income in 1996 from incentive production payments associated
with certain properties operated by Ward Lake, partially offset by the
recognition in 1995 of anticipated proceeds from contract rejection claims that
were filed in the bankruptcy proceedings of Columbia Gas Transmission
Corporation. Amounts included in income related to the Columbia claims were $1.3
million in 1995 and $276,000 in 1996. Payment of these claims was received by
the Company in January, 1997.
PRODUCTION EXPENSE. Production expense increased $6.3 million (54%)
from $11.8 million in 1995 to $18.1 million 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. The average production cost per equivalent Mcf of natural
gas excluding taxes increased from $.58 per Mcfe in 1995 to $.61 per Mcfe in
1996.
PRODUCTION TAXES. 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.
COST OF GAS AND GATHERING EXPENSE. Cost of gas and gathering expense
increased $3.8 million (11%) from $33.8 million in 1995 to $37.6 million in 1996
due to an increase in volumes of gas purchased and an increase in the cost of
gas.
OILFIELD SALES AND SERVICE EXPENSE. Oilfield sales and service expense
increased $4.8 million (27%) from $18.3 million in 1995 to $23.1 million in 1996
primarily as a result of the increased cost of goods sold associated with the
increased sales described above.
EXPLORATION EXPENSE. Exploration expense increased $1.2 million (23%)
from $4.9 million in 1995 to $6.1 million in 1996 primarily due to higher levels
of geological, geophysical and leasing activity and increases in the size of the
technical staff in conjunction with increased drilling activity.
23
25
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense
increased $771,000 (20%) from $3.8 million in 1995 to $4.6 million in 1996 due
to increases in employee compensation and benefits, an increase in profit
sharing and bonuses and investment banking and other professional fees.
INTEREST EXPENSE. 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 3 -
"Acquisitions").
DEPRECIATION, DEPLETION AND AMORTIZATION. 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
described 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.
FRANCHISE, PROPERTY AND OTHER TAXES. Franchise, property and other
taxes increased by $511,000 (42%) from $1.2 million in 1995 to $1.7 million in
1996. Franchise taxes increased approximately $350,000 due to the increase in
shareholders' equity as a result of the common stock issued in 1995 and the
increase in net income retained in the business.
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES. Income from
continuing operations before income taxes increased $13.4 million (159%) from
$8.4 million in 1995 to $21.8 million in 1996. The oil and gas operations
segment increased operating income $12.4 million (99%) from $12.4 million in
1995 to $24.8 million in 1996. The increase was attributable to the items
discussed above. The oilfield sales and service segment operating income
increased $290,000 (43%) from $673,000 in 1995 to $963,000 in 1996.
INCOME FROM CONTINUING OPERATIONS. Income from continuing operations
increased $8.9 million (143%) from $6.3 million in 1995 to $15.2 million in
1996. This increase in income from continuing operations was primarily the
result of the items discussed above. Provision for income taxes from continuing
operations increased $4.4 million (205%) from $2.2 million in 1995 to $6.6
million in 1996. This increase 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. Earnings from continuing operations on a per common share
basis increased from $.69 per share in 1995 to $1.34 per share in 1996. This
increase was primarily the result of the factors discussed above.
LOSS FROM DISCONTINUED OPERATIONS. Loss from discontinued operations
was $675,000 ($439,000 net of tax benefit or $.04 per share) in 1996 compared to
$1,761,000 ($1,139,000 net of tax benefit or $.13 per share) in 1995. The losses
in 1996 and 1995 include losses on assets sold, the write-down of various assets
and inventories to estimated realizable value and a provision for estimated
costs of asset disposals and future losses.
1995 COMPARED TO 1994
OIL AND GAS SALES. Oil and gas sales increased $14.3 million (44%) in
1995 compared to 1994 due primarily to an increase in oil and gas volumes sold
and a higher average price paid for the
24
26
Company's oil. These increases more than offset a lower average price paid for
the Company's natural gas.
Oil volumes increased 60,000 Bbls (12%) from 496,000 Bbls in 1994 to
556,000 Bbls in 1995 resulting in an increase in oil sales of approximately $1.0
million. Gas volumes increased 7.4 Bcf (77%) from 9.6 Bcf in 1994 to 17.0 Bcf in
1995 resulting in an increase in gas sales of approximately $19.1 million. These
volume increases were primarily due to production from the Company's 1995
acquisitions and from wells drilled in 1994 and 1995. Gas volumes produced in
1995 were less than the Company's full production potential as a result of the
Company's decision to curtail gas production due to low spot market gas prices.
Interstate pipeline repairs and construction in Michigan and West Virginia also
reduced potential production volumes.
The average price paid for the Company's oil increased from $15.98 per
barrel in 1994 to $16.78 per barrel in 1995 which increased oil sales by
approximately $450,000. The average price paid for the Company's natural gas
decreased $.37 per Mcf to $2.21 per Mcf in 1995 compared to 1994 resulting in
decreased gas sales of approximately $6.3 million.
GAS MARKETING AND GATHERING REVENUE. Gas marketing and gathering
revenue increased $7.3 million (22%) from $33.1 million in 1994 to $40.4 million
in 1995 primarily due to the Company's 1995 acquisitions. Increased volumes of
gas purchased from third parties and resold were offset by a lower average
selling price .
OILFIELD SALES AND SERVICE REVENUE. Oilfield sales and service revenue
increased $6.9 million (53%) from $13.2 million in 1994 to $20.1 million in
1995. This increase was primarily due to the sales generated by the three
oilfield service companies acquired by the Company in September and October of
1994 and three oilfield sales and service companies acquired in 1995.
INTEREST AND OTHER REVENUE. Interest and other revenue increased $2.1
million (383%) from $562,000 in 1994 to $2.7 million in 1995 primarily due to
the recognition of $1.3 million in anticipated proceeds from contract rejection
claims that have been filed in the bankruptcy proceedings of Columbia Gas
Transmission Corporation and the recognition of income in 1995 from an incentive
production payment associated with certain properties operated by Ward Lake.
PRODUCTION EXPENSE. Production expense increased $4.0 million (50%)
from $7.8 million in 1994 to $11.8 million in 1995. This increase was primarily
due to the increased production volumes discussed above. The average production
cost per equivalent Mcf of natural gas excluding taxes decreased from $.62 per
Mcfe in 1994 to $.58 per Mcfe in 1995.
PRODUCTION TAXES. Production taxes increased $703,000 (52%) from $1.4
million in 1994 to $2.1 million in 1995. This increase was primarily due to the
increased production volumes discussed above.
COST OF GAS AND GATHERING EXPENSE. Cost of gas and gathering expense
increased $4.9 million (17%) from $28.9 million in 1994 to $33.8 million in 1995
primarily due to the Company's 1995 acquisitions. Increased volumes of gas
purchased from third parties and resold were offset by a lower average purchase
price.
25
27
OILFIELD SALES AND SERVICE EXPENSE. Oilfield sales and service expense
increased $6.1 million (50%) from $12.2 million in 1994 to $18.3 million in 1995
primarily as a result of the increased cost of goods sold associated with
increased sales resulting from the acquisitions described above.
EXPLORATION EXPENSE. Exploration expense increased $2.1 million (76%)
from $2.8 million in 1994 to $4.9 million in 1995 primarily due to higher levels
of geological and geophysical activity and increases in the size of the
technical staff.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense
increased $235,000 (7%) from $3.6 million in 1994 to $3.8 million in 1995
primarily due to increases in employee compensation and benefits.
INTEREST EXPENSE. Interest expense increased $2.6 million (73%) from
$3.5 million in 1994 to $6.1 million in 1995. This increase was primarily due to
higher average debt balances incurred to finance the 1995 acquisitions (Note 3 -
"Acquisitions").
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and
amortization increased by $7.8 million (66%) from $11.9 million in 1994 to $19.7
million in 1995. Depletion expense increased $6.0 million (66%) from $9.1
million in 1994 to $15.1 million in 1995. This increase was primarily due to
additional depletion expense associated with the increased production volumes
described above. Depletion per Mcfe increased from $.72 per Mcfe in 1994 to $.74
per Mcfe in 1995.
FRANCHISE, PROPERTY AND OTHER TAXES. Franchise, property and other
taxes increased by $374,000 (44%) from $854,000 in 1994 to $1.2 million in 1995
primarily due to the acquisitions made in 1995 and the increase in shareholders'
equity as a result of the common stock issued in 1995.
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES. Income from
continuing operations before income taxes increased $1.9 million (29%) from $6.5
million in 1994 to $8.4 million in 1995. The operating income from the oil and
gas operations segment increased $3.3 million (37%) from $9.1 million in 1994 to
$12.4 million in 1995. The increase was attributable to the items discussed
above. The operating income from the oilfield sales and service segment
increased $323,000 (92%) from $350,000 in 1994 to $673,000 in 1995.
INCOME FROM CONTINUING OPERATIONS. Income from continuing operations
increased $2.1 million (50%) from $4.2 million in 1994 to $6.3 million in 1995.
This increase in income from continuing operations was primarily the result of
the items discussed above. Provision for income taxes from continuing operations
decreased $180,000 (8%) from $2.3 million in 1994 to $2.2 million in 1995. This
decrease was attributable to a decrease in the effective tax rate partially
offset by an increase in income from continuing operations before income taxes.
The effective tax rate decreased primarily due to the utilization of
nonconventional fuel source tax credits. Earnings from continuing operations on
a per common share basis increased from $.57 per share in 1994 to $.69 per share
in 1995. This increase was primarily the result of the factors discussed above.
LOSS FROM DISCONTINUED OPERATIONS. Loss from discontinued operations
was $1,761,000 ($1,139,000 net of tax benefit or $.13 per share) in 1995
compared to $509,000 ($337,000 net of tax benefit or $.05 per share) in 1994.
The loss in 1995 includes the write-down of various assets and inventories to
estimated realizable value and a provision for estimated costs of asset
disposals and future losses.
26
28
LIQUIDITY AND CAPITAL RESOURCES
The Company's working capital is closely related to and dependent on
the current prices paid for its oil and gas.
The Company's current ratio at December 31, 1996 was 1.64 to 1.00.
During 1996, working capital increased $4.7 million from $17.4 million to $22.1
million. The increase was primarily due to an increase in accounts receivable
($5.4 million) and decreases in accounts payable and accrued expenses ($4.4
million), which was partially offset by a decrease in cash ($3.7 million) and an
increase in the current portion of long-term liabilities ($2.2 million)
reflecting the first principal payment due in 1997 on the senior notes. The
Company's operating activities provided cash flow of $46.5 million during 1996.
On May 25, 1995, the Company's bank group amended its revolving bank
facility. The facility was increased to $200 million and the maturity date was
extended to March 31, 1999. The borrowing base is calculated by the bank group
and is based on the cash flows generated by the Company's proved developed
reserves, gas gathering systems and other corporate assets. Generally, the
Company can expect to have the borrowing base increased by at least 50% of the
present value before income taxes (discounted at 10% per annum) of any proved
developed reserves added through acquisition or drilling. At December 31, 1996
the borrowing base was $70 million. The Company believes that its reserves at
December 31, 1996 could provide a borrowing base in excess of $115 million.
On February 16, 1996, the Company's bank group further amended its
revolving bank facility. The maturity date was extended to March 31, 2001 and
the LIBOR interest rate option was modified to decrease from LIBOR + 2% to a
range of LIBOR + 1-1/4% to LIBOR + 3/4% as outstanding balances decrease in
relation to the borrowing base.
Outstanding balances under the agreement incurred interest at the
Company's choice of either: (i) the one, two or three-month LIBOR + 1.25% (6.81%
for the three-month LIBOR interest rate option at December 31, 1996) or (2) the
bank's prime rate (8.25% at December 31, 1996). At December 31, 1996, the
Company had $59 million outstanding under this facility.
The amended facility will continue to restrict the sale of assets to no
more than 15% of shareholders' equity in any one year and will require the
Company to maintain certain levels of net worth, working capital and debt
service coverage.
When market conditions are favorable, the Company may enter into
interest rate swap arrangements, whereby a portion of the Company's floating
rate exposure is exchanged for a fixed interest rate. The Company had no such
derivative financial instruments at December 31, 1995 or 1996.
During 1993, the Company placed $35 million of 7% fixed-rate senior
notes with five insurance companies in a private placement. These notes, which
are interest-only for four years, mature on September 30, 2005. Equal annual
principal payments of $3,888,888 will be required on each September 30
commencing in 1997.
The senior note agreement limits the Company's senior debt to 50% of
the discounted present value (at 10%) of the Company's oil and gas reserves plus
the net book value of its gas gathering systems. Other terms and covenants are
substantially the same as those contained in the $200 million revolving credit
facility.
27
29
In the fourth quarter of 1996, $1.25 million of the Company's 9.25%
convertible subordinated debentures (due June 30, 2000) were converted by the
holders into 62,034 shares of the Company's common stock at the current
conversion price of $20.15 per share.
The Company currently expects to spend approximately $38 million during
1997 on its drilling activities and approximately $12 million for other capital
expenditures. The Company's acquisition program is expected to be financed with
any available cash flow over $50 million and with its available bank credit
line. The Company believes that its existing sources of working capital are
sufficient to satisfy all currently anticipated working capital requirements.
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, through additional borrowings and,
to the extent necessary, the issuance of additional common or preferred stock.
INFLATION AND CHANGES IN PRICES
During 1994, the price paid for the Company's crude oil increased from
$13.50 per barrel to a high of $18.00 per barrel, then decreased to $15.50 per
barrel at year end, with an average price of $15.98 per barrel. 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. The average price of the Company's natural gas
decreased from $2.58 per Mcf in 1994 to $2.21 per Mcf in 1995, then increased to
$2.56 per Mcf in 1996.
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 based on a regional index or a
negotiated positive basis above the relevant 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.
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.
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30
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
--------------------------------------------------
The information with respect to the directors of the Company set forth
under the caption "Election of Directors" in the Company's proxy statement to be
filed for the Annual Meeting of Shareholders to be held on or about May 22, 1997
is incorporated herein by reference. See pages 16 through 19 of this report for
information regarding executive officers.
Item 11. EXECUTIVE COMPENSATION
----------------------
The information with respect to executive compensation set forth under
the captions "Executive Compensation" and "Information about the Board of
Directors" in the Company's proxy statement to be filed for the Annual Meeting
of Shareholders to be held on or about May 22, 1997 is incorporated herein by
reference.
29
31
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
---------------------------------------------------
MANAGEMENT
----------
The information with respect to security ownership of certain
beneficial owners and management set forth under the caption "Ownership of
Voting Securities" in the Company's proxy statement to be filed for the Annual
Meeting of Shareholders to be held on or about May 22, 1997 is incorporated
herein by reference.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
----------------------------------------------
The information set forth under the caption "Certain Transactions" in
the Company's proxy statement to be filed for the Annual Meeting of Shareholders
on or about May 22, 1997 is incorporated by reference.
PART IV
-------
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
-------------------------------------------------------
FORM 8-K
--------
(a) Documents filed as a part of this report:
1. Financial Statements
The financial statements listed in the accompanying Index to
Consolidated Financial Statements and Schedules are filed as part of this Annual
Report on Form 10-K.
2. Financial Statement Schedules
No financial statement schedules are required to be filed as part of
this Annual Report on Form 10-K.
3. Exhibits
No. Description
- --- -----------
3.1 Articles of Incorporation of the Company--incorporated by
reference to Exhibit 3.1 to the Company's Registration
Statement on Form S-4 (Registration No. 33-43209)
3.2 Amended Articles of Incorporation to the Company--incorporated
by reference to Exhibit 3.2 to the Company's Registration
Statement on Form S-4 (Registration No. 33-43209)
3.2(a) Amendment to Amended Articles of Incorporation of the
Company--incorporated by reference to Exhibit 4 to the
Company's Current Report on Form 8-K dated December 30, 1992
3.3 Amended Code of Regulations of the Company--incorporated by
reference to Exhibit 3.3 to the Company's Registration
Statement on Form S-4 (Registration No. 33-43209)
30
32
4.1 Amended and Restated Debenture Agreement between the Company
and Petercam Securities--incorporated by reference to Exhibit
4.1 to the Company's Registration Statement on Form S-4
(Registration No. 33-43209)
4.2(a) Credit Agreement among the Company, The Canton Oil & Gas
Company, Peake Energy, Inc., Peake Operating Company, Bank
One, Texas, National Association and NBD Bank, N.A. dated
November 1993--incorporated by reference to Exhibit 4.2 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1993
4.2(b) First Amendment to Credit Agreement among the Company, The
Canton Oil & Gas Company, Peake Energy, Inc., Bank One, Texas,
National Association and NBD Bank, N.A., effective as of
August 1, 1994--incorporated by reference to Exhibit 4.2(b) to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1995
4.2(c) Second Amendment to Credit Agreement among the Company, The
Canton Oil & Gas Company, Peake Energy, Inc., Ward Lake
Drilling, Inc., Bank One, Texas, National Association and NBD
Bank, N.A., effective as of March 29, 1995--incorporated by
reference to Exhibit 4.2(c) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1995
4.2(d) Third Amendment to Credit Agreement among the Company, The
Canton Oil & Gas Company, Ward Lake Drilling, Inc., Bank One,
Texas, National Association and NBD Bank, N.A., effective as
of May 25, 1995--incorporated by reference to Exhibit 4.2(d)
to the Company's Annual Report on Form 10-K for the year ended
December 31, 1995
4.2(e) Fourth Amendment to Credit Agreement among the Company, The
Canton Oil & Gas Company, Peake Energy, Inc., Ward Lake
Drilling, Inc., Bank One, Texas, National Association and NBD
Bank, N.A., effective as of February 15, 1996--incorporated by
reference to Exhibit 4.2(e) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1995
4.3 Warrant Assumption Agreement between Belden & Blake
Corporation and Belden & Blake Energy Company--incorporated by
reference to Exhibit 4.4 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1992
4.4 Note Purchase Agreement dated as of November 15, 1993 among
the Company, The Canton Oil & Gas Company, Peake Operating
Company and Peake Energy, Inc. and the purchasers listed on
Annex I thereto--incorporated by reference to Exhibit 4.5 to
the Company's Annual Report on Form 10-K for the year ended
December 31, 1993
4.5 None of the other instruments defining the rights of holders
of long-term debt of the Company or its subsidiaries involve
long-term debt in an amount which exceeds ten percent of the
total assets of the Company and its subsidiaries on a
consolidated basis. The Company agrees to furnish a copy of
such other instruments to the Commission upon request.
10.1 Amended and Restated Employment Agreement between the Company
and Henry S. Belden IV--incorporated by reference to Exhibit
10.1 to the Company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 1996
31
33
10.2 Severance Agreement between the Company and Max L. Mardick--
incorporated by reference to Exhibit 10.2 to the Company's
Quarterly Report on Form 10-Q for the quarter ended September
30, 1996
10.3 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
10.4 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
10.5 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
10.6(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)
10.6(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)
10.7 Restricted Stock Grant Plan of The Canton Oil & Gas Company
(formerly known as Belden & Blake Corporation)--incorporated
by reference to Exhibit 10.8 to the Company's Registration
Statement on Form S-4 (Registration No. 33-43209)
10.8 Belden & Blake Corporation Non-employee Director Stock Option
Plan--incorporated by reference to Exhibit 10.6 to the
Company's Annual Report on Form 10-K for the year ended
December 31, 1993
10.9 Plan and Agreement of Consolidation dated as of October 10,
1991, as amended, among Belden & Blake Energy Company, Henry
S. Belden IV, Belden & Blake International Limited and the
Company--incorporated by reference to Exhibit 2.1 to the
Company's Registration Statement on Form S-4 (Registration No.
33-43209)
10.10 Amended and Restated Gas Sales and Purchase Contract between
Peake Energy, Inc. and Kaiser Aluminum & Chemical Corporation
dated as of August 27, 1987--incorporated by reference to
Exhibit 10.11 to the Company's Registration Statement on Form
S-1 (Registration No. 33-60228)
10.11(a) Stock Purchase Agreement dated January 3, 1995 among Keith
Hardin Gornick, R. David Briney, William F. Rolinski, Charles
Nelson and the Company-- incorporated by reference to Exhibit
2.1 to the Company's Current Report on Form 8-K dated February
10, 1995
32
34
10.11(b) Agreement of Amendment dated January 16, 1995 among Keith
Hardin Gornick, R. David Briney, William F. Rolinski, Charles
Nelson and the Company-- incorporated by reference to Exhibit
2.2 to the Company's Current Report on Form 8-K dated February
10, 1995
10.11(c) Second Agreement of Amendment dated February 10, 1995 among
Keith Hardin Gornick, R. David Briney, William F. Rolinski,
Charles Nelson and the Company--incorporated by reference to
Exhibit 2.3 to the Company's Current Report on Form 8-K dated
February 10, 1995
10.12 Asset Purchase Agreement dated July 26, 1995 among Quaker
State Corporation, QSE&P, Inc. and the Company--incorporated
by reference to Exhibit 2 to the Company's Current Report on
Form 8-K dated August 9, 1995
21* Subsidiaries of the Registrant
23* Consent of Ernst & Young LLP
27* Financial Data Schedule
*Filed herewith
(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.
33
35
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 5, 1997 By: /s/ Henry S. Belden IV
- -------------------------- -------------------------------
Date Henry S. Belden IV
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
/s/ Henry S. Belden IV Chairman of the Board, March 5, 1997
- -------------------------- Chief Executive Officer -------------
Henry S. Belden IV and Director Date
(Principal Executive Officer)
/s/ Ronald E. Huff Senior Vice President, March 5, 1997
- -------------------------- Chief Financial Officer -------------
Ronald E. Huff and Director Date
(Principal Financial and
Accounting Officer)
/s/ Max L. Mardick President, Chief Operating March 5, 1997
- -------------------------- Officer and Director -------------
Max L. Mardick Date
/s/ Joseph M. Vitale Senior Vice President Legal, March 5, 1997
- -------------------------- Secretary and Director -------------
Joseph M. Vitale
/s/ Paul R. Bishop* March 5, 1997
- -------------------------- Director -------------
Paul R. Bishop Date
34
36
/s/ Theodore V. Boyd Director March 5, 1997
- -------------------------- -------------
Theodore V. Boyd Date
/s/ Gary R. Petersen* Director March 5, 1997
- -------------------------- -------------
Gary R. Petersen Date
/s/ David P. Quint* Director March 5, 1997
- -------------------------- -------------
David P. Quint Date
/s/ Raymond D. Saunders* Director March 5, 1997
- -------------------------- -------------
Raymond D. Saunders Date
/s/ George M. Smart Director March 5, 1997
- -------------------------- -------------
George M. Smart Date
*By: Joseph M. Vitale March 5, 1997
- -------------------------- -------------
Attorney-in-Fact Date
35
37
BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES
ITEM 14(A)(1) AND (2)
PAGE
----
CONSOLIDATED FINANCIAL STATEMENTS
- ---------------------------------
Report of Independent Auditors......................................... F-2
Consolidated Balance Sheets as of December 31, 1996 and 1995........... F-3
Consolidated Statements of Operations for the years ended
December 31, 1996, 1995 and 1994.................................... F-5
Consolidated Statements of Shareholders' Equity for the years
ended December 31, 1996, 1995 and 1994............................ F-6
Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994.................................... F-7
Notes to Consolidated Financial Statements............................. F-8
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
38
REPORT OF INDEPENDENT AUDITORS
To the Shareholders and Board of Directors
Belden & Blake Corporation
We have audited the accompanying consolidated balance sheets of Belden & Blake
Corporation as of December 31, 1996 and 1995, and the related consolidated
statements of operations, shareholders' equity and cash flows for each of the
three years in the period ended December 31, 1996. 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, 1996 and 1995, and the consolidated results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
ERNST & YOUNG LLP
Cleveland, Ohio
February 21, 1997
F-2
39
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
DECEMBER 31
---------------------------------
1996 1995
--------------- -------------
ASSETS
CURRENT ASSETS
Cash and cash equivalents $ 8,606 $ 12,322
Accounts receivable, net 33,523 28,123
Inventories 9,397 9,253
Deferred income taxes 2,918 2,254
Other current assets 2,280 2,198
-------------- --------------
TOTAL CURRENT ASSETS 56,724 54,150
PROPERTY AND EQUIPMENT, AT COST
Oil and gas properties (successful efforts method) 266,521 235,344
Gas gathering systems 26,045 25,416
Land, buildings, machinery and equipment 31,578 29,977
-------------- --------------
324,144 290,737
Less accumulated depreciation, depletion
and amortization 86,808 59,209
-------------- --------------
PROPERTY AND EQUIPMENT, NET 237,336 231,528
OTHER ASSETS 9,703 11,620
-------------- --------------
$ 303,763 $ 297,298
============== ==============
F-3
40
BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS, EXCEPT SHARE DATA)
December 31
------------------------
1996 1995
--------- ---------
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES
Accounts payable $ 9,421 $ 11,004
Accrued expenses 20,990 23,811
Current portion of long-term liabilities 4,203 1,976
--------- ---------
Total current liabilities 34,614 36,791
LONG-TERM LIABILITIES
Bank and other long-term debt 59,216 67,223
Senior notes 31,111 35,000
Convertible subordinated debentures 5,550 6,800
Other 1,765 1,500
--------- ---------
97,642 110,523
DEFERRED INCOME TAXES 12,589 7,693
SHAREHOLDERS' EQUITY
Common stock without par value; $.10 stated value per share; authorized
50,000,000 shares; issued
and outstanding 11,231,865 and 11,136,496 shares 1,123 1,114
Preferred stock without par value; $100 stated value
per share; authorized 8,000,000 shares;
issued and outstanding 24,000 shares 2,400 2,400
Paid in capital 128,035 126,063
Retained earnings 27,395 12,820
Unearned portion of restricted stock (35) (106)
--------- ---------
TOTAL SHAREHOLDERS' EQUITY 158,918 142,291
--------- ---------
$ 303,763 $ 297,298
========= =========
See accompanying notes.
F-4
41
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31
--------------------------------------
1996 1995 1994
--------- --------- --------
REVENUES
Oil and gas sales $ 79,491 $ 46,853 $ 32,574
Gas marketing and gathering 44,527 40,436 33,072
Oilfield sales and service 25,517 20,066 13,157
Interest and other 3,700 2,712 562
--------- --------- --------
153,235 110,067 79,365
EXPENSES
Production expense 18,098 11,756 7,827
Production taxes 3,168 2,060 1,357
Cost of gas and gathering expense 37,556 33,831 28,878
Oilfield sales and service 23,142 18,266 12,180
Exploration expense 6,064 4,924 2,803
General and administrative expense 4,573 3,802 3,567
Interest expense 7,383 6,073 3,503
Depreciation, depletion and amortization 29,752 19,717 11,886
Franchise, property and other taxes 1,739 1,228 854
--------- --------- --------
131,475 101,657 72,855
--------- --------- --------
INCOME FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES 21,760 8,410 6,510
Provision for income taxes 6,566 2,150 2,330
--------- --------- --------
INCOME FROM CONTINUING OPERATIONS 15,194 6,260 4,180
LOSS FROM DISCONTINUED OPERATIONS (439) (1,139) (337)
--------- --------- --------
NET INCOME $ 14,755 $ 5,121 $ 3,843
========= ========= ========
EARNINGS (LOSS) PER COMMON SHARE:
CONTINUING OPERATIONS $ 1.34 $ 0.69 $ 0.57
DISCONTINUED OPERATIONS (0.04) (0.13) (0.05)
--------- --------- --------
NET INCOME $ 1.30 $ 0.56 $ 0.52
========= ========= ========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING 11,176 8,785 7,080
========= ========= ========
See accompanying notes.
F-5
42
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(IN THOUSANDS)
UNEARNED
COMMON COMMON PREFERRED PAID IN RETAINED RESTRICTED
SHARES STOCK STOCK CAPITAL EARNINGS STOCK TOTAL
------- -------- ---------- -------- --------- ----------- -----------
JANUARY 1, 1994 7,053 $ 706 $ 2,400 $ 69,865 $ 4,216 $ (330) $ 76,857
Stock issued 32 3 385 388
Net income 3,843 3,843
Preferred stock dividend (180) (180)
Restricted stock vested 129 105 234
- ------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1994 7,085 709 2,400 70,379 7,879 (225) 81,142
Stock issued 4,028 403 55,264 55,667
Net income 5,121 5,121
Preferred stock dividend (180) (180)
Stock options exercised 2 -- 25 25
Employee stock bonus 22 2 251 253
Restricted stock vested 144 119 263
- ------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1995 11,137 1,114 2,400 126,063 12,820 (106) 142,291
Net income 14,755 14,755
Preferred stock dividend (180) (180)
Stock options exercised and
related tax benefit 3 -- 47 47
Employee stock bonus 26 3 418 421
Restricted stock activity 4 -- 263 71 334
Conversion of debentures 62 6 1,244 1,250
- ------------------------------------------------------------------------------------------------------------------
DECEMBER 31, 1996 11,232 $ 1,123 $ 2,400 $ 128,035 $ 27,395 $ (35) $ 158,918
==================================================================================================================
F-6
43
BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
YEAR ENDED DECEMBER 31
----------------------------------------
1996 1995 1994
------------ --------------- --------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 14,755 $ 5,121 $ 3,843
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization 29,752 20,154 12,021
Loss on disposal of property and equipment 534 177 91
Deferred income taxes 4,232 488 1,570
Deferred compensation and stock grants 1,311 1,067 359
Change in operating assets and liabilities, net of
effects of acquisition of businesses:
Accounts receivable and other operating assets (4,385) (14,485) (1,622)
Inventories (144) 469 (2,328)
Accounts payable and accrued expenses 476 8,958 1,775
-------- --------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES 46,531 21,949 15,709
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of businesses, net of cash acquired (4,543) (99,837) (17,968)
Proceeds from property and equipment disposals 2,227 589 438
Additions to property and equipment (37,074) (23,855) (19,844)
(Increase) decrease in other assets (705) (867) 88
-------- --------- --------
NET CASH USED IN INVESTING ACTIVITIES (40,095) (123,970) (37,286)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from revolving line of credit and long-term debt 16,105 73,000 6,100
Repayment of long-term debt and other obligations (26,117) (17,818) (2,938)
Preferred stock dividends (180) (180) (180)
Proceeds from sale of common stock and stock options 40 59,438 --
Common stock placement cost -- (3,746) --
-------- --------- --------
NET CASH (USED IN) PROVIDED BY
FINANCING ACTIVITIES (10,152) 110,694 2,982
-------- --------- --------
NET (DECREASE) INCREASE IN CASH
AND CASH EQUIVALENTS (3,716) 8,673 (18,595)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 12,322 3,649 22,244
-------- --------- --------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 8,606 $ 12,322 $ 3,649
======== ========= ========
See accompanying notes.
F-7
44
BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) 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 gas utilities and industrial consumers in Ohio, Michigan, West Virginia,
Pennsylvania, New York and Kentucky. The Company also provides oilfield services
and is a distributor of a broad range of oilfield equipment and supplies. Its
customers include other independent oil and gas companies, dealers and operators
throughout Ohio, Michigan, West Virginia, Pennsylvania and New York. The price
of oil and gas has a significant impact on the Company's working capital and
results of operations.
PRINCIPLES OF CONSOLIDATION AND FINANCIAL PRESENTATION
- ------------------------------------------------------
The accompanying consolidated financial statements include the
financial statements of the Company and its subsidiaries. All significant
intercompany accounts and transactions have been eliminated in consolidation.
USE OF ESTIMATES IN THE FINANCIAL STATEMENTS
- --------------------------------------------
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts. Significant estimates used in the
preparation of the Company's financial statements which could be subject to
significant revision in the near term include estimated oil and gas reserves and
the estimated net realizable value of the assets of discontinued operations.
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.
F-8
45
No gains or losses are recognized upon the disposition of oil and gas properties
except in extraordinary transactions. Sales proceeds are credited to the
carrying value of the properties. Maintenance and repairs are expensed, and
expenditures which enhance the value of properties are capitalized.
Unproved oil and gas properties are stated at cost and consist of
undeveloped leases. These costs are assessed periodically to determine whether
their value has been impaired, and if impairment is indicated, the costs are
charged to expense.
Gas gathering systems are stated at cost. Depreciation expense is
computed using the straight-line method over 15 years.
Property and equipment are stated at cost. Depreciation of non-oil and
gas properties is computed using the straight-line method over the useful lives
of the assets ranging from 3 to 15 years for machinery and equipment and 30 to
40 years for buildings. When assets other than oil and gas properties are
retired or otherwise disposed of, the cost and related accumulated depreciation
are removed from the accounts, and any resulting gain or loss is reflected in
income for the period. The cost of maintenance and repairs is charged to income
as incurred, and significant renewals and betterments are capitalized.
NET INCOME PER COMMON SHARE
- ---------------------------
Net income per common share is computed by subtracting preferred
dividends from net income and dividing the difference by the weighted average
number of common and common equivalent shares outstanding. Outstanding options,
convertible securities and warrants are included in the computation of net
income per common share when their effect is dilutive.
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.
RECLASSIFICATIONS
- -----------------
Certain reclassifications have been made in 1995 and 1994 to conform to
the presentation in 1996.
(2) ACCOUNTING CHANGES
During 1996, the Company adopted Statement of Financial Accounting
Standards (SFAS) 123, "Accounting for Stock-Based Compensation." Under SFAS 123,
companies may elect to adopt the fair value method of accounting for stock-based
compensation or continue to use Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" (APB 25) to measure expense
associated with stock-based compensation. The Company has elected to continue to
follow APB 25. See Note 8.
F-9
46
During 1996, the Company adopted SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of."
This statement requires impairment losses to be recognized for long-lived assets
(other than unproved properties) used in continuing operations when indicators
of impairment are present and the assets' carrying value is not anticipated to
be recovered through future operations or sale. No impairment was required as a
result of adopting SFAS 121.
(3) ACQUISITIONS
The following acquisitions were accounted for as purchase business
combinations. Accordingly, the results of operations of the acquired businesses
are included in the Company's consolidated statements of operations from the
date of the respective acquisitions.
During 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 in 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. Ward Lake operates and holds 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. The production from certain interests qualify for
nonconventional fuel source tax credits.
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.
In January 1994, the Company purchased substantially all of TGX
Corporation's Appalachian Basin assets for $15.5 million. The assets acquired
included 1,034 gross (910 net) gas and oil wells on approximately 121,000 acres
located in northeastern Ohio and southwestern New York and 15,000 undeveloped
acres and related inventory, real estate and oilfield equipment. At December 31,
1993, the properties acquired had estimated proved reserves of 22.0 Bcf of
natural gas and 28,700 Bbls of oil.
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 were revenues of $124.9 million, net income
F-10
47
of $8.5 million and net income per common share of $.75. The pro forma effects
of the 1996 acquisitions were not material.
(4) DETAILS OF BALANCE SHEETS
DECEMBER 31
-----------------------------
1996 1995
------------- -------------
ACCOUNTS RECEIVABLE (IN THOUSANDS)
Accounts receivable $ 16,675 $ 16,096
Allowance for doubtful accounts (556) (269)
Oil and gas production receivable 16,729 11,610
Current portion of notes receivable 675 686
------------- -------------
$ 33,523 $ 28,123
============= =============
INVENTORIES
Oil $ 1,578 $ 1,574
Natural gas 375 170
Material, pipe and supplies 7,444 7,509
------------- -------------
$ 9,397 $ 9,253
============= =============
PROPERTY AND EQUIPMENT, GROSS
OIL AND GAS PROPERTIES
Producing properties $ 247,651 $ 214,984
Non-producing properties 10,277 11,286
Other 8,593 9,074
------------- -------------
$ 266,521 $ 235,344
============= =============
LAND, BUILDINGS, MACHINERY AND EQUIPMENT
Land, buildings and improvements $ 8,537 $ 8,748
Machinery and equipment 23,041 21,229
------------- -------------
$ 31,578 $ 29,977
============= =============
ACCRUED EXPENSES
Accrued expenses $ 8,617 $ 9,924
Accrued drilling and completion costs 658 4,902
Accrued income taxes 612 15
Ad valorem and other taxes 3,114 2,162
Compensation and related benefits 2,994 2,147
Undistributed production revenue 4,995 4,661
------------- -------------
$ 20,990 $ 23,811
============= =============
(5) LONG-TERM DEBT
Long-term debt consists of the following:
DECEMBER 31
-----------------------------
1996 1995
------------- -------------
(IN THOUSANDS)
Revolving line of credit $ 59,000 $ 67,000
Senior notes 35,000 35,000
Convertible subordinated debentures 5,550 6,800
Other 246 1,871
------------- -------------
99,796 110,671
Less current portion 3,918 1,648
------------- -------------
Long-term debt $ 95,878 $ 109,023
============= =============
F-11
48
The Company has a $200 million unsecured revolving credit facility with
a group of banks that matures on March 31, 2001. Outstanding balances under the
facility incurred interest at the Company's choice of either: (1) the one, two,
or three-month LIBOR plus 1.25% (6.81% for the three-month LIBOR interest rate
option at December 31, 1996) or (2) the bank's prime rate (8.25% at December 31,
1996). At December 31, 1996, amounts payable under this facility were at the
three-month LIBOR option with rates ranging from 6.78% to 6.84%. Borrowings
under the credit agreement are limited to the borrowing base as established
semi-annually by the bank group. The borrowing base at December 31, 1996 was $70
million. The Company believes that its oil and gas reserves at December 31, 1996
could provide a borrowing base in excess of $115 million.
When market conditions are favorable, the Company may enter into
interest rate swap arrangements, whereby a portion of the Company's floating
rate exposure is exchanged for a fixed interest rate. The Company had no such
derivative financial instruments at December 31, 1996 or 1995.
The Company has $35 million of 7% fixed-rate senior notes outstanding
with five insurance companies. These notes, which are interest-only through
1996, mature on September 30, 2005. Equal principal payments of $3,888,888 will
be required on each September 30 commencing in 1997.
The convertible subordinated debentures have a fixed interest rate of
9.25% and mature on June 30, 2000. The debentures are currently convertible by
the debenture holders at the rate of one share of the Company's common stock for
each $20.15 of principal. During 1996, $1,250,000 of the debentures were
converted by the holders into 62,034 shares of common stock.
The debt agreements contain various covenants restricting payment of
dividends on common stock to $5 million plus 50% of cumulative net income,
restricting sales of assets to 15% of shareholders' equity in any one year and
requiring the maintenance of certain levels of net worth, working capital and
other financial ratios.
At December 31, 1996, the aggregate long-term debt maturing in the next
five years is as follows: $3,918,000 (1997); $3,907,000 (1998); $3,907,000
(1999); $9,457,000 (2000); $62,907,000 (2001); and $15,700,000 (2002 and
thereafter).
(6) 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 approximately $1.6 million, $1.4 million and $742,000
for the years ended December 31, 1996, 1995, and 1994, respectively. Future
commitments under leasing arrangements were not significant at December 31,
1996.
(7) SHAREHOLDERS' EQUITY
In December 1996 and 1995, the Company awarded 36,077 and 26,085 shares
of 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 common stock for each $20.15 of principal into 62,034 shares of common
stock.
In August 1995, the Company sold 4,025,000 shares of common stock. Net
proceeds, after deducting underwriting discounts and expenses, totaled
approximately $55.6 million. Approximately
F-12
49
$50 million of the net proceeds were used to purchase the Quaker State
Properties, and the remaining proceeds were used to reduce the outstanding
balance under the Company's revolving credit agreement.
Outstanding warrants for the purchase of 13,801 shares of the Company's
common stock at a price of $21.74 per share were exercisable by the holder in
whole or part any time prior to February 15, 1997. These warrants expired
unexercised on February 15, 1997.
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 common stock, each share is entitled to cumulative cash dividends of
$7.50 per year, payable quarterly. The Preferred Stock is subject to redemption
at $100 per share at any time by the Company and is convertible into 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 common share. Holders of the
Preferred Stock are entitled to one vote per preferred share. In February 1997,
the Company notified the preferred stockholder that it intended to redeem 100%
of the preferred stock for aggregate consideration of $2.4 million in March,
1997.
At December 31, 1996, the Company had reserved a total of 449,075
shares of common stock for the conversion of the convertible subordinated
debentures and the Class II Serial Preferred Stock and the exercise of the
outstanding warrants referred to above.
The Company's Articles of Incorporation include certain anti-takeover
provisions. The provisions grant the Board of Directors the authority to issue
and fix the terms of preferred stock as well as the ability to take certain
other actions that could have the effect of discouraging unsolicited takeover
attempts. In addition, the Company has entered into contracts with its officers
and other employees that provide for severance payments, in certain
circumstances, in the event that their employment is terminated following a
change in control. The senior notes may, at the noteholder's discretion, be
accelerated and become due and payable upon a change in control of the Company.
(8) STOCK OPTION PLANS
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 become exercisable in 25% increments over a four-year period beginning
one year from date of grant. As of December 31, 1996, there were 301,000 shares
available for grant under the Plan.
On May 27, 1994, the shareholders approved the 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. As of December 31, 1996,
there were 80,000 shares available for grant under the Plan.
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-13
50
Pro forma information regarding net income and earnings per share 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 and 1996, respectively: risk-free interest
rates of 6.4% and 6.5%; volatility factors of the expected market price of the
Company's common stock of .36 and .36; 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:
1996 1995
------------- -------------
Pro forma net income (in thousands) $ 14,286 $ 5,016
Pro forma earnings per share $ 1.25 $ .55
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 two plans consisted of the following:
WEIGHTED
AVERAGE
NUMBER OF EXERCISE
SHARES PRICE
------------ ------------
BALANCE DECEMBER 31, 1993 95,000 $10.00
Granted 193,000 12.38
------------
BALANCE DECEMBER 31, 1994 288,000 11.59
Granted 260,000 16.37
Exercised (2,250) 11.32
Forfeited (1,000) 10.00
------------
BALANCE DECEMBER 31, 1995 544,750 13.88
Granted 292,000 20.74
Exercised (3,250) 12.38
Forfeited (30,000) 15.75
------------
BALANCE DECEMBER 31, 1996 803,500 $16.31
============ ============
OPTIONS EXERCISABLE AT DECEMBER 31, 1996 225,525 $12.73
============ ============
The weighted average fair value of options granted during the years
1996 and 1995 were $10.59 and $8.27 per share, respectively. The exercise price
for the options outstanding as of December 31, 1996 ranged from $10.00 to $16.38
per share. At December 31, 1996 the weighted average remaining contractual life
of the outstanding options is 8.4 years.
F-14
51
(9) TAXES
The provision for income taxes on income from continuing operations
before income taxes in the Consolidated Statements of Operations includes the
following:
YEAR ENDED DECEMBER 31
----------------------------------------
1996 1995 1994
------------ ------------ -----------
(IN THOUSANDS)
CURRENT
Federal $ 2,011 $ 1,103 $ 454
State 217 111 190
------------ ------------ -----------
2,228 1,214 644
DEFERRED
Federal 4,257 826 1,539
State 81 110 147
------------ ------------ -----------
4,338 936 1,686
------------ ------------ -----------
TOTAL $ 6,566 $ 2,150 $ 2,330
============ ============ ===========
The effective tax rate for continuing operations differs from the U.S.
federal statutory tax rate, as follows:
YEAR ENDED DECEMBER 31
-------------------------------------
1996 1995 1994
----------- ---------- ----------
Statutory federal income tax rate 35.0 % 34.0 % 34.0 %
Increases (reductions) in taxes resulting from:
State income taxes, net of federal tax benefit 1.9 1.7 3.4
Nonconventional fuel source tax credits (5.9) (10.0) --
Statutory depletion (.6) (.3) (2.3)
Other, net (.2) .2 .7
----------- ---------- ----------
Effective income tax rate for the year 30.2 % 25.6 % 35.8 %
=========== ========== ==========
The effect of the federal rate change, which was not material, is
included in "Other".
Significant components of deferred income tax liabilities and assets
are as follows:
DECEMBER 31
-----------------------------
1996 1995
------------- -------------
(IN THOUSANDS)
Deferred income tax liabilities:
Property and equipment, net $ 16,195 $ 10,891
Other, net 762 155
------------- -------------
Total deferred income tax liabilities 16,957 11,046
Deferred income tax assets:
Accrued expenses 2,293 1,984
Inventories 360 212
Net operating loss carryforwards 667 966
Tax credit carryforwards 3,562 2,263
Other, net 404 182
------------- -------------
Total deferred income tax assets 7,286 5,607
------------- -------------
Net deferred income tax liability $ 9,671 $ 5,439
============= =============
Long-term liability $ 12,589 $ 7,693
Current asset (2,918) (2,254)
------------- -------------
Net deferred income tax liability $ 9,671 $ 5,439
============= =============
F-15
52
At December 31, 1996, the Company had approximately $1,800,000 of net
operating loss carryforwards available for federal income tax reporting
purposes. Substantially all of the net operating loss carryforwards are limited
as to their annual utilization as a result of prior ownership changes. The net
operating loss carryforwards, if unused, will expire from 2002 to 2009. The
Company has alternative minimum tax credit carryforwards of approximately
$3,562,000 which have no expiration date.
Included in "Franchise, property and other taxes" are property taxes
associated with production activities of $203,000, $163,000 and $108,000 for the
years 1996, 1995 and 1994, respectively.
(10) 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 $1,256,600,
$458,000 and $340,000 for the years 1996, 1995 and 1994, 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. Retirement plan expense for 1996, 1995 and 1994
was $457,332, $372,213 and $286,446, respectively.
The Company has non-qualified deferred compensation plans which permit
certain key employees and directors to elect to defer a portion of their
compensation.
(11) 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.
(12) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
YEAR ENDED DECEMBER 31
----------------------------------
1996 1995 1994
---------- ---------- ----------
CASH PAID DURING THE YEAR FOR: (IN THOUSANDS)
Interest $ 7,830 $ 5,592 $ 3,146
Income taxes 1,222 1,296 90
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Acquisition of assets in exchange for long-term liabilities $ -- $ 8,460 $ 527
Debentures converted to common stock 1,250 -- --
Acquisition of assets in exchange for common stock -- -- 388
Sale of assets in exchange for note receivable -- -- 689
F-16
53
(13) 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 preferred stock is
redeemable at $100 per share plus unpaid dividends. The following table reflects
the financial instruments for which the fair value differs from the carrying
amount of such financial instrument in the Company's December 31, 1996 and 1995
balance sheets:
1996 1995
--------------------------- --------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
------------ ------------ ------------ ------------
(IN THOUSANDS)
Assets
Amounts receivable $ 5,659 $ 6,976 $ 6,764 $ 8,440
Liabilities
Senior notes 35,000 34,500 35,000 35,200
Convertible subordinated debentures 5,550 7,024 6,800 7,117
The fair value of the amounts receivable is based on the discounted
expected future cash flows. The fair value of the senior notes is based on rates
available at year-end for similar instruments. The fair value of the convertible
subordinated debentures at December 31, 1996 is based on the conversion rate of
$20.15 and valuing the common shares at the December 31, 1996 closing stock
price of $25.50. The fair value of the convertible subordinated debentures at
December 31, 1995 is based on rates available for similar instruments.
(14) 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 No. 69.
YEAR ENDED DECEMBER 31
----------------------------------------
1996 1995 1994
----------- ----------- ------------
(IN THOUSANDS)
Acquisition costs
Proved properties $ 4,275 $ 79,464 $ 20,274
Unproved properties 2,320 4,705 1,744
Developmental costs 30,750 19,906 9,142
Exploratory costs 6,131 4,968 2,130
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
F-17
54
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.
The following table sets forth changes in estimated proved and proved
developed reserves for the three years ended December 31, 1996:
OIL GAS
(BBL) (MCF)
-------------- --------------
DECEMBER 31, 1993 3,532,879 94,264,949
Extensions and discoveries 242,365 8,554,382
Purchase of reserves in place 222,981 26,876,534
Sales of reserves in place (11,178) (1,022,027)
Revisions of previous estimates 622,462 3,880,633
Production (496,039) (9,562,862)
---------- ------------
DECEMBER 31, 1994 4,113,470 122,991,609
Extensions and discoveries 229,957 22,287,564
Purchase of reserves in place 2,197,414 111,360,991
Sale of reserves in place (28,693) (278,013)
Revisions of previous estimates 326,771 (419)
Production (555,913) (16,961,424)
---------- ------------
DECEMBER 31, 1995 6,283,006 239,400,308
Extensions and discoveries 387,414 38,079,620
Purchase of reserves in place 336,279 8,182,402
Sale of reserves in place (7,664) (250,021)
Revisions of previous estimates 1,108,538 28,601,277
Production (718,667) (25,410,233)
---------- ------------
DECEMBER 31, 1996 7,388,906 288,603,353
========== ============
PROVED DEVELOPED RESERVES
December 31, 1994 3,714,671 101,355,451
========== ============
December 31, 1995 5,592,579 206,998,924
========== ============
December 31, 1996 6,410,344 225,693,651
========== ============
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.
F-18
55
_ Production and development costs were computed using year-end
costs assuming no change in present economic conditions.
_ Future net cash flows were discounted at an annual rate of 10%.
_ Future income taxes were computed using the approximate
statutory tax rate and giving effect to available net
operating losses, tax credits and statutory depletion.
The standardized measure of discounted future net cash flows relating
to proved oil and gas reserves is presented below:
DECEMBER 31
------------------------------------------------
1996 1995 1994
-------------- -------------- --------------
(IN THOUSANDS)
Estimated future cash inflows (outflows)
Revenues from the sale of oil and gas $ 1,087,997 $ 679,286 $ 395,610
Production and development costs (419,504) (293,601) (165,766)
-------------- -------------- --------------
Future net cash flows before income taxes 668,493 385,685 229,844
Future income taxes (185,768) (80,715) (54,762)
-------------- -------------- --------------
Future net cash flows 482,725 304,970 175,082
10% timing discount (223,496) (134,053) (85,228)
-------------- -------------- --------------
Standardized measure of discounted
future net cash flows $ 259,229 $ 170,917 $ 89,854
============== ============== ==============
The principal sources of changes in the standardized measure of future
net cash flows are as follows:
YEAR ENDED DECEMBER 31
------------------------------------------------
1996 1995 1994
-------------- -------------- ----------------
(IN THOUSANDS)
Beginning of year $ 170,917 $ 89,854 $ 71,086
Sale of oil and gas, net of
production costs (58,023) (32,874) (23,287)
Extensions and discoveries, less
related estimated future
development and production costs 60,738 24,441 14,317
Purchase of reserves in place less
estimated future production costs 10,694 104,270 20,715
Sale of reserves in place less
estimated future production costs (191) (329) (635)
Revisions of previous quantity estimates 38,204 1,129 4,972
Net changes in prices and production costs 83,530 (4,723) 94
Change in income taxes (55,494) (17,756) (8,852)
Accretion of 10% timing discount 21,425 11,647 8,944
Changes in production rates (timing)
and other (12,571) (4,742) 2,500
-------------- -------------- ----------------
End of year $ 259,229 $ 170,917 $ 89,854
============== ============== ================
F-19
56
(15) 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.
1996 1995 1994
--------- --------- ---------
REVENUES (IN THOUSANDS)
- --------
Oil and gas operations $ 124,294 $ 88,632 $ 65,646
Oilfield sales and service 32,827 25,178 17,360
Intersegment sales (7,310) (5,112) (4,203)
--------- --------- ---------
$ 149,811 $ 108,698 $ 78,803
========= ========= =========
OPERATING INCOME
- ----------------
Oil and gas operations $ 24,756 $ 12,444 $ 9,104
Oilfield sales and service 963 673 350
--------- --------- ---------
$ 25,719 $ 13,117 $ 9,454
========= ========= =========
IDENTIFIABLE ASSETS
- -------------------
Oil and gas operations $ 281,761 $ 274,021 $ 132,538
Oilfield sales and service 20,492 20,348 12,408
--------- --------- ---------
$ 302,253 $ 294,369 $ 144,946
========= ========= =========
DEPRECIATION, DEPLETION AND
- ---------------------------
AMORTIZATION EXPENSE
--------------------
Oil and gas operations $ 28,598 $ 18,729 $ 11,343
Oilfield sales and service 1,154 988 543
--------- --------- ---------
$ 29,752 $ 19,717 $ 11,886
========= ========= =========
CAPITAL EXPENDITURES
- --------------------
Oil and gas operations $ 35,486 $ 129,219 $ 33,956
Oilfield sales and service 1,240 4,735 3,391
--------- --------- ---------
$ 36,726 $ 133,954 $ 37,347
========= ========= =========
No customer exceeded 10% of consolidated revenue during the year ended
December 31, 1996. One customer exceeded 10% of consolidated revenue during each
of the years ended December 31, 1995 and 1994 which amounted to $11.1 million
and $9.6 million, respectively.
(16) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The results of operations for the four quarters of 1996 and 1995 are
shown below.
FIRST SECOND THIRD FOURTH
------------ ----------- ------------ -----------
1996 (IN THOUSANDS, EXCEPT PER SHARE DATA)
- -----
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
Net income per common share .30 .30 .28 .42
1995
Sales and other operating revenues $ 20,872 $ 22,063 $ 30,566 $ 35,197
Gross profit 3,250 3,865 5,178 5,288
Net income 739 916 1,155 2,311
Net income per common share .10 .12 .11 .20
F-20
57
Income tax expense in the fourth quarter of 1995 was reduced by
approximately $600,000 to record the reduction of the effective tax rate for the
first nine months of 1995 as a result of the recognition of nonconventional fuel
source tax credits.
(17) 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.
Since September 1995, a substantial portion of the workforce was eliminated and
substantial assets were sold. The Company recognized an additional charge in
1996 to reduce the remaining assets to net realizable value. Net revenues
generated by EPS were approximately $3.9 million in 1996, $4.2 million in 1995
and $3.7 million in 1994. The results of operations of EPS are presented as
discontinued operations in the accompanying financial statements for all periods
presented.
YEAR ENDED DECEMBER 31
-------------------------------------------
1996 1995 1994
-------------- ------------- -------------
(IN THOUSANDS)
Loss from operations of discontinued business $ (180) $ (760) $ (509)
Income tax benefit 63 268 172
-------------- ------------- -------------
(117) (492) (337)
Estimated loss on disposal (495) (1,001) --
Income tax benefit 173 354 --
-------------- ------------- -------------
(322) (647) --
-------------- ------------- -------------
LOSS FROM DISCONTINUED OPERATIONS $ (439) $ (1,139) $ (337)
============== ============= =============
(18) 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.
(19) HEDGING ACTIVITIES
As a result of certain 1995 acquisitions, the Company has several
contracts to sell gas at indexed prices. In early 1996, the Company's Board of
Directors approved a formal policy covering hedging with financial instruments.
Significant provisions of this policy are that targets are pre-defined and
transactions are pre-authorized by senior management; all transactions must meet
the accounting definition of a hedge; basis risk must be hedged; leveraged
transactions are prohibited and quarterly reports must be made to the Board of
Directors on all open positions.
The Company may, from time to time, partially hedge indexed contract
price exposure by selling futures contracts on the NYMEX. During 1996, the
Company incurred a net $258,000 pretax loss on its hedging activities due to
rapidly rising gas prices during the year. At December 31, 1996, the Company did
not have any open futures contracts.
When market conditions are favorable, the Company may enter into
interest rate swap arrangements, whereby a portion of the Company's floating
rate exposure is exchanged for a fixed interest rate. The Company had no such
derivative financial instruments at December 31, 1996 or 1995.
F-21
58
EXHIBIT INDEX
-------------
Location in
Sequentially
No. Description Numbered Copy
--- ----------- ------------
3.1 Articles of Incorporation of the
Company--incorporated by reference to Exhibit 3.1
to the Company's Registration Statement on Form
S-4 (Registration No. 33-43209)
3.2 Amended Articles of Incorporation to the
Company-- incorporated by reference to Exhibit
3.2 to the Company's Registration Statement on
Form S-4 (Registration No. 33-43209)
3.2(a) Amendment to Amended Articles of Incorporation of
the Company--incorporated by reference to Exhibit
4 to the Company's Current Report on Form 8-K
dated December 30, 1992
3.3 Amended Code of Regulations of the Company--
incorporated by reference to Exhibit 3.3 to the
Company's Registration Statement on Form S-4
(Registration No. 33-43209)
4.1 Amended and Restated Debenture Agreement between
the Company and Petercam Securities--incorporated
by reference to Exhibit 4.1 to the Company's
Registration Statement on Form S-4 (Registration
No. 33-43209)
4.2(a) Credit Agreement among the Company, The Canton
Oil & Gas Company, Peake Energy, Inc., Peake
Operating Company, Bank One, Texas, National
Association and NBD Bank, N.A. dated November
1993--incorporated by reference to Exhibit 4.2 to
the Company's Annual Report on Form 10-K for the
year ended December 31, 1993
4.2(b) First Amendment to Credit Agreement among the
Company, The Canton Oil & Gas Company, Peake
Energy, Inc., Bank One, Texas, National
Association and NBD Bank, N.A., effective as of
August 1, 1994--incorporated by reference to
Exhibit 4.2(b) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1995
4.2(c) Second Amendment to Credit Agreement among the
Company, The Canton Oil & Gas Company, Peake
Energy, Inc., Ward Lake
59
Drilling, Inc., Bank One, Texas, National Association
and NBD Bank, N.A., effective as of March 29,
1995--incorporated by reference to Exhibit 4.2(c)
to the Company's Annual Report on Form 10-K for
the year ended December 31, 1995
4.2(d) Third Amendment to Credit Agreement among the
Company, The Canton Oil & Gas Company, Ward Lake
Drilling, Inc., Bank One, Texas, National
Association and NBD Bank, N.A., effective as of
May 25, 1995-- incorporated by reference to
Exhibit 4.2(d) to the Company's Annual Report on
Form 10-K for the year ended December 31, 1995
4.2(e) Fourth Amendment to Credit Agreement among the
Company, The Canton Oil & Gas Company, Peake
Energy, Inc., Ward Lake Drilling, Inc., Bank One,
Texas, National Association and NBD Bank, N.A.,
effective as of February 15, 1996--incorporated
by reference to Exhibit 4.2(e) to the Company's
Annual Report on Form 10-K for the year ended
December 31, 1995
4.3 Warrant Assumption Agreement between Belden &
Blake Corporation and Belden & Blake Energy
Company-- incorporated by reference to Exhibit
4.4 to the Company's Annual Report on Form 10-K
for the year ended December 31, 1992
4.4 Note Purchase Agreement dated as of November 15,
1993 among the Company, The Canton Oil & Gas
Company, Peake Operating Company and Peake
Energy, Inc. and the purchasers listed on Annex I
thereto--incorporated by reference to Exhibit 4.5
to the Company's Annual Report on Form 10-K for
the year ended December 31, 1993
4.5 None of the other instruments defining the rights
of holders of long-term debt of the Company or
its subsidiaries involve long-term debt in an
amount which exceeds ten percent of the total
assets of the Company and its subsidiaries on a
consolidated basis. The Company agrees to furnish
a copy of such other instruments to the
Commission upon request.
10.1 Amended and Restated Employment Agreement between
the Company and Henry S. Belden IV--incorporated
by reference to Exhibit 10.1 to the Company's
Quarterly Report on Form 10-Q for the quarter
ended September 30, 1996
10.2 Severance Agreement between the Company and Max
L. Mardick--incorporated by reference to Exhibit
10.2 to the
60
Company's Quarterly Report on Form
10-Q for the quarter ended September 30, 1996
10.3 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
10.4 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
10.5 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
10.6(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)
10.6(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)
10.7 Restricted Stock Grant Plan of The Canton Oil &
Gas Company (formerly known as Belden & Blake
Corporation)--incorporated by reference to
Exhibit 10.8 to the Company's Registration
Statement on Form S-4 (Registration No. 33-43209)
10.8 Belden & Blake Corporation Non-employee Director
Stock Option Plan--incorporated by reference to
Exhibit 10.6 to the Company's Annual Report on
Form 10-K for the year ended December 31, 1993
10.9 Plan and Agreement of Consolidation dated as of
October 10, 1991, as amended, among Belden &
Blake Energy Company, Henry S. Belden IV, Belden
& Blake International Limited and
61
the Company--incorporated by reference to Exhibit
2.1 to the Company's Registration Statement on Form
S-4 (Registration No. 33-43209)
10.10 Amended and Restated Gas Sales and Purchase
Contract between Peake Energy, Inc. and Kaiser
Aluminum & Chemical Corporation dated as of
August 27, 1987-- incorporated by reference to
Exhibit 10.11 to the Company's Registration
Statement on Form S-1 (Registration No. 33-60228)
10.11(a) Stock Purchase Agreement dated January 3, 1995
among Keith Hardin Gornick, R. David Briney,
William F. Rolinski, Charles Nelson and the
Company--incorporated by reference to Exhibit 2.1
to the Company's Current Report on Form 8-K dated
February 10, 1995
10.11(b) Agreement of Amendment dated January 16, 1995
among Keith Hardin Gornick, R. David Briney,
William F. Rolinski, Charles Nelson and the
Company--incorporated by reference to Exhibit 2.2
to the Company's Current Report on Form 8-K dated
February 10, 1995
10.11(c) Second Agreement of Amendment dated February 10,
1995 among Keith Hardin Gornick, R. David Briney,
William F. Rolinski, Charles Nelson and the
Company--incorporated by reference to Exhibit 2.3
to the Company's Current Report on Form 8-K dated
February 10, 1995
10.12 Asset Purchase Agreement dated July 26, 1995
among Quaker State Corporation, QSE&P, Inc. and
the Company-- incorporated by reference to
Exhibit 2 to the Company's Current Report on Form
8-K dated August 9, 1995
21* Subsidiaries of the Registrant
23* Consent of Ernst & Young LLP
27* Financial Data Schedule
*Filed herewith