Item 1. BUSINESS
Belden & Blake Corporation ("successor company") and its predecessor were acquired by TPG Partners II L.P. ("TPG") and certain other investors on June 27, 1997 ("the Acquisition"). The operations of the successor company represent 100% of the businesses of the predecessor. Therefore certain operational data for the twelve months ended December 31, 1997 have been presented on a combined basis because such information is comparable to the historical data of the predecessor and the current data of the successor.
The historical financial statements of the successor company and its predecessor are presented separately as described in Note 1 to the consolidated financial statements included under Item 8.
GENERAL
Belden & Blake Corporation, an Ohio corporation (the "Company"), is an integrated energy company engaged in marketing natural gas directly to end users in a six state area; producing oil and natural gas; acquiring and enhancing the economic performance of producing oil and natural gas properties; exploring for and developing natural gas and oil reserves; and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. Until 1995, the Company conducted business exclusively in the Appalachian Basin where it has operated since 1942 through several predecessor entities. It is a fast-growing independent natural gas marketer and one of the largest gas producers operating in the Appalachian, Michigan, and Illinois Basins (the Company operates in Ohio, Pennsylvania, New York, West Virginia, Michigan and Kentucky). In early 1995, the Company commenced gas marketing, production and drilling operations in the Michigan Basin through the acquisition of Ward Lake Drilling, Inc. ("Ward Lake"), an independent energy company, which markets gas and owns and operates oil and gas properties in Michigan's lower peninsula. In September 1996, the Company entered the Illinois Basin by acquiring a natural gas gathering system and the Shrewsbury Gas Field in western Kentucky.
At December 31, 1998, the Company marketed approximately 149 Mmcf (million cubic feet) of natural gas per day to more than 360 commercial and industrial customers. Approximately 58% of such marketed gas represented the Company's own production, with the balance purchased from third parties. The Company owned and operated approximately 2,600 miles of gas gathering systems with access to the commercial and industrial gas markets of the northeastern United States at December 31, 1998.
At December 31, 1998, the Company's net production was approximately 86 Mmcf of gas and 2,194 Bbls (barrels) of oil per day. At that date the Company owned interests in 8,069 gross (7,101 net) productive gas and oil wells in Ohio, West Virginia, Pennsylvania, New York, Michigan and Kentucky with proved reserves totaling 315.3 Bcf (billion cubic feet) of gas and 4.2 Mmbbl (million barrels) of oil. The estimated future net cash flows from these reserves had a present value (discounted at 10 percent) before income taxes of approximately $256.6 million at December 31, 1998. At December 31, 1998, the Company operated approximately 7,850 wells, including wells operated for third parties. At that date, the Company held leases on 1,410,888 gross (1,206,211 net) acres, including 770,534 gross (646,646 net) undeveloped acres.
The Company's production and reserves have grown principally through the acquisition of producing properties and related gas gathering facilities and exploration and development of its own acreage. From its formation in March 1992 through December 31, 1998, the Company acquired for $158.3 million producing properties with 235.2 Bcfe (billion cubic feet of natural gas equivalent) of proved developed reserves at an average cost of $0.67 per Mcfe (thousand cubic feet of natural gas equivalent) and spent $21.6 million to acquire and develop additional gas gathering facilities. During the period from 1992 through 1998, the Company drilled 1,057 gross (808.7 net) wells at an aggregate cost of approximately $151.2 million for the net wells. This drilling added 159.3 Bcfe to the Company's proved reserves. During 1998, the Company drilled 249 gross (199.2 net) wells at a direct cost of approximately $36.0 million for the net wells. The 1998 drilling activity added 35.3 Bcfe of proved developed reserves at an average cost of $1.02 per Mcfe. Proved developed reserves added through drilling in 1998 represent approximately 102% of 1998 production.
The Company maintains its corporate offices at 5200 Stoneham Road, North Canton, Ohio 44720. Its telephone number at that location is (330) 499-1660. Unless the context otherwise requires, all references herein to the "Company" are to Belden & Blake Corporation, its subsidiaries and predecessor entities.
SIGNIFICANT EVENTS
In July 1998, the Company began development of a major expansion of its gas marketing capability with the objective of substantially increasing the number of commercial and industrial customers served, the volumes of gas sold and the Company's future net operating margins from gas sales. The expansion includes the selection and installation of systems and technology to enhance the efficiency of the gas marketing operation. During 1998, $731,000 was expensed and $924,000 was capitalized relating to this expansion project. See Note 6 to the consolidated financial statements.
In conjunction with the expansion of its gas marketing capability, the Company formed Belden Energy Services Company ("BESCO"), a wholly-owned subsidiary, in September 1998. BESCO was formed to market natural gas to retail and wholesale customers in the midwestern and northeastern United States. BESCO may elect to expand its retail and wholesale marketing activities to electricity as the marketing of this commodity is deregulated in its area of operations. Through the use of internally developed and licensed marketing programs, BESCO increased the number of commercial and industrial customers it serves by 44% from October 1998 through February 1999. BESCO's objective is to significantly increase the number of commercial and industrial customers served in 1999.
RECENT DEVELOPMENTS
SUBSEQUENT EVENTS
On January 15, 1999, the Company was notified that the several lenders under its revolving credit agreement had reduced the Company's borrowing base from $170 million to $126 million. The Company's outstanding borrowings on that date exceeded the redetermined borrowing base by $28 million. Under the terms of the existing credit agreement, the Company is required to prepay 50% of such excess by April 15, 1999 and the balance by July 14, 1999, unless the lenders and the Company otherwise agree.
The Company and its lenders have agreed to a required prepayment of $14 million on March 22, 1999 and an additional $14 million on May 10, 1999. In conjunction with this agreement, the Company
has been granted a waiver by the lenders of certain terms of its working capital ratio covenant. As a result, as of December 31, 1998, the Company has met all covenants under the credit agreement.
On March 22, 1999, the Company made a $14 million payment to reduce the outstanding amount under the credit agreement to $140 million. The funds for the payment were provided by internally generated cash flow and a term loan provided by Chase Manhattan Bank. This term loan provided borrowings of $9 million and is due on September 22, 1999. Interest is payable monthly at LIBOR plus 1.5%. The Company is in the process of renegotiating its revolving credit facility with its lenders and expects to have a new facility in place prior to May 10, 1999, when the second payment of $14 million is due. Should the Company not be successful in renegotiating an acceptable facility, the Company expects to be able to meet its 1999 debt service requirements through internally generated cash flow, the sale of non-strategic assets and/or the use of instruments in financial futures markets.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The Company's operations are conducted in the United States and are managed along three reportable segments which include: (1) exploration and production, (2) gas marketing and gathering and (3) oilfield sales and service. The information with respect to the Company's operating segments is shown in Note 18 to the consolidated financial statements.
DESCRIPTION OF BUSINESS
OVERVIEW
The Company, founded in 1942, is actively engaged in natural gas marketing and gathering, and the production, acquisition, exploration and development of natural gas and oil in the Appalachian, Michigan and Illinois Basins. The Company operates principally in the Appalachian and Michigan Basins (a region which includes Ohio, Pennsylvania, New York, West Virginia and Michigan) where it is a fast-growing natural gas marketer and one of the largest gas producers. It commenced operations in Kentucky in September 1996, which marked its entrance into the Illinois Basin.
The Company has been selling natural gas directly to commercial and industrial customers since 1974. The major industrial centers of Akron, Buffalo, Canton, Cleveland, Detroit, Grand Rapids and Pittsburgh are all located in close proximity to the Company's production operations and along with other urban areas in the midwestern and northeastern United States provide a large potential market for direct natural gas sales. The states of Ohio, Pennsylvania, New York and Michigan account for approximately 19% of the natural gas consumed in the United States. These states produce in aggregate less than 16% of the gas they consume on an annual basis.
The Company focuses its gas marketing efforts on commercial customers and small to mid-sized industrial customers that require more service and have the potential to generate higher margins per Mcf than large industrial users. The Company currently markets natural gas to approximately 500 commercial and industrial customers and various local gas distribution companies in its region of operations. It currently markets approximately 149 million cubic feet of gas per day, of which more than 85% consists of its own production and production it controls through operations.
The Company's capability to market gas directly to end users is enhanced by its ability to deliver gas through its approximately 2,600 miles of gathering systems. The Company's gathering systems can interconnect with local gas distribution companies and the many interstate gas pipelines that traverse its operating region, thus allowing the Company to deliver gas throughout its primary marketing area.
The proximity of the Appalachian and Michigan Basins to large commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices that since 1986 have ranged from $0.31 to $1.30 per Mcf (thousand cubic feet) above national wellhead prices. The Company's average wellhead gas price in 1998 was $0.57 per Mcf above the estimated average national wellhead price. The Company believes that its growing natural gas production base in these premium markets enhances its gas marketing ability and the net margins it is able to secure for its marketed gas.
The Appalachian Basin is the oldest and geographically one of the largest oil and gas producing regions in the United States. Although the Appalachian Basin has sedimentary formations indicating the potential for oil and gas reservoirs to depths of 30,000 feet or more, oil and gas is currently produced primarily from shallow, highly developed blanket formations at depths of 1,000 to 5,500 feet. Drilling success rates of the Company and others drilling in these formations historically have exceeded 90% with production generally lasting longer than 20 years.
The combination of long-lived production and high drilling success rates at these shallower depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the Appalachian Basin. As of December 31, 1998, there were over 10,000 independent operators of record and approximately 175,000 producing oil and gas wells in Ohio, West Virginia, Pennsylvania and New York. There has been only limited testing or development of the formations below the existing shallow production in the Appalachian Basin. Fewer than 2,500 wells have been drilled to a depth greater than 7,500 feet, and fewer than 100 wells have been drilled to a depth greater than 12,500 feet in the entire Appalachian Basin. As a result, the Company believes there are significant exploration and development opportunities in these less developed formations for those operators with the capital, technical expertise and ability to assemble the large acreage positions needed to justify the use of advanced exploration and production technologies.
In January 1995, the Company purchased Ward Lake Drilling, Inc., a privately-held energy company headquartered in Gaylord, Michigan, and commenced operations in the Michigan Basin. At the time of purchase, Ward Lake operated approximately 500 Antrim Shale gas wells producing approximately 41 Mmcf per day in Michigan's lower peninsula. The Company's primary objective in acquiring Ward Lake was to allow the Company to pursue gas marketing and production opportunities in the Michigan Basin with an established operating company that provided the critical mass to operate efficiently. Ward Lake currently operates approximately 700 wells producing approximately 57 Mmcf per day in Michigan.
In September 1996, the Company commenced operations in the Illinois Basin by acquiring a 100% working interest in 98 natural gas wells and an extensive gas gathering system in the Shrewsbury Gas Field located in western Kentucky.
The Company's rationale for entering the Michigan and Illinois Basins was based on their geologic and operational similarities to the Appalachian Basin, their geographic proximity to the Company's operations in the Appalachian Basin and their proximity to premium gas markets. Geologically, the Michigan and Illinois Basins resemble the Appalachian Basin with shallow blanket formations and deeper formations with greater reserve potential. Operationally, economies of scale and
cost containment are essential to operating profitability. The operating environment in each of these basins is also highly fragmented with substantial acquisition opportunities.
Most of the Company's production in the Michigan Basin is derived from the shallow (700 to 1,700 feet) blanket Antrim Shale formation which has not been extensively developed. Success rates for companies drilling to this formation have exceeded 90%, with production often lasting as long as 20 years. The Michigan Basin also contains deeper formations with greater reserve potential. The Company has also established production from certain of these deeper formations through its drilling operations. The Michigan Basin has approximately 200 operators of record, most of which are private companies, and more than 9,500 producing wells. Because the production rate from Antrim Shale wells is relatively low, cost containment is a crucial aspect of operations. In contrast to the shallow, highly developed blanket formations in the Appalachian Basin, the operating environment in the Antrim Shale is more capital intensive because of the low natural reservoir pressures and the high initial water content of the formation.
The Company's production in the Illinois Basin is primarily from the New Albany Shale formation, which is a stratigraphic equivalent of the Antrim Shale formation. The New Albany Shale has likewise not been widely developed. The New Albany Shale has similar operating characteristics to shale formations in the adjacent Appalachian and Michigan Basins from which the Company is currently producing.
BUSINESS STRATEGY
The Company seeks to increase shareholder value by increasing cash flow through the integration of its proactive gas marketing operations with a growing base of primarily natural gas production and a balanced program of strategic acquisitions and exploration and development drilling. Specifically, the Company believes that being able to control the flow of natural gas from the wellhead to the burner tip end user will maximize the economic rewards to the Company and its shareholders. The key elements of the Company's strategy are as follows:
o EXPAND NATURAL GAS MARKETING AND GATHERING. The Company is located and operates in an area of major United States gas markets. The recent deregulation of natural gas markets by various states and the beginning of "open access" to these markets to independent gas marketers creates the opportunity for the Company to greatly expand its commercial and industrial customer base. There are an estimated 510,000 commercial and industrial natural gas customers in Ohio, Pennsylvania and Michigan alone. While the Company has been marketing directly to large industrial end users since 1974, much of the commercial and smaller industrial market has been under the monopoly control of local gas distribution companies ("LDCs") franchised and regulated by the various states.
The Company's extensive gas gathering systems enhance its ability to market its own production and purchased gas throughout its marketing region. The gathering systems' ability to connect to local distribution systems and interstate pipelines further enables the Company to deliver gas to premium gas markets. The Company's gas gathering systems are also integral to the Company's low cost structure and high revenues per unit of gas production. It is the Company's intention to expand its gas gathering systems, to include the addition of storage capacity, in order to further enhance its gas marketing capability and to improve the rate of return on the Company's drilling and development activities.
o PURSUE CONSOLIDATION OPPORTUNITIES. There is a continuing trend toward consolidation in the energy industry in general. The basins in which the Company operates are highly fragmented. The Company believes this provides the basis for significant acquisition opportunities as capital constrained operators, the majority of which are privately held, seek liquidity or operating capital. The Company intends to capitalize on its geographic knowledge, technical expertise, low cost structure and decentralized organization to pursue additional strategic acquisitions in its area of operations.
The Company's acquisition strategy focuses on acquiring producing properties that: (i) are properties in which the Company already owns an interest and operates or that are strategically located in relation to its existing operations, (ii) have the potential for increased revenues resulting from the Company's gas marketing capabilities, (iii) can be enhanced through operating cost reductions, advanced production technologies, mechanical improvements, recompleting or reworking wells and/or the use of enhanced and secondary recovery techniques, (iv) provide development and exploratory drilling opportunities or opportunities to improve the Company's acreage position, or (v) are of sufficient size to allow the Company to operate efficiently in new areas.
o MAINTAIN A BALANCED DRILLING PROGRAM. It is the Company's intention to expand production and reserves through a balanced program of developmental and exploratory drilling. The Company believes that there are significant exploration and development opportunities in the less developed or deeper formations in the Appalachian and Michigan Basins and has identified numerous development and exploratory drilling locations in the deeper formations of these Basins. Originally, the Company's drilling budget for 1999 was approximately $28 million to drill 251 wells. However, due to continued depressed pricing in oil and gas markets and capital constraints as a result of the decrease in the Company's borrowing base, the drilling budget has been reduced to a minimal amount for 1999.
o UTILIZE ADVANCED TECHNOLOGY. The combination of long-lived production and high drilling success rates at the shallow depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the Appalachian Basin. The Company has been applying more advanced technology, including 3-D seismic, horizontal drilling, advanced fracturing techniques and enhanced oil recovery methods. The Company is implementing these techniques to improve drilling success rates, reserves discovered per well, production rates, reserve recovery rates and total economics in its operating area.
GAS MARKETING AND GATHERING
Gas Marketing. The Company began marketing natural gas directly to industrial end users in 1974 under the provisions of Ohio's Self Help Act. In 1993, the Federal Energy Regulatory Commission ("FERC") issued Order 636 which, along with other provisions, required pipelines to separate ("unbundle") their gas sales from their transportation services. Order 636 was designed to place all natural gas sellers on an equal footing. Subsequent to the issuance of Order 636, several states, including Michigan, Ohio and Pennsylvania, have passed legislation to remove the monopoly distribution authority previously granted to local gas distribution companies. Such legislation was intended to encourage competition among gas marketers and reduce the cost of gas to industrial, commercial and residential consumers.
In 1997 and 1998, various LDCs in Michigan, Ohio and Pennsylvania began pilot programs of open access to allow their small industrial, commercial and residential customers to purchase natural gas from other marketers, with the LDC continuing to provide physical delivery of the commodity. By the end of 1999 the two largest LDCs in Ohio and the largest LDC in western Pennsylvania are expected to afford full open access to all of their customers. The two largest LDCs in Michigan are similarly expected to be in a full open access status by the end of 2000. These LDCs in aggregate have an estimated 510,000 commercial and industrial customers.
In July 1998, the Company began development of a major expansion of its gas marketing capability with the objective of capturing a significant share of these newly-opened natural gas markets. The Company intends to substantially increase the number of commercial and industrial customers served, the volumes of gas sold and the Company's future net operating margins from gas sales. The expansion includes the selection and installation of systems and technology to enhance the efficiency of the gas marketing operation.
In conjunction with the expansion of its gas marketing capability, the Company formed BESCO, a wholly-owned subsidiary, in September 1998. BESCO was formed to market natural gas to wholesale and retail customers in the midwestern and northeastern United States independent of the Company's own natural gas production. Through BESCO the Company may elect to expand its wholesale and retail marketing activities in its market area to electricity as the marketing of this commodity is deregulated. Through the use of internally developed and licensed marketing programs, BESCO increased the number of commercial and industrial customers it serves by 44% from October 1998 through February 1999. BESCO's objective is to significantly increase the number of commercial and industrial customers served in 1999.
The major industrial centers of Akron, Buffalo, Canton, Cleveland, Columbus, Detroit, Grand Rapids, Pittsburgh and Toledo are all located in BESCO's market area and provide a very large potential market for retail and wholesale natural gas sales. At present, BESCO markets gas directly to approximately 500 customers in a six-state area. BESCO intends to focus its gas marketing efforts on commercial and small to mid-sized industrial customers that require more service and have the potential to generate higher margins per Mcf than large industrial users.
The Company sells the gas it produces to its commercial and industrial customers, local distribution companies and on the spot market. In addition to its own production, the Company buys gas from other producers and third parties and resells it. At December 31, 1998, the Company marketed approximately 149 Mmcf of gas per day of which approximately 58% consisted of its own production. Gas sold by the Company to end users and local distribution companies is usually sold pursuant to contracts which extend for periods of one or more years at either fixed prices or market sensitive prices. Gas sold on the spot market is generally priced on the basis of a regional index. Since late 1995, the Company has attempted to maintain a balance between gas volumes sold under fixed price contracts and volumes sold under market sensitive contracts. At December 31, 1998, approximately 46% of the gas marketed by the Company was at fixed prices and 54% was at market sensitive prices. This contract strategy is intended to reduce price volatility and place a partial floor under the price received while still maintaining the potential for gains from upward movement in market sensitive prices.
The Company has a policy which governs its ability to trade in the financial futures markets. The Company may, from time to time, partially hedge its physical gas sales prices by selling futures contracts on the New York Mercantile Exchange ("NYMEX") or by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. At December 31, 1998, the
Company had 620 open futures contracts covering 1999, at an average price of $2.44 per Mcf. To offset these hedges, the Company has contracted for the physical delivery of gas into various pipelines in its producing areas at a NYMEX price plus a fixed basis. Additionally, the Company has entered into a "swaption" whereby the counterparty has the option to extend a current swap of 20 contracts per month through calendar year 2000 by giving notice on September 30, 1999.
The following table shows the type of buyer for gas marketed by the Company at December 31, 1998:
Gas Gathering. The Company operates approximately 2,600 miles of natural gas gathering lines in Ohio, West Virginia, Pennsylvania, New York, Michigan and Kentucky which are tied directly to various interstate natural gas transmission systems. The interconnections with these interstate pipelines afford the Company potential marketing access to numerous major gas markets. The Company's gas gathering revenues totaled $6.9 million in 1998. Direct costs associated with gas gathering in 1998 totaled approximately $1.7 million.
ACQUISITION OF PRODUCING PROPERTIES
The Company employs a disciplined approach to acquisition analysis that requires input and approval from all key areas of the Company. These areas include field operations, exploration and production, finance, legal, gas marketing, land management and environmental compliance. Although the Company often reviews in excess of 50 acquisition opportunities per year, this disciplined approach can result in uneven annual spending on acquisitions. The following table sets forth information pertaining to acquisitions completed during the period 1992 through 1998.
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(1) Represents the portion of the purchase price allocated to proved developed reserves.
(2) Mbbl - thousand barrels Mmcf - million cubic feet Mmcfe - million cubic feet equivalent
During 1998, the Company acquired for approximately $7.6 million, working interests in 898 oil and gas wells in Ohio, Michigan, West Virginia and New York. Estimated proved developed reserves associated with the wells totaled 8.6 Bcf of natural gas and 34,000 Bbls of oil, net to the Company's interest.
OIL AND GAS OPERATIONS AND PRODUCTION
Operations. The Company serves as the operator of substantially all of the wells in which it holds working interests. The Company seeks to maximize the value of its properties through operating efficiencies associated with economies of scale and through operating cost reductions, advanced production technology, mechanical improvements and/or the use of enhanced and secondary recovery techniques.
Through its production field offices in Ohio, West Virginia, Pennsylvania, New York, Michigan and Kentucky, the Company continuously reviews its properties, especially recently acquired properties, to determine what action can be taken to reduce operating costs and/or improve production. The Company has successfully reduced field level costs through improved operating practices such as computerized production scheduling and the use of hand-held computers to gather field data. On
acquired properties, further efficiencies may be realized through improvements in production scheduling and reductions in oilfield labor. Actions that may be taken to improve production include modifying surface facilities and redesigning downhole equipment.
The Company may also implement enhanced and secondary recovery techniques. Secondary recovery methods typically involve all methods of oil extraction in which extrinsic energy sources are applied to extract additional reserves. The principal secondary recovery technique used by the Company is waterflooding, which the Company has used successfully in Ohio and Pennsylvania.
Production. The following table sets forth certain information regarding oil and gas production from the Company's properties:
EXPLORATION AND DEVELOPMENT
The Company's exploration and development activities include development drilling in the highly developed or blanket formations and development and exploratory drilling in the less developed formations of the Appalachian, Michigan and Illinois Basins. The Company's strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. The Company has an extensive inventory of acreage on which to conduct its exploration and development activities.
In 1998, the Company drilled 192 gross (169.5 net) wells to highly developed or shallow blanket formations in its six state operating area at a direct cost of approximately $28.4 million for the net wells. The Company also drilled 57 gross (29.7 net) wells to less developed and deeper formations in 1998 at a direct cost of approximately $7.6 million for the net wells. The result of this drilling activity is shown in the table on page 15.
The Company believes that its diversified portfolio approach to its drilling activities results in more consistent and predictable economic results than might be experienced with a less diversified or higher risk drilling program profile.
Highly Developed Formations. In general, the highly developed or blanket formations found in the Appalachian, Michigan and Illinois Basins are widespread in extent and hydrocarbon accumulations are not dependent upon local stratigraphic or structural trapping. Drilling success rates exceed 90%. The principal risk of such wells is uneconomic recoverable reserves.
The highly developed formations in the Appalachian Basin are relatively tight reservoirs that produce 20% to 30% of their recoverable reserves in the first year and 40% to 50% of their total recoverable reserves in the first three years, with steady declines in subsequent years. Average well lives range from 15 years to 25 years or more.
The Antrim Shale formation, the principal shallow blanket formation in the Michigan Basin, is characterized by high formation water production in the early years of a well's productive life, with water production decreasing over time. Antrim Shale wells typically produce at rates of 100 Mcf to 125 Mcf per day for several years, with modest declines thereafter. Gas production often increases in the early years as the producing formation becomes less water saturated. Average well lives are 20 years or more.
Producing natural gas in the form of methane from coalbed formations is becoming a more common practice, particularly in Pennsylvania. In 1998, the Company completed its second project area near Connellsville, PA, with the completion of 12 coalbed methane wells. This brings the Company's total wells producing from this type of reservoir to 62. With over 60,000 acres under lease in the coal seam fairway, the Company believes that substantial additional opportunities exist for coalbed drilling.
In the Illinois Basin, the highly developed or shallow blanket formations include the New Albany Shale formation as well as the Mississippian Sandstones. Production characteristics of the New Albany Shale are very similar to the Devonian Shale from which the Company produces in West Virginia.
Certain typical characteristics of the highly developed or blanket formations drilled by the Company in 1998 are described below:
Less Developed Formations. The Appalachian Basin has productive and potentially productive sedimentary formations to depths of 30,000 feet or more, but the combination of long-lived production and high drilling success rates in the shallow formations has curbed the development of the deeper formations in the basin. The Company believes it possesses the technological expertise and the acreage position needed to explore the deeper formations in a cost effective manner.
The less developed formations in the Appalachian Basin include the Knox sequence of sandstones and dolomites which includes the Rose Run, Beekmantown and Trempealeau productive zones, at depths ranging from 2,500 feet to 8,000 feet. The geographical boundaries of the Knox sequence, which lies approximately 2,000 feet below the highly developed Clinton Sandstone, are generally well defined in Ohio with less definition in New York and Pennsylvania. Nevertheless, the Knox group has been only lightly explored, with fewer than 2,000 wells drilled to this sequence of formations during the past 10 years.
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:
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(1) Completed as producing wells in the Knox formations.
The Company's historical experience is that the average Knox well produces 20% to 25% of its recoverable reserves in the first year of production and approximately 50% of its recoverable reserves in the first three years with a steady decline thereafter. Wells in the Knox formations have an expected productive life ranging from 10 to 20 years.
As shown in the following table, the Company's production from Knox formation wells has increased steadily as additional wells have been drilled.
Productive Knox wells represented approximately 1.2% of the Company's total productive wells at December 31, 1998. Production from Knox wells in 1998, however, equaled 15% of the Company's total production on an Mcfe basis.
The Company is well positioned to exploit the undeveloped potential of the Knox formations in the future. At December 31, 1998, it held leases on approximately 560,567 net acres overlying potential Knox drilling locations.
In addition, the Company has also tested the Niagaran Carbonate, Trenton/Black River Carbonates, Onondaga Limestone, Oriskany Sandstone and Newburg Sandstone formations. Certain typical characteristics of the less developed or deeper formations drilled by the Company in 1998 are described below:
Drilling Results. The following table sets forth drilling results with respect to wells drilled during the past five years:
(1) Consists of wells drilled to the Berea and Clinton Sandstone formations in Ohio, the Berea Sandstone, Devonian Brown Shale, Ravencliff Sandstone and Big Lime Limestone formations in West Virginia, the Clarendon, Upper Devonian, Coalbed Methane and Medina formations in Pennsylvania, the Medina Sandstone formation in New York, the New Albany Shale formation in Kentucky and the Antrim Shale formation in Michigan.
(2) Consists of wells drilled to the Trenton Limestone and Knox formations in Ohio, the Niagaran and Dundee Carbonates in Michigan, the Oriskany Sandstone and Onondaga Limestone formations in Pennsylvania and the Oriskany Sandstone, Onondaga Limestone, Trenton/Black River Carbonates and Knox formations in New York.
(3) One additional well which was dry in the Knox formations was subsequently completed in the shallower Clinton formation.
(4) Two additional wells which were dry in the Knox formations were subsequently completed in the shallower Clinton formation. One additional well which was dry in the Oriskany formation was subsequently completed in the shallower Berea/Shale formations.
(5) Three additional wells which were dry in the Knox formations were subsequently completed in shallower formations.
(6) Two additional wells which were dry in the Knox formations were subsequently completed in the shallower Clinton formation.
OILFIELD SALES AND SERVICE
The Company has provided its own oilfield services for more than 30 years in order to assure quality control and operational and administrative support to its exploration and production operations. In 1992, Arrow Oilfield Service Company ("Arrow"), a separate service division, was organized. Arrow provides the Company and third party customers with necessary oilfield services such as well workovers, well completions, brine hauling and disposal and oil trucking. Arrow is currently the largest oilfield service company in Ohio. In 1998, approximately 55% of Arrow's revenues were generated by sales to third parties.
Target Oilfield Pipe & Supply Company ("TOPS"), a wholly-owned subsidiary of the Company, operates retail sales outlets in the Appalachian and Michigan Basins from which it sells a broad range of equipment, including pipe, tanks, fittings, valves and pumping units. The Company originally entered the
oilfield supply business to ensure the quality and availability of supplies for its own operations. In 1998, approximately 72% of TOPS' revenues were generated by sales to third parties.
EMPLOYEES
As of February 26, 1999, the Company had 574 full-time employees, including 16 gas marketing employees, 318 oil and gas production employees, 19 petroleum engineers, 9 geologists, 3 geophysicists, 169 oilfield sales and service employees and 40 general administrative employees.
COMPETITION AND CUSTOMERS
The oil and gas industry is highly competitive. Competition is particularly intense with respect to the acquisition of producing properties and the sale of oil and gas production. There is competition among oil and gas producers as well as with other industries in supplying energy and fuel to end users.
The competitors of the Company in oil and gas exploration, development, production and marketing include major integrated oil and gas companies as well as numerous independent oil and gas companies, individual proprietors, natural gas pipelines and their affiliates and natural gas marketers and brokers. Many of these competitors possess and employ financial and personnel resources substantially in excess of those available to the Company. Such competitors may be able to pay more for desirable prospects or producing properties and to evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources of the Company will permit. The ability of the Company to add to its reserves in the future will be dependent on its ability to exploit its current developed and undeveloped lease holdings and its ability to select and acquire suitable producing properties and prospects for future exploration and development.
No customer exceeded 10% of consolidated revenues during the year ended December 31, 1998, the six months ended June 30, 1997 and December 31, 1997 and the year ended December 31, 1996.
REGULATION
Regulation of Production. In all states in which the Company is engaged in oil and gas exploration and production, its activities are subject to regulation. Such regulations may extend to requiring drilling permits, spacing of wells, the prevention of waste and pollution, the conservation of natural gas and oil, and other matters. Such regulations may impose restrictions on the production of natural gas and oil by reducing the rate of flow from individual wells below their actual capacity to produce which could adversely affect the amount or timing of the Company's revenues from such wells. Moreover, future changes in local, state or federal laws and regulations could adversely affect the operations of the Company.
Environmental Regulation. The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from the Company's operations. Management believes the Company is in substantial compliance with current applicable environmental laws and regulations and
that continued compliance with existing requirements will not have a material adverse impact on the Company.
Regulation of Sales and Transportation. The Federal Energy Regulatory Commission regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). In the past, the federal government has regulated the prices at which oil and gas could be sold. Currently, sales by producers of natural gas and all sales of crude oil and condensate in natural gas liquids can be made at uncontrolled market prices.
ITEM 2.
ITEM 2. PROPERTIES
OIL AND GAS RESERVES
The following table sets forth the Company's proved oil and gas reserves as of December 31, 1996, 1997 and 1998 determined in accordance with the rules and regulations of the Securities and Exchange Commission. Proved reserves are the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
See Note 17 to the consolidated financial statements for more detailed information regarding the Company's oil and gas reserves. The following table sets forth the estimated future net cash flows from the proved reserves of the Company and the present value of such future net cash flows as of December 31, 1998 determined in accordance with the rules and regulations of the Securities and Exchange Commission.
Estimated future net cash flows represent estimated future gross revenues from the production and sale of proved reserves, net of estimated production costs (including production taxes, ad valorem taxes, operating costs, development costs and additional capital investment). Estimated future net cash flows were calculated on the basis of prices and costs estimated to be in effect at December 31, 1998 without escalation, except where changes in prices were fixed and readily determinable under existing contracts. The following table sets forth the weighted average year-end prices for oil and gas:
IMPAIRMENT OF OIL AND GAS PROPERTIES AND OTHER ASSETS
As described in Note 2 to the consolidated financial statements, the Company evaluates long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. As demonstrated by the chart in the preceding section, the decline in oil and gas prices since 1996 has been significant and has negatively impacted the quantity and value of the Company's oil and gas reserves. Given this impairment indicator, the Company computed the expected future undiscounted cash flows, employing methods consistent with those utilized to determine the estimated future net cash flows from proved reserves discussed above. For those assets in which the sum of the expected future undiscounted cash flows was less than the carrying amount, an impairment loss was recognized for the difference between the fair value and carrying value of the asset, with fair value determined based on discounted cash flow analysis, sale of similar properties or recent offers for specific assets. As a result of this evaluation, the Company recorded total impairment charges of $160.7 million (pre-tax) in 1998, consisting of $148.0 million relating to producing properties and related assets, $5.8 million for unproved properties and $6.9 million relating to other long-lived assets. The magnitude of the impairment charge was impacted by the Acquisition in 1997, in which the allocation of the purchase price at fair value resulted in a significant increase in the book value of the Company's assets.
PRODUCING WELL DATA
The following table summarizes by state the Company's productive wells at December 31, 1998:
ACREAGE DATA
The following table summarizes by state the Company's gross and net developed and undeveloped leasehold acreage at December 31, 1998:
Item 3.
Item 3. LEGAL PROCEEDINGS
The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on the Company's financial position or the results of operations.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
There is no established public trading market for the Company's equity securities.
The number of record holders of the Company's equity securities at February 28, 1999 was as follows:
DIVIDENDS
No dividends have been paid on the Company's Common Stock.
Item 6.
Item 6. SELECTED FINANCIAL DATA
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
As disclosed in the accompanying notes to consolidated financial statements, on March 27, 1997 the Company entered into a merger agreement with TPG which resulted in all of the Company's common stock being acquired by TPG and certain other investors on June 27, 1997 in a transaction accounted for as a purchase. For financial reporting purposes, the Acquisition is considered effective June 30, 1997 and the operations of the Company prior to July 1, 1997 are classified as predecessor company operations. The consolidated balance sheets at December 31, 1997 and 1998 include the application of purchase accounting to measure the Company's assets and liabilities at fair value. Debt incurred to finance the Acquisition and related transaction costs are reflected in the December 31, 1997 and 1998 financial statements. A vertical black line is shown in the financial statements to separate the results of operations of the predecessor and successor companies.
The allocation of the purchase price at fair value resulted in a significant increase in the book value of the Company's assets. The increase in the book value of assets resulted in materially higher charges for depreciation, depletion and amortization in the second half of 1997 and all of 1998.
As described in Note 2 to the consolidated financial statements, the Company evaluates long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Due to sustained significantly lower oil and gas prices, the quantity and value of the Company's oil and gas reserves have been negatively impacted. Given this impairment indicator, the Company computed the expected future undiscounted cash flows, employing methods consistent with those utilized to determine the estimated future net cash flows from proved reserves discussed in Note 17 to the consolidated financial statements. For those assets in which the sum of the expected future undiscounted cash flows was less than the carrying amount, an impairment loss was recognized for the difference between the fair value and carrying value of the asset, with fair value determined based on discounted cash flow analysis, sale of similar properties or recent offers for specific assets. As a result of this evaluation, the Company recorded total impairment charges of $160.7 million (pre-tax) in 1998, consisting of $148.0 million relating to producing properties and related assets, $5.8 million for unproved properties and $6.9 million relating to other long-lived assets. The magnitude of the impairment charge was impacted by the Acquisition in 1997, in which the allocation of the purchase price at fair value resulted in a significant increase in the book value of the Company's assets.
The Company incurred transaction costs associated with the Acquisition of $16.8 million. These costs were expensed in the second quarter of 1997. As a result of the Acquisition, the Company is highly leveraged, resulting in materially higher interest charges in the second half of 1997 and all of 1998. These higher interest charges are expected to continue in subsequent accounting periods.
The Company's principal business is natural gas marketing and gathering and the production, acquisition and development of, and exploration for, oil and gas reserves, principally in Ohio, West Virginia, Pennsylvania, Michigan, New York and Kentucky.
The Company's gas marketing and gathering operations consist of purchasing gas at the wellhead and from interstate pipelines and selling gas to industrial and commercial customers and local gas distribution companies.
The Company utilizes the "successful efforts" method of accounting for its oil and gas properties. Under this method, property acquisition and development costs and productive exploration costs are capitalized while non-productive exploration costs, which include dry holes, expired leases and delay rentals, are expensed as incurred. Capitalized costs related to proved properties are depleted using the unit-of-production method. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.
The Company provides oilfield sales and services to its own operations and to third parties. Oilfield sales and service provided to the Company's own operations are provided at cost and all intercompany revenues and expenses are eliminated in consolidation.
RESULTS OF OPERATIONS
As a result of the Acquisition, the results of operations for the periods subsequent to June 30, 1997 are not necessarily comparable to those prior to July 1, 1997. The following table combines the six-month predecessor company period ended June 30, 1997 with the six-month successor company period ended December 31, 1997 for purposes of the discussion of year-end results (dollars are stated in thousands and as a percentage of revenue).
1998 COMPARED TO 1997
Operating income decreased $183.4 million from $9.5 million in 1997 to an operating loss of $173.9 million in 1998. The decrease in operating income was due primarily to the $160.7 million write-down of certain permanently impaired assets and a $21.4 million increase in depreciation, depletion and amortization expense from significant increases in the book value of property, equipment and other assets as a result of the purchase accounting associated with the Acquisition discussed above.
Loss from continuing operations increased $109.4 million from a loss of $21.2 million in 1997 to a loss of $130.6 million in 1998. This increase was the result of the $160.7 million asset impairment, the $21.4 million increase in depreciation, depletion and amortization expense and an increase of $13.8 million in interest expense offset by the $16.8 million of transaction-related expenses in 1997 and an increase in the income tax benefit of $71.1 million. This increase in the income tax benefit was primarily due to the decrease in income from continuing operations before income taxes combined with a change in
the effective tax rate due to the nondeductibility of certain transaction- related expenses and a decrease in the utilization of nonconventional fuel source tax credits in 1998.
Earnings before interest, income taxes, depreciation, depletion and amortization and exploration expense ("EBITDAX") was $65.3 million in 1998 compared to $66.9 million in 1997.
Total revenues decreased $8.7 million (5%) in 1998 compared to 1997. Gross operating margins decreased $3.0 million (4%) in 1998 compared to 1997.
Oil volumes increased 15,000 Bbls (2%) from 753,000 Bbls in 1997 to 768,000 Bbls in 1998 resulting in an increase in oil sales of approximately $272,000. Gas volumes increased 2.9 Bcf (11%) from 27.2 Bcf in 1997 to 30.1 Bcf in 1998 resulting in an increase in gas sales of approximately $7.8 million. These volume increases were primarily due to production from properties acquired and wells drilled in 1997 and 1998.
The average price paid for the Company's oil decreased from $18.10 per barrel in 1997 to $12.61 per barrel in 1998 which decreased oil sales by approximately $4.2 million. The average price paid for the Company's natural gas decreased $.08 per Mcf to $2.57 per Mcf in 1998 compared to 1997 which decreased gas sales in 1998 by approximately $2.4 million.
Production expense increased $2.2 million (10%) from $21.5 million in 1997 to $23.7 million in 1998. The average production cost of $.68 per Mcfe in 1998 was consistent when compared to the same period in 1997. Production taxes decreased $186,000 from $3.2 million in 1997 to $3.0 million in 1998. Average production taxes decreased from $.10 per Mcfe in 1997 to $.09 per Mcfe in 1998.
Depreciation, depletion and amortization increased by $21.4 million (46%) from $47.1 million in 1997 to $68.5 million in 1998. Depletion expense increased $19.2 million (50%) from $38.5 million in 1997 to $57.7 million in 1998. Depletion per Mcfe increased from $1.21 per Mcfe in 1997 to $1.66 per Mcfe in 1998. These increases were primarily the result of significant increases in the book value of property, equipment and other assets as a result of the purchase accounting associated with the Acquisition discussed above.
Interest expense increased $13.8 million (72%) from $19.1 million in 1997 to $32.9 million in 1998. This increase was due to substantial additional debt incurred primarily to finance the Acquisition.
In the exploration and production segment, 1998 revenues remained consistent with 1997 revenues. Loss from continuing operations before income taxes increased $168.0 million from $6.6 million in 1997 to $174.6 million in 1998. This increase was due primarily to the $144.7 million write-down of certain permanently impaired exploration and production segment assets, a $12.4 million increase in interest expense associated with the additional debt incurred to finance the Acquisition and the properties acquired and wells drilled in 1998 and 1997 and a $11.9 million increase in depreciation, depletion and amortization expense from significant increases in the book value of the segment's property, equipment and other assets as a result of the purchase accounting associated with the Acquisition and the properties acquired and wells drilled in 1998 and 1997.
Gas marketing and gathering segment revenues decreased $1.8 million from $41.4 million in 1997 to $39.6 million in 1998. Income from continuing operations before income taxes decreased $18.6 million from $2.9 million in 1997 to a loss of $15.7 million in 1998. This decrease was due
primarily to the $9.1 million write-down of certain permanently impaired gas marketing and gathering segment assets and a $8.7 million increase in depreciation, depletion and amortization expense from significant increases in the book value of the segment's property, equipment and other assets as a result of the purchase accounting associated with the Acquisition.
Oilfield sales and service segment revenues decreased $6.6 million from $30.4 million in 1997 to $23.8 million in 1998. This decrease was primarily the result of work deferred by the Company and third parties due to low oil prices. Income from continuing operations before income taxes decreased $9.9 million from $681,000 in 1997 to a loss of $9.2 million in 1998. This decrease was due primarily to the $6.9 million write-down of certain permanently impaired oilfield sales and service segment assets and a $2.3 million decrease in the oilfield sales and service operating margin.
1997 COMPARED TO 1996
Operating income decreased $19.6 million (67%) from $29.1 million in 1996 to $9.5 million in 1997. The decrease in operating income was due primarily to an $17.3 million increase in depreciation, depletion and amortization expense from significant increases in the book value of property, equipment and other assets as a result of the purchase accounting associated with the Acquisition discussed above.
Income from continuing operations decreased $36.4 million from income of $15.2 million in 1996 to a loss of $21.2 million in 1997. This decrease was the result of $16.8 million of transaction-related expenses, the $17.3 million increase in depreciation, depletion and amortization expense and an increase of $11.7 million in interest expense offset by a decrease in the provision for income taxes of $11.7 million. This decrease in the provision for income taxes was primarily due to the decrease in income from continuing operations before income taxes combined with a change in the effective tax rate due to the nondeductibility of certain transaction-related expenses and a decrease in the utilization of nonconventional fuel source tax credits in 1997.
Earnings before interest, income taxes, depreciation, depletion and amortization and exploration expense was $66.9 million in 1997 compared to $65.0 million in 1996.
Total revenues increased $10.3 million (7%) in 1997 compared to the same period of 1996. Gross operating margins in 1997 were consistent when compared to the same period in 1996.
Oil volumes increased 34,000 Bbls (5%) from 719,000 Bbls in 1996 to 753,000 Bbls in 1997 resulting in an increase in oil sales of approximately $700,000. Gas volumes increased 1.8 Bcf (7%) from 25.4 Bcf in 1996 to 27.2 Bcf in 1997 resulting in an increase in gas sales of approximately $4.6 million. These volume increases were primarily due to production from properties acquired and wells drilled in 1996 and 1997.
The average price paid for the Company's oil decreased from $20.24 per barrel in 1996 to $18.10 per barrel in 1997 which decreased oil sales by approximately $1.6 million. The average price paid for the Company's natural gas increased $.09 per Mcf to $2.65 per Mcf in 1997 compared to 1996 which increased gas sales in 1997 by approximately $2.4 million.
Production expense increased $3.4 million (19%) from $18.1 million in 1996 to $21.5 million in 1997. The average production cost increased from $.61 per Mcfe in 1996 to $.68 per Mcfe in 1997. These increases were due to an anticipated steep decline in production volumes from certain high volume wells with low production costs coupled with a reduction in operating fees received from third parties
primarily due to the purchase of certain third party working interests by the Company. Such fees are recorded as a reduction of production expense. Production taxes were consistent at $3.2 million in 1997 and 1996.
Depreciation, depletion and amortization increased by $17.3 million (58%) from $29.8 million in 1996 to $47.1 million in 1997. Depletion expense increased $15.5 million (68%) from $23.0 million in 1996 to $38.5 million in 1997. Depletion per Mcfe increased from $.77 per Mcfe in 1996 to $1.21 per Mcfe in 1997. These increases were primarily the result of significant increases in the book value of property, equipment and other assets as a result of the purchase accounting associated with the Acquisition discussed above.
Interest expense increased $11.7 million (159%) from $7.4 million in 1996 to $19.1 million in 1997. This increase was due to substantial additional debt incurred primarily to finance the Acquisition.
Exploration and production segment revenues increased $5.7 million from $85.6 million in 1996 to $91.3 million in 1997 due to the changes in oil and gas volumes and prices discussed above. Income from continuing operations before income taxes decreased $29.2 million from $22.6 million in 1996 to a loss of $6.6 million in 1997. This decrease was due primarily to a $10.9 million increase in interest expense associated with the additional debt incurred to finance the properties acquired and wells drilled in 1997 and a $16.5 million increase in depreciation, depletion and amortization expense from significant increases in the book value of the segment's property, equipment and other assets as a result of the purchase accounting associated with the Acquisition.
In the gas marketing and gathering segment, 1997 revenues remained consistent with 1996 revenues. Income from continuing operations before income taxes decreased $596,000 from $3.5 million in 1996 to $2.9 million in 1997.
Oilfield sales and service segment revenues increased $4.9 million from $25.5 million in 1996 to $30.4 million in 1997. Income from continuing operations before income taxes decreased $687,000 from $1.4 million in 1996 to $681,000 in 1997.
LIQUIDITY AND CAPITAL RESOURCES
The Company's liquidity and capital resources are closely related to and dependent on the current prices paid for its oil and gas.
The Company's current ratio at December 31, 1998 was 0.90 to 1.00. During 1998, working capital decreased $26.1 million from $19.8 million to a deficit of $6.3 million. The decrease was primarily due to an increase in current portion of long-term debt of $28.1 million offset by an increase in cash of $4.1 million. The Company's operating activities provided cash flows of $25.3 million in 1998.
On June 27, 1997, the Company entered into a senior revolving credit agreement with several lenders. These lenders have committed, subject to compliance with the borrowing base, to provide the Company with revolving credit loans of up to $200 million, of which $25 million will be available for the issuance of letters of credit. The borrowing base is determined based on the Company's oil and gas reserves and other assets and is subject to annual or semiannual adjustment. The Company's borrowing base at December 31, 1998, was $170 million. On January 15, 1999, the Company's borrowing base was reduced to $126 million. The Company had $154 million outstanding under this agreement at December 31, 1998, which resulted in the Company having a borrowing base deficiency of $28 million. The
Company has agreed with the lenders to reduce this deficiency by $14 million on March 22, 1999 and by the remaining $14 million on May 10, 1999.
On March 22, 1999, the Company made a $14 million payment to reduce the outstanding amount under the credit agreement to $140 million. The funds for the payment were provided by internally generated cash flow and a term loan provided by Chase Manhattan Bank. This term loan provided borrowings of $9 million and is due on September 22, 1999. Interest is payable monthly at LIBOR plus 1.5%. The Company is in the process of renegotiating its revolving credit facility with its lenders and expects to have a new facility in place prior to May 10, 1999, when the second payment of $14 million is due. Should the Company not be successful in renegotiating an acceptable facility, the Company expects to be able to meet its 1999 debt service requirements through internally generated cash flow, the sale of non-strategic assets and/or the use of instruments in financial futures markets.
At December 31, 1998, the outstanding balance under the credit agreement was $154 million. The credit agreement will mature on June 27, 2002. Outstanding balances under the agreement incur interest at the Company's choice of several indexed rates, the most favorable being 6.566% at December 31, 1998.
The credit agreement contains a number of covenants that, among other things, restricts the ability of the Company and its subsidiaries to dispose of assets, incur additional indebtedness, prepay other indebtedness or amend certain debt instruments, pay dividends, create liens on assets, enter into sale and leaseback transactions, make investments, loans or advances, make acquisitions, engage in mergers or consolidations, change the business conducted by the Company or its subsidiaries, make capital expenditures or engage in certain transactions with affiliates and otherwise restrict certain corporate activities. In addition, under the credit agreement, the Company is required to maintain specified financial ratios and tests, including minimum interest coverage ratios and maximum leverage ratios. The agreement requires a minimum working capital ratio of 1.00 to 1.00. As of December 31, 1998, the Company's working capital ratio was .90 to 1.00. The Company and its lenders have agreed to exclude the $28 million required reduction in outstanding borrowings from the covenant requiring a specific working capital ratio. The ratio after excluding the $28 million results in a working capital ratio of 1.58 to 1.00.
The Company issued $225 million of 9.875% Senior Subordinated Notes on June 27, 1997. The notes mature June 15, 2007. Interest is payable semiannually on June 15 and December 15 of each year, commencing December 15, 1997.
The notes are general unsecured obligations of the Company and are subordinated in right of payment to senior debt. Except as otherwise described below, the notes are not redeemable prior to June 15, 2002. Thereafter, the notes are subject to redemption at the option of the Company at specific redemption prices. Prior to June 15, 2000, the Company may, at its option, on any one or more occasions, redeem up to 40% of the original aggregate principal amount of the notes at a redemption price equal to 109.875% of the principal amount, plus accrued and unpaid interest, if any on the redemption date, with all or a portion of net proceeds of public sales of common stock of the Company; provided that at least 60% of the original aggregate principal amount of the notes remains outstanding immediately after the occurrence of such redemption; and provided, further, that such redemption shall occur within 60 days of the date of the closing of the related sale of common stock of the Company. Prior to June 15, 2002, the notes may be redeemed as a whole at the option of the Company upon the occurrence of a change in control.
The indenture contains certain covenants that limit the ability of the Company and its subsidiaries to incur additional indebtedness and issue stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens, and engage in mergers and consolidations.
On March 31, 1997, the Company redeemed all of the outstanding Class II Series A preferred stock for $2.4 million in cash.
On April 3, 1997, the Company gave notice of redemption of all of the outstanding 9.25% convertible subordinated debentures for 104% of face value. Redemption of these debentures occurred June 10, 1997 when holders of the debentures elected to convert them into 275,425 shares of predecessor common stock.
On June 25, 1997, the Company redeemed all $35 million of its 7% fixed-rate senior notes.
On June 27, 1997, the Company repaid all outstanding amounts due under the then existing revolving bank facility in the amount of $94 million.
The Company currently expects to spend approximately $4 million during 1999 on its drilling activities and other capital expenditures. The Company intends to finance such activities, as well as its acquisition program, through its available cash flow, available revolving credit line, additional borrowings or additional equity. The level of the Company's cash flow in the future will depend on a number of factors including the demand and price levels for oil and gas, its ability to acquire additional producing properties and the scope and success of its drilling activities.
From time to time the Company may enter into interest rate swaps to hedge the interest rate exposure associated with the credit facility, whereby a portion of the Company's floating rate exposure would be exchanged for a fixed interest rate. During October 1997, the Company entered into two interest rate swap arrangements covering $90 million of debt. The Company swapped $40 million of floating three-month LIBOR +1.5% for a fixed rate of 7.485% for three years, extendible at the institution's option for an additional two years. The Company also swapped $50 million of floating three-month LIBOR +1.5% for a fixed rate of 7.649% for five years. During June 1998, the Company entered into a third interest rate swap covering $50 million of debt. The Company swapped $50 million of floating rate three-month LIBOR + 1.5% for a fixed rate of 7.2825% for three years.
INFLATION AND CHANGES IN PRICES
During 1996, the price paid for the Company's crude oil increased from a low of $16.50 per barrel at year-end 1995 to a high of $22.50 per barrel at year-end 1996, with an average price of $20.24 per barrel. During 1997, the price paid for the Company's crude oil increased from $22.50 per barrel at year-end 1996 to a high of $23.50 per barrel in early 1997, then decreased to a low of $14.25 at year-end 1997, with an average price of $18.10 per barrel. During 1998, the price paid for the Company's crude oil increased to a high of $14.50 per barrel in January, then decreased to a low of $8.50 per barrel in December and increased to $9.25 per barrel at year-end 1998, with an average price of $12.61 per barrel. The average price of the Company's natural gas increased from $2.56 per Mcf in 1996 to $2.65 per Mcf in 1997, then decreased to $2.57 per Mcf in 1998.
The price of oil and gas has a significant impact on the Company's results of operations. Oil and gas prices fluctuate based on market conditions and, accordingly, cannot be predicted. As a result of
increased competition among drilling contractors and suppliers and continuing low levels of drilling activity in the Company's operating area, costs to drill, complete, and service wells have remained relatively constant in recent years.
Historically, a large portion of the Company's natural gas sales has been under long-term fixed price contracts. As a result of recent acquisitions, certain natural gas sales are currently based on indexed prices. Many of these contracts contain "trigger" clauses which allow the Company to fix the price at which deliveries in future months will be sold at the NYMEX price for one or more future months. The Company may also, from time to time, enter into hedging transactions with financial institutions to reduce its exposure to variable commodity pricing.
READINESS FOR YEAR 2000
Like most companies, the Company is faced with the Year 2000 ("Y2K") issue. The Y2K problem arose because many existing computer programs use only the last two digits to refer to a year. This does not allow programs to properly recognize a year that begins with "20" instead of "19". Any computer programs that have date-sensitive software may recognize a date using "00" as the year 1900 instead of the year 2000. This could result in system failures and miscalculations causing disruptions of operations or financial processes, such as equipment failures or a temporary inability to process transactions or send invoices.
The Company has taken actions to understand the nature and extent of the work required to make its systems and operations Y2K compliant. A project team is responsible for coordinating the assessment, remediation, testing and implementation of the necessary modifications to its key applications (which consist of third party software, hardware and embedded chip systems, as well as internally developed computer applications). To date, the team has worked to identify potential risks to the Company and has replaced the Company's major legacy systems. An inventory of hardware and software and all peripheral systems is complete and prioritized for upgrade or replacement. A testing plan has been developed, and the Company expects to complete testing of its mission-critical systems by the end of June, 1999.
The Company intends to monitor and compare the estimated costs associated with its actions to actual costs. Estimated additional costs for making the necessary changes (primarily installation of current releases of operating systems and application software) to such systems, including implementation and testing efforts, are expected to range from $250,000 to $350,000 not including internal costs. This estimate is based on various factors including availability of internal and external resources and complexity of the software applications. Such estimate does not include costs of new systems for which the principal justification is improved business functionality, rather than Y2K compliance. While the Company has enlisted the guidance of various industry experts in the project planning process, it does not rely on the assistance of outside consultants to direct the project. Employees assigned to the project have integrated their responsibilities into normal operations. The Company does not separately track the internal costs incurred in connection with the project. Such internal costs consist primarily of payroll costs for the employees assigned to the project.
The Company's goal is to ensure that all of its critical systems and processes remain functional. Since certain systems may be interrelated with systems outside the Company's control, there can be no assurance that all implementations will be successful. The Company has completed identification of its critical relationships with outside vendors, customers and business partners and has requested confirmation of Y2K compliance from such third parties. Among these, special attention is being given to obtaining evidence of Y2K compliance from third-party transporters of natural gas, deemed as a
critical element to the Company's uninterrupted business operations. The Company is preparing contingency plans to minimize any disruptions resulting from a vendor, supplier or customer not being Y2K compliant. Failure by the Company and/or its vendors, suppliers, and customers to complete Y2K compliance could have a material adverse effect on the Company's operations. Recognizing this risk, formal contingency plans are being developed by the Company and are expected to be finalized by the end of the second quarter of 1999.
FORWARD-LOOKING INFORMATION
The forward-looking statements regarding future operating and financial performance contained in this report involve risks and uncertainties that include, but are not limited to, the Company's future gas marketing activity, production and costs of operation, the market demand for, and prices of, oil and natural gas, results of the Company's future drilling, the uncertainties of reserve estimates, environmental risks, availability of financing, the Company's readiness for Y2K as well as potential adverse consequences related to third party Y2K compliance and other factors detailed in the Company's filings with the Securities and Exchange Commission. Actual results may differ materially from forward-looking statements made in this report.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company is exposed to interest rate and commodity price risks.
The interest rate risk relates to existing debt under the Company's revolving credit facility as well as any new debt financing needed to fund capital requirements. The Company manages its interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of the Company's floating rate exposure would be exchanged for a fixed interest rate. A portion of the Company's long-term debt consists of senior subordinated notes where the interest component is fixed. The Company had derivative financial instruments for managing interest rate risks in place as of December 31, 1998 and 1997. The principal amount of the hedges totaled $140 million and $90 million at December 31, 1998 and 1997, respectively. If market interest rates for short-term borrowings increased 1%, the increase in the Company's interest expense, after considering the effects of its interest rate swap and cap agreements, would be immaterial. This sensitivity analysis is based on the Company's financial structure at December 31, 1998.
The commodity price risk relates to crude oil and natural gas produced, held in storage and marketed by the Company. The Company's financial results can be significantly impacted as commodity prices fluctuate widely in response to changing market forces. From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to commodity price volatility. The Company employs a policy of hedging gas production sold under NYMEX based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. If NYMEX gas prices increased $.25 per Mcf, the Company's gas sales would increase $5 million, after considering the effects of the hedging contracts in place at December 31, 1998. This sensitivity analysis is based on the Company's 1998 gas sales volumes.
The information included in this Item is considered to constitute "forward looking statements" for purposes of the statutory safe harbor provided in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Forward-Looking Information" in Item 7 of this Report.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Index to Consolidated Financial Statements and Schedules on page 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.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Executive officers and directors of the Company as of February 28, 1999 were as follows:
All executive officers of the Company serve at the pleasure of its Board of Directors. None of the executive officers of the Company is related to any other executive officer or director, except that Henry S. Belden IV and Dennis D. Belden are brothers. The Board of Directors consists of nine
members each of whom is elected annually to serve one year terms. The business experience of each executive officer and director is summarized below.
RONALD L. CLEMENTS has been Chief Executive Officer and a Director of the Company since the Acquisition on June 27, 1997. Previously he served as Senior Vice President of Exploration and Production and managed the Company's Exploration and Production Division from 1993 to 1997. He joined Belden & Blake in 1990 and served as Vice President of Producing Operations. He has more than 30 years of petroleum engineering and production experience. Prior to joining Belden & Blake he served as Vice President and District Manager of TXO Production Corporation in Corpus Christi, Texas. From 1967 to 1982, Mr. Clements held various operational management positions with Shell Oil Company.
Mr. Clements received a BS degree in Electrical Engineering from the University of North Dakota and a MS degree in Petroleum Engineering from the University of Tulsa. He is a member of the Society of Petroleum Engineers and the Ohio Oil and Gas Association.
RONALD E. HUFF has been President and Chief Financial Officer of the Company since the Acquisition, having previously served as its Senior Vice President and Chief Financial Officer from 1989 to 1996 and Senior Controller from 1986 to 1989. Mr. Huff has been a director of Belden & Blake since 1991. He is a Certified Public Accountant with 20 years of experience in oil and gas finance and accounting. From 1983 to 1986, Mr. Huff served as Vice President and Chief Accounting Officer of Towner Petroleum Company. From 1980 to 1983 he worked for Sonat Exploration Company as Manager of Financial Accounting; and from 1977 to 1980 he served as Corporate Accounting Supervisor for Transco Companies, Incorporated. Mr. Huff received a BS degree in Accounting from the University of Wyoming.
JOSEPH M. VITALE has been Senior Vice President Legal of the Company since 1989 and has served as its General Counsel since 1974. He has been a director of the Company since 1991. Prior to joining Belden & Blake, Mr. Vitale served for four years in the Army Judge Advocate General's Corps. He holds a BS degree from John Carroll University and a JD degree from Case Western Reserve Law School. He is a member of the Ohio Oil and Gas Association, the Stark County, Ohio State and American Bar Associations, and the Interstate Oil Compact Commission. Mr. Vitale is a past Chairman of the Natural Resources Law Committee of the Ohio State Bar Association.
TOMMY L. KNOWLES has been Senior Vice President of Exploration and Production of the Company since 1997. Previously he served as Vice President of Production from 1996 to 1997. He has 25 years of petroleum engineering and production experience. Prior to joining Belden & Blake, Mr. Knowles served as President of FWA Drilling Company, a subsidiary of Texas Oil & Gas Corporation. From 1982 to 1988 he worked for TXO Production Corporation in Sacramento, California, serving in various management positions including Vice President; from 1979 to 1982 he held the position of Drilling and Production Manager for Texas Oil & Gas Corporation; and, from 1973 to 1979 he held various engineering, supervisory and management positions with Exxon Corporation.
Mr. Knowles holds a BS degree in Mechanical Engineering from the University of Texas at Austin where he graduated with honors. He is a member of the Society of Petroleum Engineers, the American Petroleum Institute, and the Independent Association of Drilling Contractors.
LEO A. SCHRIDER has been Senior Vice President of Technical Development since 1993. He previously served as Senior Vice President of Exploration, Drilling and Engineering for the Company
since 1986. Mr. Schrider is a Petroleum Engineer with 35 years of experience in oil and gas production, principally in the Appalachian Basin. Prior to joining Belden & Blake in 1981, he served as Assistant and Deputy Director of Morgantown Energy Technology Center from 1976 to 1980. From 1973 to 1976, Mr. Schrider served as Project Manager of the Laramie Energy Research Center. He has also held various research positions with the U.S. Department of Energy in Wyoming and West Virginia.
Mr. Schrider received his BS degree from the University of Pittsburgh in 1961 and did graduate work at West Virginia University. He has published more than 35 technical papers on oil and gas production. He was an Adjunct Professor at West Virginia University and also served as a member of the International Board of Directors of the Society of Petroleum Engineers. In 1994, Mr. Schrider was elected to the Board of Directors of the Petroleum Technology Transfer Council and is chairman of the producer advisory group representing the Appalachian region.
DENNIS D. BELDEN has served as Vice President of Supply and Service for the Company since 1989 and has managed the Oilfield Supply and Service Division since 1992. He joined Belden & Blake in 1980 and served as the Company's land manager from 1980 to 1989. From 1976 to 1980 he was employed by Wilmot Mining Company as Special Projects Manager; from 1974 to 1976 he was Treasurer and General Manager of Cabbages & Kings Restaurant of Ohio; and from 1972 to 1974 he was employed by T & M Fuel as General Supervisor. Mr. Belden attended Kent State University. He is a member of the Ohio Oil and Gas Association.
DUANE D. CLARK has been Vice President of Gas Marketing for the Company since 1997. Previously, he served as General Manager of Gas Marketing from 1996 to 1997. He joined the Company in 1995 as a Gas Marketing Analyst. Prior to joining Belden & Blake, Mr. Clark held various management positions with Quaker State Corporation from 1978 to 1995. He has 20 years of experience in the oil and gas industry . Mr. Clark received his BA degree in Mathematics and Economics from Ohio Wesleyan University. His professional affiliations include the Ohio Oil and Gas Association, the Independent Oil and Gas Association of West Virginia and the Pennsylvania Oil and Gas Association.
JAMES C. EWING has been Vice President of Human Resources for the Company since 1997. He previously served as Human Resources Manager. Mr. Ewing joined Belden & Blake in April of 1986 and has 12 years of experience in the oil and gas industry and more than 20 years of experience in the Human Resource field. Prior to joining Belden & Blake, he was the Director of Personnel for the Union Metal Manufacturing Company from 1978 to 1986. Mr. Ewing holds a Bachelor of Arts degree in Psychology from West Liberty State College. He is a member of the Society for Human Resource Management. He is a founder and current member of the Stark County Health Care Coalition; President of the Stark County Historical Society; and, Chairman of the Business Advisory Board and adjunct faculty member of Kent State University.
CHARLES P. FABER has been Vice President of Corporate Development for the Company since 1993. He previously served as Senior Vice President of Capital Markets from 1988 to 1993. Prior to joining Belden & Blake, Mr. Faber was employed as Senior Vice President of Marketing for Heritage Asset Management from 1986 to 1988. From 1983 to 1986 he served as President and Chief Executive Officer of Samson Properties, Incorporated. Mr. Faber holds a BA degree in Marketing and an MBA in Finance from the University of Wisconsin where he graduated with honors. He is a member of the Independent Petroleum Association of America and the Ohio Oil and Gas Association.
ROBERT W. PESHEK has served as Vice President of Finance for the Company since 1997. Previously, he served as Corporate Controller and Tax Manager from 1994 to 1997. Prior to joining Belden & Blake, Mr. Peshek served as a Senior Manager of the Tax Department at Ernst & Young LLP from 1981 to 1994. He is a Certified Public Accountant with extensive experience in taxation, accounting and auditing. Mr. Peshek holds a Bachelor of Business Administration degree in Accounting from Kent State University where he graduated with honors. His professional affiliations include the American Institute of Certified Public Accountants and the Ohio Society of Certified Public Accountants.
DEAN A. SWIFT has served as Vice President, Assistant General Counsel and Assistant Secretary of the Company since 1989. He served as Assistant General Counsel of the Company from 1981 to 1989. From 1978 to 1981 he was associated with the law firm of Hahn, Loeser and Parks in Cleveland, Ohio. Mr. Swift received a BA degree from the University of the South and a JD degree from the University of Virginia. He is a member of the Stark County, Ohio State and American Bar Associations.
HENRY S. BELDEN IV served as Chairman and Chief Executive Officer of the Company from 1982 to 1997. He resigned as Chairman and Chief Executive Officer upon the Acquisition, and was appointed to serve on the Board of Directors upon consummation of the Acquisition. Mr. Belden has been involved in oil and gas production since 1955 and associated with Belden & Blake since 1967. Prior to joining Belden & Blake, he was employed by Ashland Oil & Refining Company and Halliburton Services, Incorporated. Mr. Belden attended Florida State University and the University of Akron and is a member of the 25-Year Club of the Petroleum Industry and the Board of Trustees of the Ohio Oil and Gas Association. He is also a member of the Regional Advisory Board of the Independent Petroleum Association of America and a director and a member of the Executive Committee of the Pennsylvania Grade Crude Oil Association. He is a member of the Interstate Oil Compact Commission. Other professional memberships include the World Business Council and the Association of Ohio Commodores. He is a director of KeyBank-Canton District and Phoenix Packaging Corporation.
LAWRENCE W. KELLNER has been Executive Vice President and Chief Financial Officer of Continental Airlines, Inc. since November 1996. Previously, he served as Senior Vice President and Chief Financial Officer at Continental from June 1995 to November 1996. Prior to joining Continental, he was Executive Vice President and Chief Financial Officer of American Savings Bank, F.A. from November 1992 to May 1995. Mr. Kellner graduated magna cum laude with a Bachelor of Science, Business Administration degree from the University of South Carolina.
MAX L. MARDICK was President and Chief Operating Office of the Company from 1990 to 1997, a director from 1992 to 1997 and a director of predecessor companies from 1988 to 1992. He resigned as President and Chief Operating Officer upon consummation of the Acquisition and was appointed to serve on the Board of Directors upon consummation of the Acquisition. He previously served as Executive Vice President and Chief Operating Officer from 1988 to 1990. Mr. Mardick is a Petroleum Engineer with more than 35 years of experience in domestic and international production, engineering, drilling operations and property evaluation. Prior to joining Belden & Blake, he was employed for more than 30 years by Shell Oil Company in various engineering, supervisory and senior management positions, including: Manager, Property Acquisitions and Business Development (1986-1988); Production Manager for Shell's Onshore and Eastern Divisions (1981-1986); Production Manager of Shell's Rocky Mountain Division (1980-1981); Operations Manager (1977-1980); and Engineering Manager (1975-1977). Mr. Mardick holds a BS degree in Petroleum Engineering from the University of Kansas. He is a member of the Society of Petroleum Engineers and the Ohio Oil and Gas Association. He has served as Vice Chairman of the Alabama-Mississippi section of the Mid-Continent Oil and Gas Association.
WILLIAM S. PRICE, III, who became a director upon consummation of the Acquisition, was a founding partner of Texas Pacific Group in 1993. Prior to forming Texas Pacific Group, Mr. Price was Vice President of Strategic Planning and Business Development for G.E. Capital, and from 1985 to 1991 he was employed by the management consulting firm of Bain & Company, attaining partnership status and acting as co-head of the Financial Services Practice. Mr. Price is a 1978 graduate of Stanford University and received a JD degree from the Boalt Hall School of Law at the University of California, Berkeley. Mr. Price serves on the Boards of Directors of AerFi Group plc, Beringer Wine Estates Holdings, Inc., Continental Airlines, Inc., Denbury Resources, Inc., Favorite Brands International, Inc., Vivra Specialty Partners, Inc. and Zilog, Inc.
GARETH ROBERTS is President, Chief Executive Officer and a Director of Denbury Resources, Inc. ("Denbury"), and is the founder of the operating subsidiary of Denbury, which was founded in April 1990. Mr. Roberts has 25 years of experience in the exploration and development of oil and natural gas properties with Texaco, Inc., Murphy Oil Corporation and Coho Resources, Inc. His expertise is particularly focused in the Gulf Coast region where he specializes in the acquisition and development of old fields with low productivity. Mr. Roberts holds honors and masters degrees in Geology and Geophysics from St. Edmund Hall, Oxford University.
DAVID M. STANTON, who became a director upon consummation of the Acquisition, is a partner of Texas Pacific Group. From 1991 until he joined Texas Pacific Group in 1994, Mr. Stanton was a venture capitalist with Trinity Ventures, where he specialized in information technology, software and telecommunications investing. Mr. Stanton earned a BS degree in Chemical Engineering from Stanford University and received an MBA from the Stanford Graduate School of Business. Mr. Stanton serves on the Boards of Directors of Denbury Resources, Inc., Globespan Semiconductor, Inc., GT Com and Paradyne Corp.
Item 11.
Item 11. EXECUTIVE COMPENSATION
The following table shows the annual and long-term compensation for services in all capacities to the Company during the fiscal years ended December 31, 1998, 1997 and 1996 of the Company's Chief Executive Officer and its other four most highly compensated executive officers.
SUMMARY COMPENSATION TABLE
- ---------------------
(1) All awards prior to June 27, 1997 relate to options to purchase stock in the predecessor company.
(2) Represents contributions of cash and Common Stock to the Company's 401(k) Profit Sharing Plan for the account of the named executive officers.
(3) Includes stock grants amounting to $60,803.
(4) Includes stock grants amounting to $17,500 and moving expenses of $34,269.
AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION/SAR VALUE
(1) There were no options exercised in 1998.
COMPENSATION OF DIRECTORS
The outside directors of the Company are compensated for their services at $7,500 per quarter. Directors employed by the Company or TPG are not compensated for their services.
EMPLOYMENT AND SEVERANCE AGREEMENTS
The Company has severance agreements with Messrs. Clements, Huff and Vitale which entitle each of them to receive a lump sum severance payment equal to 300% of the sum of (i) his respective annual base salary at the highest rate in effect for any period prior to his employment termination plus (ii) his highest annual bonus and incentive compensation during the three-year period preceding a change in control, in the event of the termination of his employment by the Company other than for "cause" (as defined therein) or his resignation in response to a substantial reduction in responsibilities, authority, position, compensation or location of his place of work prior to June 27, 2000. In addition, each of them would be entitled to receive an additional payment sufficient to cover any excise tax imposed by Section 4999 of the Code on the severance payments or other payment considered "contingent on a change in ownership or control" of the Company within the meaning of Section 280G of the Code.
Messrs. Clements and Huff each entered into employment agreements dated as of June 27, 1997 (the "Employment Agreements") providing for their employment as Chief Executive Officer and President, respectively, of the Company. The Employment Agreements provide for an annual base salary of not less than $300,000 payable to Mr. Clements and $250,000 payable to Mr. Huff. Messrs. Clements and Huff will each be entitled to earn an annual bonus of up to 50% of his annual base salary based on the attainment of certain goals to be set by the Company's Board of Directors. Each of Messrs. Clements and Huff agreed to continue to hold, and not surrender, certain stock options previously granted to him under the Company's Stock Option Plan, thereby foregoing the right to receive $334,220 each in cash upon the surrender of such options on consummation of the Acquisition. The Employment Agreements provide for the granting to each of Messrs. Clements and Huff of additional options to purchase shares of common stock of the Company constituting 1.25% of the outstanding common stock (on a fully-diluted basis) at an option price equivalent to the price paid by TPG in connection with the Acquisition. The options will vest over a four year period, with one-fourth (1/4) vesting one year after the date of grant and
the balance at the rate of one-twelfth (1/12) at the end of each quarter thereafter during the continuation of employment with the Company. The Employment Agreements provide for certain call options and rights of first refusal in connection with the shares of common stock obtainable upon the exercise of stock options.
The Employment Agreements provide that Messrs. Clements and Huff will be entitled to employee welfare and retirement benefits substantially comparable to those presently provided by the Company and to any other employee benefits later made available to senior executive management of the Company.
The Employment Agreements further provide that the existing severance agreements that Messrs. Clements and Huff have with the Company will remain in force and upon the expiration thereof will be replaced by new severance agreements providing substantially the same benefits.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During 1998, the Compensation and Organizational Committee of the Board of Directors consisted of William S. Price, III, Henry S. Belden IV and Gareth Roberts, all of whom are outside directors. No executive officer of the Company was a director or member of the compensation committee of any entity of which a member of the Company's board of directors or its Compensation and Organizational Committee was or is an executive officer.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information as of February 28, 1999 regarding the beneficial ownership of the Company's common stock by each person who beneficially owns more than five percent of the Company's outstanding common stock, each director, the chief executive officer and the four other most highly compensated executive officers and by all directors and executive officers of the Company, as a group:
*Less than 1%
(1) Neither TPG Advisors II, Inc. nor Mr. Price is the record owner of any shares of the Company's common stock. Mr. Price is, however, a director, executive officer and shareholder of TPG Advisors II, Inc., which is the general partner of TPG GenPar II, L.P., which in turn is the general partner of each of TPG II, TPG Investors II, L.P. and TPG Parallel II, L.P. which are the direct beneficial owners of 7,976,645, 832,047 and 544,346 shares of common stock, respectively.
(2) Consists of shares subject to stock options exercisable within 60 days.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In connection with the Acquisition, the Company entered into a Transaction Advisory Agreement with TPG Partners II, L.P. pursuant to which TPG Partners II, L.P. received a cash financial advisory fee of $5.0 million upon the closing of the Acquisition as compensation for its services as financial advisor in connection with the Acquisition. TPG Partners II, L.P. also will be entitled to receive (but, at its discretion, may waive) fees of up to 1.5% of the "transaction value" for each subsequent transaction (a tender offer, acquisition, sale, merger, exchange offer, recapitalization, restructuring or other similar transaction) in which the Company is involved. The term "transaction value" means the total value of any subsequent transaction, including, without limitation, the aggregate amount of the funds required to complete the subsequent transaction (excluding any fees payable pursuant to the Transaction Advisory Agreement and fees, if any, paid to any other person or entity for financial advisory, investment banking, brokerage or any other similar services rendered in connection with such transaction) including the amount of any indebtedness, preferred stock or similar items assumed (or remaining outstanding). The Transaction Advisory Agreement shall continue until the earlier of (i) 10 years from the execution date or (ii) the date on which TPG Partners II, L.P. and its affiliates cease to own, beneficially, directly or indirectly, at least 25% of the voting power of the securities of the Company. In management's opinion, the fees provided for under the Transaction Advisory Agreement reasonably reflect the benefits received and to be received by the Company.
Messrs. Belden and Mardick have each entered into non-competition agreements with the Company dated March 27, 1997 (the "Non-Competition Agreements"), which became effective contemporaneously with consummation of the Acquisition. Pursuant to the terms of the Non-Competition Agreements, Messrs. Belden and Mardick have each agreed, for a period of three (3) years from June 27, 1997 that he will not, in any county in the United States in which the Company does business, directly or indirectly, either for himself or as a member of a partnership or as a shareholder, investor, agent, associate or consultant engage in any business in which the Company is engaged immediately prior to June 27, 1997. Messrs. Belden and Mardick have each further agreed that he will not, directly or indirectly, make any misleading or untrue statement that disparages or would have the effect of disparaging the Company or any of its affiliates or employees or of adversely affecting the reputation, business or credit rating of the Company or any of its affiliates or employees, and that, for a period of three years from June 27, 1997, he will not, directly or indirectly, interfere with, or take any action that would have the effect of interfering with, the contractual and other relationships between the Company or any of its affiliates and any of its or their employees, customers or suppliers. In consideration of such agreements, Mr. Belden will receive $2,400,616.44 and Mr. Mardick will receive $983,711.16 in each case payable in 36 monthly installments.
PART IV
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Documents filed as a part of this report:
1. Financial Statements
The financial statements listed in the accompanying Index to Consolidated Financial Statements and Schedules are filed as part of this Annual Report on Form 10-K.
2. Financial Statement Schedules
No financial statement schedules are required to be filed as part of this Annual Report on Form 10-K.
3. Exhibits
*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.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
BELDEN & BLAKE CORPORATION
April 14, 1999 By: /s/ Ronald L. Clements - --------------------------------- -------------------------------- Date Ronald L. Clements Chief Executive Officer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
BELDEN & BLAKE CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
ITEM 14(a) (1) AND (2)
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.
REPORT OF INDEPENDENT AUDITORS
To the Shareholders and Board of Directors Belden & Blake Corporation
We have audited the accompanying consolidated balance sheets of Belden & Blake Corporation ("Successor Company") as of December 31, 1998 and 1997, and the related consolidated statements of operations, shareholders' equity (deficit) and cash flows for the year ended December 31, 1998 and the six month period ended December 31, 1997 ("Successor periods"). We have also audited the accompanying consolidated statements of operations, shareholders' equity (deficit) and cash flows of Belden & Blake Corporation ("Predecessor Company") for the six month period ended June 30, 1997 and the year ended December 31, 1996 ("Predecessor periods"). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Belden & Blake Corporation at December 31, 1998 and 1997 and the consolidated results of their operations and their cash flows for the Successor periods and the Predecessor periods in conformity with generally accepted accounting principles.
ERNST & YOUNG LLP
Cleveland, Ohio April 13, 1999
BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
See accompanying notes.
BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS)
See accompanying notes.
BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT) (IN THOUSANDS)
See accompanying notes.
BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
See accompanying notes.
BELDEN & BLAKE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) MERGER
On March 27, 1997, the Company signed a definitive merger agreement with TPG Partners II, L.P. ("TPG"), a private investment partnership, pursuant to which TPG and certain other investors acquired the Company in an all-cash transaction valued at $440 million. Under the terms of the agreement, TPG and such investors paid $27 per share for all common shares outstanding plus an additional amount to redeem certain stock options held by directors and employees. The transaction was completed on June 27, 1997 and for financial reporting purposes has been accounted for as a purchase effective June 30, 1997. The acquisition resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date. Accordingly, the financial statements for the periods subsequent to June 30, 1997 are presented on the Company's new basis of accounting, while the results of operations for the periods ended June 30, 1997 and December 31, 1996 reflect the historical results of the predecessor company. A vertical black line is presented to separate the financial statements of the predecessor and successor companies.
The following table presents the actual results of operations for the year ended December 31, 1998 and the unaudited pro forma results of operations for the years ended December 31, 1997 and 1996 as if the merger occurred at the beginning of 1996 (in thousands):
The unaudited pro forma information presented above assumes the transaction-related expenses were incurred prior to the period presented and does not purport to be indicative of the results that actually would have been obtained if the merger had been consummated at the beginning of 1996 and is not intended to be a projection of future results or trends.
In connection with the merger, the Company entered into a Transaction Advisory Agreement with TPG pursuant to which TPG received a cash financial advisory fee of $5.0 million for services as financial advisor in connection with the merger. The fee is included in the $16.8 million of transaction-related expenses. TPG also will be entitled to receive (but, at its discretion, may waive) fees of up to 1.5% of the transaction value for each subsequent transaction (a tender offer, acquisition, sale, merger, exchange offer, recapitalization, restructuring or other similar transaction) entered into by the successor company.
Certain former officers have entered into non-competition agreements with the Company dated March 27, 1997, which became effective contemporaneously with consummation of the merger. These agreements have a term of 36 months and had a total value of $3.0 million at June 27, 1997. The obligation for these agreements is included in the balance sheet.
(2) BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
BUSINESS
The Company operates primarily in the oil and gas industry. The Company's principal business is natural gas marketing and gathering and the production, acquisition and development of oil and gas
reserves. Sales of oil are ultimately made to refineries. Sales of gas are ultimately made to industrial and commercial consumers in Ohio, Michigan, West Virginia, Pennsylvania, New York and Kentucky and to gas utilities. The Company also provides oilfield services and is a distributor of a broad range of oilfield equipment and supplies. Its customers include other independent oil and gas companies, dealers and operators throughout Ohio, Michigan, West Virginia, Pennsylvania and New York. The price of oil and gas has a significant impact on the Company's working capital and results of operations.
PRINCIPLES OF CONSOLIDATION AND FINANCIAL PRESENTATION
The accompanying consolidated financial statements include the financial statements of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
USE OF ESTIMATES IN THE FINANCIAL STATEMENTS
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts. Significant estimates used in the preparation of the Company's financial statements which could be subject to significant revision in the near term include estimated oil and gas reserves. Although actual results could differ from these estimates, significant adjustments to these estimates historically have not been required.
CASH EQUIVALENTS
For purposes of the statements of cash flows, cash equivalents are defined as all highly liquid debt instruments purchased with an initial maturity of three months or less.
CONCENTRATIONS OF CREDIT RISK
Credit limits, ongoing credit evaluation and account monitoring procedures are utilized to minimize the risk of loss. Collateral is generally not required. Expected losses are provided for currently and actual losses have been within management's expectations.
INVENTORIES
Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural gas inventories are stated at the lower of average cost or market.
PROPERTY AND EQUIPMENT
The Company utilizes the "successful efforts" method of accounting for its oil and gas properties. Under this method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, dry holes, expired leases and delay rentals, are expensed as incurred. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.
Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense. During 1998, the Company recorded a $5.8 million impairment which wrote-down unproved oil and gas properties to their estimated fair value.
Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years.
Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is charged to income as incurred, and significant renewals and betterments are capitalized.
Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and carrying value of the asset. In performing the review for long-lived asset recoverability during 1998, the Company recorded $148.0 million and $6.9 million of impairments which wrote-down producing properties and other assets, respectively, to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the assets, discounted at a market rate of interest.
INTANGIBLE ASSETS
Intangible assets totaling $16 million at December 31, 1998, include deferred debt issuance costs, goodwill and other intangible assets and are being amortized over 25 years or the shorter of their respective terms.
REVENUE RECOGNITION
Oil and gas production revenue is recognized as production and delivery take place. Oil and gas marketing revenues are recognized when title passes. Oilfield sales and service revenues are recognized when the goods or services have been provided.
INCOME TAXES
The Company uses the liability method of accounting for income taxes. Deferred income taxes are provided for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred income taxes also are recognized for operating losses that are available to offset future taxable income and tax credits that are available to offset future federal income taxes.
STOCK-BASED COMPENSATION
The Company measures expense associated with stock-based compensation under the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees."
Belden & Blake Corporation common stock held in the 401k plan is subject to variable plan accounting. The changes in share value are reported as adjustments to compensation expense. The reduction in share value in 1998 resulted in a reduction in compensation expense of $403,000.
(3) ACCOUNTING CHANGES
During 1998, the Company adopted Statement of Financial Accounting Standards No. (SFAS) 130, "Reporting Comprehensive Income," Statement of Financial Accounting Standards No. (SFAS) 131, "Disclosures about Segments of an Enterprise and Related Information" and Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained for Internal Use."
SFAS 130 establishes standards for reporting and displaying comprehensive income and its components in general-purpose financial statements. This pronouncement had no effect on the Company's financial statements.
SFAS 131 establishes standards for public business enterprises for reporting information about operating segments in annual financial statements and requires that such enterprises report selected information about operating segments in interim financial reports issued to shareholders. This Statement also establishes standards for related disclosures about products and services, geographic areas, and major customers. See Note 18.
SOP 98-1 requires companies to capitalize certain qualified costs incurred in connection with internal-use software development projects. Adoption of this standard was not material to the Company's financial position, operating results or cash flows.
(4) NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. (SFAS) 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. SFAS 133 is effective for fiscal years beginning after June 15, 1999. On adoption, the provisions of SFAS 133 must be applied prospectively as the cumulative effect of an accounting change. The Company has not determined the impact that SFAS 133 will have on its financial statements and has not determined the timing of or method of adoption of SFAS 133.
(5) ACQUISITIONS
The following acquisitions were accounted for as purchase business combinations. Accordingly, the results of operations of the acquired businesses are included in the Company's consolidated statements of operations from the date of the respective acquisitions.
During 1998, the Company acquired working interests in oil and gas wells in Ohio, West Virginia, Michigan and New York for approximately $7.6 million. Estimated proved developed reserves associated with the wells totaled 8.8 Bcfe net to the Company's interest at the time of acquisition. The Company also acquired undeveloped properties and other assets for $4.2 million.
On March 19, 1998, the Company entered into an agreement in principle with FirstEnergy Corp. ("FirstEnergy") to form an equally-owned joint venture to be named FE Holdings L.L.C. ("FE Holdings") to engage in the exploration, development, production, transportation and marketing of natural gas. Formation of the joint venture was subject to the negotiation and execution of a definitive joint venture agreement. The Company was unable to reach agreement with FirstEnergy regarding certain terms of the joint venture agreement and in June 1998, the Company determined it would not participate in the proposed joint venture. Costs of $372,000 related to the proposed formation of the joint venture and to due diligence associated with a proposed acquisition by FE Holdings were written-off to general and administrative expense in 1998.
During 1997, the Company acquired working interests in oil and gas wells in Ohio, Pennsylvania, West Virginia and Michigan for approximately $13.5 million for the successor company's six months ended December 31, 1997 and $7.8 million for the predecessor company's six months ended June 30, 1997. Estimated proved developed reserves associated with the wells totaled 32.8 Bcf of natural gas and 101,000 Bbls of oil net to the Company's interest at the time of the acquisitions.
During 1996, the Company acquired for approximately $4.1 million working interests in 323 oil and gas wells in Ohio and Kentucky. Estimated proved developed reserves associated with the wells totaled 6.0 Bcf of natural gas and 205,000 Bbls of oil net to the Company's interest at July 1, 1996.
The pro forma effects of the 1998, 1997 (predecessor and successor periods) and the 1996 acquisitions were not material.
(6) EXPANSION OF GAS MARKETING CAPABILITY
In July 1998, the Company began development of a major expansion of its gas marketing capability, with the objective of substantially increasing the number of industrial and commercial customers served, the volumes of gas sold and future net operating margins from gas sales. The expansion includes the selection and installation of systems and technology to enhance the efficiency of the gas marketing operation.
Through December 31, 1998, the Company expensed $731,000 related to this expansion project, which was included in "Cost of gas and gathering expense" in the Consolidated Statements of Operations. The Company has adopted SOP 98-1, and has capitalized $46,000 of certain internal costs associated with the development of the systems. The Company has also capitalized $878,000 of other external costs related to this expansion project. The majority of these expenditures relate to consulting services associated with the selection of the systems.
(7) DETAILS OF BALANCE SHEETS
(8) LONG-TERM DEBT
Long-term debt consists of the following (in thousands):
On June 27, 1997, the Company completed a private placement (pursuant to Rule 144A) of $225 million of 9 7/8% Senior Subordinated Notes, Series A, which mature on June 15, 2007. The notes were
issued under an indenture which requires interest to be paid semiannually on June 15 and December 15 of each year, commencing December 15, 1997. The notes are subordinate to the senior revolving credit agreement. In September 1997, the Company completed a registration statement on Form S-4 providing for an exchange offer under which each Series A Senior Subordinated Note would be exchanged for a Series B Senior Subordinated Note. The terms of the Series B Notes are the same in all respects as the Series A Notes except that the Series B Notes have been registered under the Securities Act of 1933 and therefore will not be subject to certain restrictions on transfer.
The notes are redeemable in whole or in part at the option of the Company, at any time on or after June 15, 2002, at the redemption prices set forth below plus, in each case, accrued and unpaid interest, if any, thereon.
Prior to June 15, 2000, the Company may, at its option, on any one or more occasions, redeem up to 40% of the original aggregate principal amount of the notes at a redemption price equal to 109.875% of the principal amount, plus accrued and unpaid interest, if any, on the redemption date, with all or a portion of net proceeds of public sales of common stock of the Company; provided that at least 60% of the original aggregate principal amount of the notes remains outstanding immediately after the occurrence of such redemption; and provided, further, that such redemption shall occur within 60 days of the date of the closing of the related sale of common stock of the Company.
The indenture under which the subordinated notes were issued contains certain covenants that limit the ability of the Company and its subsidiaries to incur additional indebtedness and issue stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens, and engage in mergers and consolidations.
On June 27, 1997, the Company also entered into a senior revolving credit agreement with several lenders. These lenders committed, subject to compliance with the borrowing base, to provide the Company with revolving credit loans of up to $200 million, of which $25 million will be available for the issuance of letters of credit. The credit agreement is a senior revolving credit facility which is secured by substantially all of the Company's assets. The borrowing base is the sum of the Company's proved developed reserves, proved developed non-producing reserves, proved undeveloped reserves and related processing and gathering assets and other assets of the Company, adjusted by the engineering committee of the bank in accordance with their standard oil and gas lending practices. If less than 75% of the borrowing base is utilized, the borrowing base will be re-determined annually. If more than 75% of the borrowing base is utilized, the borrowing base will be re-determined semi-annually. The Company's borrowing base at December 31, 1998 was $170 million. On January 15, 1999 the Company's borrowing base was redetermined at $126 million. The Company had $154 million outstanding under this agreement at December 31, 1998 which resulted in the Company having a borrowing base deficiency of $28 million. The Company has agreed with the lenders, to reduce this deficiency by $14 million on March 22, 1999 and by the remaining $14 million on May 10, 1999.
On March 22, 1999 the Company made a $14 million payment to reduce the outstanding amount under the credit agreement to $140 million. The funds for the payment were provided by internally
generated cash flow and a term loan provided by Chase Manhattan Bank. This term loan provided borrowings of $9 million and is due on September 22, 1999. Interest is payable monthly at LIBOR plus 1.5%. The Company is in the process of renegotiating its revolving credit facility with its lenders and expects to have a new facility in place prior to May 10, 1999, when the second payment of $14 million is due. Should the Company not be successful in renegotiating an acceptable facility, the Company expects to be able to meet its 1999 debt service requirements through internally generated cash flow, the sale of non-strategic assets and/or the use of instruments in financial futures markets.
The Company borrowed $104 million under the credit agreement in 1997 to partially finance the acquisition of the Company by TPG; to repay certain existing outstanding indebtedness of the Company and to pay certain fees and expenses related to the transaction. The credit agreement will mature on June 27, 2002. Outstanding balances under the agreement incur interest at the Company's choice of several indexed rates, the most favorable being 6.566% at December 31, 1998.
The credit agreement contains a number of covenants that, among other things, restricts the ability of the Company and its subsidiaries to dispose of assets, incur additional indebtedness, prepay other indebtedness or amend certain debt instruments, pay dividends, create liens on assets, enter into sale and leaseback transactions, make investments, loans or advances, make acquisitions, engage in mergers or consolidations, change the business conducted by the Company or its subsidiaries, make capital expenditures or engage in certain transactions with affiliates and otherwise restrict certain corporate activities. In addition, under the credit agreement, the Company is required to maintain specified financial ratios and tests, including minimum interest coverage ratios and maximum leverage ratios. The agreement requires a minimum working capital ratio of 1.00 to 1.00. As of December 31, 1998 the Company's working capital ratio was .90 to 1.00. The Company and its lenders have agreed to exclude the $28 million required reduction in outstanding borrowings from the covenant requiring a specific working capital ratio. The ratio after excluding the $28 million results in a working capital ratio of 1.58 to 1.00.
In connection with the senior subordinated notes and the credit agreement, the Company allocated $9.5 million of fees paid to investment bankers to deferred debt issuance costs.
The Company may enter into interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of the Company's floating rate exposure would be exchanged for a fixed interest rate. During October 1997, the Company entered into two interest rate swap arrangements with a major financial institution covering $90 million of debt. The Company swapped $40 million of floating three-month LIBOR +1.5% for a fixed rate of 7.485% for three years, extendible at the institution's option for an additional two years. The Company also swapped $50 million of floating three-month LIBOR +1.5% for a fixed rate of 7.649% for five years. In June 1998 the Company entered into a third interest rate swap covering $50 million of debt. The Company swapped $50 million of floating rate three-month LIBOR + 1.50% for a fixed rate of 7.2825% for three years. The Company had no such derivative financial instruments at December 31, 1996. Under the deferral method, gains and losses on these instruments are deferred on the balance sheet and the interest rate differential to be received or paid is recognized as an adjustment to interest expense for the month hedged.
On April 3, 1997, the Company gave notice of redemption of all of the outstanding 9.25% convertible subordinated debentures for 104% of face value. Redemption of these debentures occurred June 10, 1997 when holders of the debentures elected to convert them into 275,425 shares of common stock in the predecessor company.
At December 31, 1998, the aggregate long-term debt maturing in the next five years is as follows: $28,098,000 (1999); $18,000 (2000); $18,000 (2001); $126,018,000 (2002); $19,000 (2003); and $225,105,000 (2004 and thereafter).
(9) LEASES
The Company leases certain computer equipment, vehicles and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $2.2 million and $1.0 million for the successor company's year ended December 31, 1998 and six months ended December 31, 1997, respectively, and $1.0 million and $1.6 million for the predecessor company's six months ended June 30, 1997 and the year ended December 31, 1996, respectively. Future commitments under leasing arrangements were not significant at December 31, 1998.
(10) SHAREHOLDERS' EQUITY
In November 1998 and 1997, the Company awarded 118,274 and 110,915 shares of successor company common stock, respectively, to employees as profit sharing and bonuses. These shares were issued in each subsequent year.
On December 31, 1992, the Company issued 24,000 shares of Class II Serial Preferred Stock with a stated value of $100 per share. In preference to shares of predecessor company common stock, each share was entitled to cumulative cash dividends of $7.50 per year, payable quarterly. The Preferred Stock was subject to redemption at $100 per share at any time by the Company and was convertible into predecessor company common stock, at the holder's election, at any time after five years from the date of issuance at a conversion price of $15.00 per predecessor company common share. Holders of the Preferred Stock were entitled to one vote per preferred share. On March 31, 1997, the Company redeemed all of the outstanding Class II Series A preferred stock for $2.4 million in cash.
In December 1996 the Company awarded 36,077 shares of predecessor company common stock to employees as profit sharing and bonuses. These shares were issued in 1997.
In November 1996, $1,250,000 of convertible subordinated debentures were converted by the debenture holders at the rate of one share of the Company's predecessor company common stock for each $20.15 of principal into 62,034 shares of predecessor company common stock.
(11) STOCK OPTION PLANS
In connection with the merger, certain executives of the predecessor company had agreed that they would not exercise or surrender certain stock options having an aggregate value of $1.8 million at June 27, 1997, based on the intrinsic value of the options (the difference between the exercise price of the options and a purchase price of $27 per share). These options were exchanged for 165,083 in new stock options of the successor company based on the intrinsic value of the predecessor company's options at the date of the transaction.
The Company has an employee stock option plan which is authorized to issue up to 824,195 shares of common stock to officers and employees. The option price per share is the fair value of a share of common stock on the date of grant, as determined by the Company's board of directors. The expiration date of each option is fixed by the board of directors at not more than ten years from the date of grant. The options become exercisable from time to time over periods and upon terms and conditions as the board of directors determines. Current outstanding options become exercisable in 25% increments over a four-year period beginning one year from date of grant. As of December 31, 1998, there were 171,571 shares available for grant under the Plan.
The Company has an employee stock option plan which is authorized to issue up to 1,070,000 shares of common stock to officers and employees. The exercise price of options may not be less than the fair market value of a share of common stock on the date of grant. Options expire on the tenth anniversary of the grant date unless cessation of employment causes earlier termination. The options became exercisable in 25% increments over a four-year period beginning one year from date of grant.
The Company has a Non-Employee Directors Stock Option Plan authorizing the issuance of up to 120,000 shares of common stock. The exercise price of options under the Plan is equal to the fair market value on the date of grant. Options expire on the tenth anniversary of the grant date. The options become exercisable on the anniversary of the grant date at a rate of one third of the shares each year.
The Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25) and related Interpretations in accounting for its employee stock options because, as discussed below, the alternative fair value accounting provided for under SFAS 123, "Accounting for Stock-Based Compensation" requires use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, no compensation expense is recognized because the exercise price of the Company's employee stock options equals the market price of the underlying stock on the date of the grant.
Pro forma information regarding net income is required by Statement 123, and has been determined as if the Company had accounted for its employee stock options under the fair value method of that Statement. The fair value for these stock options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 1996 and 1997 (predecessor and successor periods), respectively: risk-free interest rates of 6.5% and 6.1%; volatility factors of the expected market price of the Company's common stock of .36 and near zero; dividend yield of zero; and a weighted-average expected life of the option of seven years. There were no options issued in 1998.
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its stock options.
For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The Company's pro forma information for grants made after January 1, 1995, follows: net loss of $130.8 million and $11.4 million for the successor company's year ended December 31, 1998 and six months ended December 31, 1997, respectively, and net loss of $12.4 million and net income of $14.3 million for the predecessor company's six months ended June 30, 1997 and the year ended December 31, 1996, respectively.
The effects of applying Statement 123 for providing pro forma disclosures are not indicative of future amounts until the new rules are applied to all outstanding, nonvested awards.
Stock option activity under the three plans consisted of the following:
No options were granted in 1998. The weighted average fair value of options granted during the years 1997 and 1996 were $1.98 and $10.59 per share, respectively. The exercise price for the options outstanding as of December 31, 1998 ranged from $.10 to $10.82 per share. At December 31, 1998 the weighted average remaining contractual life of the outstanding options is 8.7 years.
12) TAXES
The (benefit) provision for income taxes on continuing operations includes the following (in thousands):
The effective tax rate for continuing operations differs from the U.S. federal statutory tax rate as follows:
Significant components of deferred income tax liabilities and assets are as follows (in thousands):
SFAS No. 109 requires a valuation allowance to be recorded when it is more likely than not that some or all of the deferred tax assets will not be realized. The valuation allowance at December 31, 1998 relates principally to certain net operating loss carryforwards which management estimates will expire before they can be utilized.
At December 31, 1998, the Company had approximately $66 million of net operating loss carryforwards available for federal income tax reporting purposes. Approximately $1 million of the net operating loss carryforwards are limited as to their annual utilization as a result of prior ownership changes. These net operating loss carryforwards, if unused, will expire from 2001 to 2006. The remaining net operating loss carryforwards will expire in 2012 and 2018. The Company has alternative minimum tax credit carryforwards of approximately $700,000 which have no expiration date. The
Company has approximately $600,000 of statutory depletion carryforwards, which have no expiration date.
(13) PROFIT SHARING AND RETIREMENT PLANS
The Company has a non-qualified profit sharing arrangement under which the Company contributes discretionary amounts determined by the compensation committee of its Board of Directors. Amounts are allocated to substantially all employees based on relative compensation. The Company contributed $938,000 and $749,500 for the successor company's year ended December 31, 1998 and six months ended December 31, 1997, respectively, and $588,900 and $1.3 million for the predecessor company's six months ended June 30, 1997 and year ended December 31, 1996, respectively, to the profit sharing plan of which one half was paid in cash and one half was paid in shares of the Company's common stock contributed into each eligible employee's 401(k) plan account. Additional discretionary bonuses are also made.
The Company has a qualified defined contribution plan (a 401(k) plan) covering substantially all of the employees of the Company. Under the plan, an amount equal to 2% of participants' compensation is contributed by the Company to the plan each year. Eligible employees may also make voluntary contributions which the Company matches $.50 for every $1.00 contributed up to 6% of an employee's annual compensation. Prior to January 1, 1998, the Company matched $.25 for every $1.00 contributed up to 6% of an employee's annual compensation. Retirement plan expense amounted to $867,000 and $285,000 for the successor company's year ended December 31, 1998 and six months ended December 31, 1997, respectively, and $266,000 and $457,000 for the predecessor company's six months ended June 30, 1997 and year ended December 31, 1996, respectively.
The Company also has non-qualified deferred compensation plans which permit certain key employees to elect to defer a portion of their compensation.
(14) COMMITMENTS AND CONTINGENCIES
The Company is involved in various legal actions arising in the normal course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the financial position of the Company.
(15) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(16) FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of the financial instruments disclosed herein is not representative of the amount that could be realized or settled, nor does the fair value amount consider the tax consequences, if any, of realization or settlement. The amounts in the financial statements for cash equivalents, accounts receivable and notes receivable approximate fair value due to the short maturaties of these instruments. The recorded amounts of outstanding bank and other long term debt approximate fair value because interest rates are based on LIBOR or the prime rate or due to the short maturaties. The $225.0 million in senior subordinated notes had an approximate fair value of $157.5 million at December 31, 1998 based on rates available for similar instruments. The estimated fair value of interest rate swaps was an unrealized loss of $4.2 million at December 31, 1998 based on current market prices.
From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas price volatility. The Company employs a policy of hedging gas production sold under NYMEX based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. Under the deferral method, gains and losses on these instruments are deferred on the balance sheet and are included as an adjustment to gas revenue for the production being hedged in the contract month. The Company incurred pre-tax gains on its hedging activities of $1.5 million in 1998 and losses on its hedging activities of $116,000 in 1997 and $258,000 in 1996.
During 1998, the Company hedged 6.2 Bcf of 1999 gas production at a weighted average NYMEX price of $2.44 per Mcf which represented a net unrealized gain of $2.8 million at December 31, 1998. At December 31, 1997, the Company had a net unrealized gain of $422,000.
(17) SUPPLEMENTARY INFORMATION ON OIL AND GAS ACTIVITIES
The following disclosures of costs incurred related to oil and gas activities are presented in accordance with SFAS 69.
The amounts reflected in the above table do not include the effects of purchase accounting which resulted from the TPG merger. See Note 1.
PROVED OIL AND GAS RESERVES (UNAUDITED)
The Company's proved developed and proved undeveloped reserves are all located within the United States. The Company cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production
history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made.
The estimates of proved developed reserves have been reviewed by independent petroleum engineers. The estimates of proved undeveloped reserves were prepared by the Company's petroleum engineers and the December 31, 1998 proved undeveloped reserves have been reviewed by independent petroleum engineers.
The following table sets forth changes in estimated proved and proved developed reserves for the periods indicated:
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (UNAUDITED)
The following tables, which present a standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves, are presented pursuant to SFAS No. 69. In computing this data, assumptions other than those required by the FASB could produce different results. Accordingly, the data should not be construed as representative of the fair market value of the Company's proved oil and gas reserves. The following assumptions have been made:
- Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements.
- Production and development costs were computed using year-end costs assuming no change in present economic conditions.
- Future net cash flows were discounted at an annual rate of 10%.
- Future income taxes were computed using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion.
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is presented below:
The principal sources of changes in the standardized measure of future net cash flows are as follows (the successor and predecessor periods are combined in 1997 for purposes of this presentation):
(18) INDUSTRY SEGMENT FINANCIAL INFORMATION
GENERAL INFORMATION
The Company's operations are conducted in the United States and are managed along three reportable segments which include: (1) exploration and production, (2) gas marketing and gathering, and (3) oilfield sales and service. The Company's reportable segments were identified based on the nature of the business activities of each component organized primarily by products or services provided. The exploration and production segment derives its revenues primarily through the production of oil and natural gas, acquiring and enhancing the economic performance of producing oil and gas properties and exploring for and developing natural gas and oil reserves. The gas marketing and gathering segment derives its revenues primarily from gas marketed directly to commercial and industrial customers and from its operation of natural gas gathering lines. The oilfield sales and service segment derives its revenues primarily from oilfield services provided and from the sale of a broad range of oilfield supplies. The Company has no material operations in any individual foreign country.
FINANCIAL INFORMATION AND RECONCILIATION
The following tables present certain financial information for the successor company's year ended December 31, 1998 and six months ended December 31, 1997 and the predecessor company's six months ended June 30, 1997 and year ended December 31, 1996 regarding the Company's reportable segments of its continuing operations. The "all other" column in each of the following tables includes unallocated corporate charges that support the segments and eliminations of all intersegment transactions to reconcile the reportable segment's revenues, income or loss, assets and other significant items to the Company's consolidated totals. Segment information for the periods prior to the year ended December 31, 1998 has been restated to reflect changes in the composition of reportable segments. Income and expense items below operating (loss) income are not allocated to the segments and are not disclosed.
MEASUREMENT
The Company measures segment operating results based on earnings before interest, taxes, depreciation, depletion, amortization and exploration expense and results from continuing operations before income taxes. The accounting policies of the reportable segments are the same as those described in the summary of significant accounting policies. Intersegment sales are billed on an intercompany basis at prices for comparable third party goods and services.
MAJOR CUSTOMERS
No customer exceeded 10% of consolidated revenue during the year ended December 31, 1998, the six months ended June 30, 1997 and December 31, 1997 and the year ended December 31, 1996.
(19) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
The results of operations for the four quarters of 1998 and 1997 are shown below (in thousands).
(1) The net loss in the fourth quarter of 1998 includes pre-tax impairment losses of $160.7 million. See note 2.
(20) DISCONTINUED OPERATIONS
In September 1995, the Company announced plans to sell Engine Power Systems, Inc. ("EPS"), its wholly-owned subsidiary engaged in engine, parts and service sales. The Company was unable to identify an acceptable buyer for EPS by the end of 1996. A substantial portion of the workforce was eliminated and substantial assets were sold and the Company recognized an additional charge in 1996 to reduce the remaining assets to net realizable value. The remaining assets were sold in 1997. Net revenues generated by EPS were approximately $3.9 million in 1996 and $4.2 million in 1995. Loss from operations of discontinued business was $180,000 ($117,000 net of tax benefit) in 1996 and $760,000 ($492,000 net of tax benefit) in 1995. Estimated loss on disposal was $495,000 ($322,000 net of tax benefit) in 1996 and $1.0 million ($647,000 net of tax benefit) in 1995. The results of operations of EPS are presented as discontinued operations in the accompanying financial statements for all periods presented.
(21) SALE OF TAX CREDIT PROPERTIES
In March 1998, the Company sold certain interests that qualify for the nonconventional fuel source tax credit. The interests were sold for approximately $730,000 in cash and a volumetric production payment under which 100% of the cash flow from the properties will go to the Company until approximately 10.8 Bcf (billion cubic feet) of gas has been produced and sold. In addition to receiving 100% of the cash flow from the properties, the Company will receive quarterly incentive payments based on production from the interests. The Company has the option to repurchase the interests at a future date.
In February and March 1996, the Company sold certain interests that qualify for the nonconventional fuel source tax credit. The interests were sold in two separate transactions for approximately $750,000 and $100,000, respectively, in cash and a volumetric production payment under which 100% of the cash flow from the properties will go to the Company until approximately 11.7 Bcf and 3.4 Bcf, respectively, of gas has been produced and sold. In addition to receiving 100% of the cash flow from the properties, the Company will receive quarterly incentive payments based on production from the interests. The Company has the option to repurchase the interests at a future date.