-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Chz3g7L2U0WqGTLCtEFDeNAKOTCE2l5RsB0oz1hWEXvrc16B2MwUHWssY97EfYJK 6mCO95/aXhyXjDEHNlMwQw== 0000950152-98-002622.txt : 19980331 0000950152-98-002622.hdr.sgml : 19980331 ACCESSION NUMBER: 0000950152-98-002622 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980327 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: BELDEN & BLAKE CORP /OH/ CENTRAL INDEX KEY: 0000880114 STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381] IRS NUMBER: 341686642 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 000-20100 FILM NUMBER: 98577148 BUSINESS ADDRESS: STREET 1: 5200 STONEHAM RD STREET 2: P O BOX 2500 CITY: NORTH CANTON STATE: OH ZIP: 44720 BUSINESS PHONE: 2164991660 MAIL ADDRESS: STREET 1: 5200 STONEHAM RD STREET 2: P O BOX 2500 CITY: NORTH CANTON STATE: OH ZIP: 44720 10-K405 1 BELDEN & BLAKE CORPORATION 10-K405 1 FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 [x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File No. 0-20100 BELDEN & BLAKE CORPORATION (Exact name of registrant as specified in its charter) OHIO 34-1686642 (State or other jurisdiction of (I.R.S. Employer Identification incorporation or organization) Number) 5200 STONEHAM ROAD NORTH CANTON, OHIO 44720 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (330) 499-1660 Securities registered pursuant to Section 12(b) of the Act: NONE Securities registered pursuant to Section 12(g) of the Act: COMMON STOCK, WITHOUT PAR VALUE (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No__ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X The aggregate market value of the voting stock held by non-affiliates of the registrant as of February 28, 1998 was $8,200,229. The number of shares outstanding of registrant's common stock, without par value, as of February 28, 1998 was 10,110,915. DOCUMENTS INCORPORATED BY REFERENCE None. 2 PART I - ------ Item 1. BUSINESS -------- Throughout this report, the "Company" refers to Belden & Blake Corporation ("Successor Company") and its predecessor which were acquired by TPG Partners II L.P. on March 27, 1997 (see Significant Events under this Item). The operations of the successor company represent 100% of the businesses of the predecessor. Therefore certain operational data for the twelve months ended December 31, 1997 has been presented on a combined basis because such information is comparable to the historical data of the predecessor. The historical financial statements of the successor company and its predecessor are presented separately as described in Note 1 to the consolidated financial statements included under Item 8. GENERAL Belden & Blake Corporation, an Ohio corporation (the "Company"), is primarily engaged in producing oil and natural gas, acquiring and enhancing the economic performance of producing oil and gas properties, exploring for and developing natural gas and oil reserves and gathering and marketing natural gas. Until 1995, the Company conducted business exclusively in the Appalachian Basin where it has operated since 1942 through several predecessor entities. It is now one of the largest exploration and production companies operating in the Appalachian Basin in terms of reserves, acreage held and wells operated. In early 1995, the Company commenced operations in the Michigan Basin through the acquisition of Ward Lake Drilling, Inc. ("Ward Lake"), an exploration and production company, which owns and operates oil and gas properties in Michigan's lower peninsula. In September 1996, the Company entered the Illinois Basin by acquiring the Shrewsbury Field in northwestern Kentucky. At December 31, 1997, the Company owned interests in 8,070 gross (7,232 net) productive gas and oil wells in Ohio, West Virginia, Pennsylvania, New York, Michigan and Kentucky with proved reserves totaling 291.6 Bcf (billion cubic feet) of gas and 5.6 Mmbbl (million barrels) of oil. The estimated future net revenues from these reserves had a present value before income taxes of approximately $292.6 million at December 31, 1997. At that date, the Company held leases on 1,250,226 gross (1,081,558 net) acres, including 625,450 gross (520,691 net) undeveloped acres. At December 31, 1997, the Company operated more than 7,900 wells, including wells operated for third parties. The Company owned and operated approximately 3,000 miles of gas gathering systems with access to the commercial and industrial gas markets of the northeastern United States at December 31, 1997. At December 31, 1997, the Company's net production was approximately 83 Mmcf (million cubic feet) of gas and 1,980 Bbls (barrels) of oil per day. At that date, the Company was marketing approximately 141 Mmcf of gas per day, consisting of its own production and gas purchased from third parties. The Company has grown principally through the acquisition of producing properties and related gas gathering facilities and exploration and development of its own acreage. From its formation in 1992 through December 31, 1997, the Company has acquired for $150.7 million producing properties with 226.4 Bcfe (billion cubic feet of natural gas equivalent) of proved developed reserves at an average cost of $.67 per Mcfe (thousand cubic feet of natural gas equivalent) and spent $20.5 million to acquire and develop additional gas gathering facilities. During the period from 1992 through 1997, the Company 1 3 drilled 808 gross (609.5 net) wells at an aggregate cost of approximately $115.2 million for the net wells. This drilling added 124.0 Bcfe to the Company's proved reserves. During 1997, the Company drilled 261 gross (199.6 net) wells at a direct cost of approximately $40.5 million for the net wells. The 1997 drilling activity added 41.9 Bcfe of proved reserves at an average cost of $.97 per Mcfe. Reserves added through drilling in 1997 represent approximately 132% of 1997 production. The Company maintains its corporate offices at 5200 Stoneham Road, North Canton, Ohio 44720. Its telephone number at that location is (330) 499-1660. Unless the context otherwise requires, all references herein to the "Company" are to Belden & Blake Corporation, its subsidiaries and predecessor entities. SIGNIFICANT EVENTS On March 27, 1997, the Company signed a definitive merger agreement with TPG Partners II, L.P. ("TPG"), a private investment partnership, pursuant to which TPG and certain other investors acquired the Company in an all-cash transaction valued at $440 million. Under the terms of the agreement, TPG and such investors paid $27 per share for all common shares outstanding plus an additional amount to redeem certain options held by directors and employees. The transaction was completed on June 27, 1997 and for financial reporting purposes has been accounted for as a purchase effective June 30, 1997. On June 27, 1997, the Company completed a private placement (pursuant to Rule 144A) of $225 million of 9 7/8% Senior Subordinated Notes, Series A, which mature on June 15, 2007. The notes were issued under an indenture which requires interest to be paid semiannually on June 15 and December 15 of each year, commencing December 15, 1997. The notes are subordinate to the new credit agreement. In September 1997, the Company completed a registration statement on Form S-4 providing for an exchange offer under which each Series A Senior Subordinated Note would be exchanged for a Series B Senior Subordinated Note. The terms of the Series B Notes are the same in all respects as the Series A Notes except that the Series B Notes have been registered under the Securities Act of 1933 and therefore will not be subject to certain restrictions on transfer. RECENT DEVELOPMENTS SUBSEQUENT EVENTS On March 19, 1998, the Company entered into an agreement with FirstEnergy Corp. ("FirstEnergy") to form an equally owned joint venture to be named FE Holdings, L.L.C. ("FE Holdings") to engage in the exploration for, development, production, transportation and marketing of natural gas. Under the agreement, the Company proposes to contribute its gas marketing division to FE Holdings and provide FE Holdings with its gas marketing, operational and management expertise. FirstEnergy, a diversified energy services holding company headquartered in Akron, Ohio, comprises the nation's twelfth largest investor-owned electric utility system. Its electric utility operating companies - -- Ohio Edison Company and its subsidiary, Pennsylvania Power Company; The Illuminating Company; and Toledo Edison Company -- serve 2.2 million customers within 13,200 square miles of northern and central Ohio and western Pennsylvania. FirstEnergy produces approximately $5 billion in annual revenues and owns more than $18 billion in assets, including ownership in 18 power plants. In an expansion of its energy-related products and services, FirstEnergy in December 1997 acquired Roth Bros., 2 4 Inc., and RPC Mechanical, Inc., which form one of the nation's largest providers of engineered heating, ventilating and air-conditioning equipment and energy management and control systems. The joint venture is expected to substantially expand the Company's market outlet for its production of natural gas and more fully utilize the capabilities and capacity of the Company's Gas Marketing Division. The venture will allow FirstEnergy to offer its customers total energy services, including natural gas, electricity and related energy products and services. The Company and FirstEnergy have also agreed to have FE Holdings acquire Marbel Energy Corporation ("Marbel"), a privately-held, fully integrated natural gas company headquartered in Canton, Ohio. Marbel owns interests in more than 1,800 gas and oil wells and holds interests in more than 200,000 undeveloped acres in eastern and central Ohio. Marbel's subsidiaries include MB Operating Company, Inc., a natural gas exploration and production company, and Northeast Ohio Operating Companies, Inc. ("NOOC"), a public utility holding company based in Lancaster, Ohio. NOOC owns and operates over 1,300 miles of gas gathering lines and a local gas distribution company with more than 3,000 customers in eastern and central Ohio. The acquisition of Marbel will provide FE Holdings with a base of exploration, development and production capability, along with utility transportation and distribution capability. Marbel's net production in 1997 was approximately 6.3 Bcfe. At September 30, 1997, Marbel had estimated proved developed oil and gas reserves of 55.7 Bcfe. FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS The Company operates in two industry segments: (1) oil and gas production and distribution and (2) oilfield sales and service. Oilfield sales are generated by its wholly-owned subsidiary, Target Oilfield Pipe and Supply Company ("TOPS") and oilfield services are provided by its Arrow Oilfield Service division ("Arrow"). The financial information with respect to the industry segments is shown in Note 16 to the Consolidated Financial Statements. DESCRIPTION OF BUSINESS OVERVIEW The Company, founded in 1942, is actively engaged in the acquisition, exploration, development, production, gathering and marketing of oil and gas in the Appalachian, Michigan and Illinois Basins. The Company operates principally in the Appalachian and Michigan Basins where it is now one of the largest oil and gas companies in terms of reserves, acreage held and wells operated. It commenced operations in the Illinois Basin in September 1996. The Appalachian Basin is the oldest and geographically one of the largest oil and gas producing regions in the United States. Although the Appalachian Basin has sedimentary formations indicating the potential for oil and gas reservoirs to depths of 30,000 feet or more, oil and gas is currently produced primarily from shallow, highly developed blanket formations at depths of 1,000 to 5,500 feet. Drilling success rates of the Company and others drilling in these formations historically have exceeded 90% with production generally lasting longer than 20 years. The combination of long-lived production and high drilling success rates at these shallower depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the 3 5 Appalachian Basin. As of December 31, 1997, there were over 10,000 independent operators of record and approximately 180,000 producing oil and gas wells in Ohio, West Virginia, Pennsylvania and New York. There has been only limited testing or development of the formations below the existing shallow production in the Appalachian Basin. Fewer than 2,000 wells have been drilled to a depth greater than 7,500 feet, and fewer than 100 wells have been drilled to a depth greater than 12,500 feet in the entire Appalachian Basin. As a result, the Company believes that there are significant exploration and development opportunities in these less developed formations for those operators with the capital, technical expertise and ability to assemble the large acreage positions needed to justify the use of advanced exploration and production technologies. In January 1995, the Company purchased Ward Lake Drilling, Inc., a privately-held exploration and production company headquartered in Gaylord, Michigan, and commenced operations in the Michigan Basin. At the time of purchase, Ward Lake operated approximately 500 Antrim Shale gas wells in Michigan's lower peninsula. The Company's primary objective in acquiring Ward Lake was to allow the Company to pursue opportunities in the Michigan Basin with an established operating company that provided the critical mass to operate efficiently. Ward Lake currently operates approximately 600 wells in Michigan. In September 1996, the Company commenced operations in the Illinois Basin by acquiring a 100% working interest in 98 natural gas wells and an extensive gas gathering system in the Shrewsbury Field located in northwestern Kentucky. The Company's rationale for entering the Michigan and Illinois Basins was based on their geologic and operational similarities to the Appalachian Basin and their geographic proximity to the Company's operations in the Appalachian Basin. Geologically, the Michigan and Illinois Basins resemble the Appalachian Basin with shallow blanket formations and deeper formations with greater reserve potential. Operationally, economies of scale and cost containment are essential to operating profitability. The operating environment in each of these basins is also highly fragmented with substantial acquisition opportunities. Most of the Company's production in the Michigan Basin is derived from the shallow (700 to 1,700 feet) blanket Antrim Shale formation which has not been extensively developed. Success rates for companies drilling to this formation have exceeded 90%, with production often lasting as long as 20 years. The Michigan Basin also contains deeper formations with greater reserve potential. The Company has also established production from certain of these deeper formations through its drilling operations. The Michigan Basin has approximately 300 operators of record, most of which are private companies, and more than 8,000 producing wells. Because the production rate from Antrim Shale wells is relatively low, cost containment is a crucial aspect of operations. In contrast to the shallow, highly developed blanket formations in the Appalachian Basin, the operating environment in the Antrim Shale is more capital intensive because of the low natural reservoir pressures and the high initial water content of the formation. The Company's production in the Illinois Basin is primarily from the New Albany Shale formation, which is a stratigraphic equivalent of the Antrim Shale formation. The New Albany Shale has likewise not been widely developed. The New Albany Shale has similar operating characteristics to shale formations in the adjacent Appalachian and Michigan Basins from which the Company is currently producing. The proximity of the Appalachian and Michigan Basins to large commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices that since 1986 have ranged from $0.31 4 6 to $1.30 per Mcf (thousand cubic feet) above national wellhead prices. The Company's average wellhead gas price in 1997 was $0.42 per Mcf above the estimated average national wellhead price. BUSINESS STRATEGY The Company seeks to increase reserves, production and cash flow through a balanced program of exploration and development drilling and strategic acquisitions. The key elements of the Company's strategy are as follows: - - MAINTAIN A BALANCED DRILLING PROGRAM. It is the Company's intention to expand production and reserves through a balanced program of developmental and exploratory drilling. The Company believes that there are significant exploration and development opportunities in the less developed or deeper formations in the Appalachian and Michigan Basins and has identified numerous development and exploratory drilling locations in the deeper formations of the Appalachian and Michigan Basins. The Company's drilling budget in 1998 is approximately $38 million, which will fund the drilling of approximately 274 wells. - - UTILIZE ADVANCED TECHNOLOGY. The combination of long-lived production and high drilling success rates at the shallow depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the Appalachian Basin. The Company has been applying more advanced technology, including 3-D seismic, horizontal drilling, advanced fracturing techniques and enhanced oil recovery methods. The Company is implementing these techniques to improve drilling success rates, the size of average discovery, production rates, reserve recovery rates and total economics in its operating areas. - - PURSUE CONSOLIDATION OPPORTUNITIES. There is a continuing trend toward consolidation in the energy industry in general. The basins in which the Company operates are highly fragmented. The Company believes this provides the basis for significant acquisition opportunities as capital constrained operators, the majority of which are privately held, seek liquidity or operating capital. The Company intends to capitalize on its geographic knowledge, technical expertise, low cost structure and decentralized organization to pursue additional strategic acquisitions in its area of operations. The Company's acquisition strategy focuses on acquiring producing properties that: (i) are properties in which the Company already owns an interest and operates or that are strategically located in relation to its existing operations, (ii) can be enhanced through operating cost reductions, advanced production technologies, mechanical improvements, recompleting or reworking wells and / or the use of enhanced and secondary recovery techniques, (iii) provide development and exploratory drilling opportunities or opportunities to improve the Company's acreage position, (iv) have the potential for increased revenues resulting from the Company's gas marketing capabilities, or (v) are of sufficient size to allow the Company to operate efficiently in new areas. - - EXPAND GAS GATHERING AND MARKETING. The Company's extensive gas gathering systems and regional natural gas marketing operation are integral to the Company's low cost structure and high revenues per unit of gas production. It is the Company's intention to expand its gas gathering systems to further improve the rate of return on the Company's drilling and development activities. The Company has excellent relationships with a large number of utilities and industrial end users located within the Company's operating areas. The Company's gas marketing operation provides a ready market for increased production, allowing the Company to shift sales from third-party gas to its own production. See: RECENT DEVELOPMENTS and SUBSEQUENT EVENTS. 5 7 ACQUISITION OF PRODUCING PROPERTIES The Company employs a disciplined approach to acquisition analysis that requires input and approval from all key areas of the Company. These areas include field operations, exploration and production, finance, gas marketing, land management and environmental compliance. Although the Company often reviews in excess of 50 acquisition opportunities per year, this disciplined approach can result in uneven annual spending on acquisitions. The following table sets forth information pertaining to acquisitions completed during the period 1992 through 1997.
Proved Developed Reserves (2) ------------------------------------------------- Number of Purchase Oil Gas Combined Period Transactions Price (1) (Mbbl) (Mmcf) (Mmcfe) ----------- --------------- --------------------- ----------- ----------- -------------- (in thousands) 1992 5 $ 23,733 466 41,477 44,273 1993 8 3,883 119 4,121 4,835 1994 11 20,274 223 26,877 28,215 1995 6 77,388 1,850 97,314 108,414 1996 3 4,103 205 6,000 7,230 1997 10 21,295 101 32,800 33,406 --------------- --------------------- ----------- ----------- -------------- Total 43 $ 150,676 2,964 208,589 226,373 =============== ===================== =========== =========== ============== - ------------
(1) Represents the portion of the purchase price allocated to proved developed reserves. (2) Mbbl - thousand barrels Mmcf - million Mmcfe - million cubic cubic feet feet equivalent During 1997, the Company acquired for approximately $21.3 million working interests in 2,365 oil and gas wells in Ohio, Pennsylvania, Michigan and West Virginia. Estimated proved developed reserves associated with the wells total 32.8 Bcf of natural gas and 101,000 Bbls of oil net to the Company's interest at the time of the acquisitions. OIL AND GAS OPERATIONS AND PRODUCTION Operations. The Company serves as the operator of substantially all of the wells in which it holds working interests. The Company seeks to maximize the value of its properties through operating efficiencies associated with economies of scale and through operating cost reductions, advanced production technology, mechanical improvements and/or the use of enhanced and secondary recovery techniques. Through its production field offices in Ohio, West Virginia, Pennsylvania, New York, Michigan and Kentucky, the Company continuously reviews its properties, especially recently acquired properties, to determine what action can be taken to reduce operating costs and/or improve production. The Company has reduced field level costs through improved operating practices such as computerized production scheduling and the use of hand-held computers to gather field data. On acquired properties, further efficiencies may be realized through improvements in production scheduling and reductions in oilfield labor. Actions that may be taken to improve production include modifying surface facilities and redesigning downhole equipment. 6 8 The Company may also implement enhanced and secondary recovery techniques. Secondary recovery methods typically involve all methods of oil extraction in which extrinsic energy sources are applied to extract additional reserves. The principal secondary recovery technique used by the Company is waterflooding, which the Company has used in Ohio and Pennsylvania. Production. The following table sets forth certain information regarding oil and gas production from the Company's properties:
YEAR ENDED DECEMBER 31 ----------------------------------------------------------- 1993 1994 1995 1996 1997 ---------- --------- ---------- ---------- ---------- Production: Oil (thousands of Bbls) 453 496 556 719 753 Gas (Bcf) 7.4 9.6 17.0 25.4 27.2 Average sales price: Oil (per Bbl) $ 17.15 $ 15.98 $ 16.78 $ 20.24 $18.10 Gas (per Mcf) 2.55 2.58 2.21 2.56 2.65 Average production costs per Mcfe (including production taxes) 0.71 0.73 0.68 0.72 0.78 Total oil and gas revenues (in thousands) 26,631 32,574 46,853 79,491 85,756 Total production expenses (in thousands) 7,119 9,184 13,816 21,266 24,668
EXPLORATION AND DEVELOPMENT The Company's exploration and development activities include development drilling in the highly developed or blanket formations and development and exploratory drilling in the less developed formations of the Appalachian, Michigan and Illinois Basins. The Company's strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. The Company has an extensive inventory of acreage on which to conduct its exploration and development activities. In 1997, the Company drilled 194 gross (162.8 net) wells to highly developed or shallow blanket formations in its six state operating area at a direct cost of approximately $31.2 million for the net wells. The Company also drilled 67 gross (36.8 net) wells to less developed and deeper formations in 1997 at a direct cost of approximately $9.3 million for the net wells. The result of this drilling activity is shown in the tables on page 11. The Company believes that its diversified portfolio approach to its drilling activities results in more consistent and predictable economic results than might be experienced with a less diversified or higher risk drilling program profile. Highly Developed Formations. In general, the highly developed or blanket formations found in the Appalachian, Michigan and Illinois Basins are widespread in extent and hydrocarbon accumulations are 7 9 not dependent upon local stratigraphic or structural trapping. Drilling success rates exceed 90%. The principal risk of such wells is uneconomic recoverable reserves. The highly developed formations in the Appalachian Basin are relatively tight reservoirs that produce 20% to 30% of their recoverable reserves in the first year and 40% to 50% of their total recoverable reserves in the first three years, with steady declines in subsequent years. Average well lives range from 15 years to 25 years or more. The Antrim Shale formation, the principal shallow blanket formation in the Michigan Basin, is characterized by high formation water production in the early years of a well's productive life, with water production decreasing over time. Antrim Shale wells typically produce at rates of 100 Mcf to 125 Mcf per day for several years, with modest declines thereafter. Gas production often increases in the early years as the producing formation becomes less water saturated. Average well lives are 20 years or more. In the Illinois Basin, the highly developed or shallow blanket formations include the New Albany Shale formation as well as the Mississippian sandstones. Production characteristics of the New Albany Shale are very similar to the Devonian Shale from which the Company produces in West Virginia. Certain typical characteristics of the highly developed or blanket formations drilled by the Company in 1997 are described below:
Range of Range of Average Drilling Average Gross Range of and Completion Reserves Well Depths Costs per Well per Well --------------------- ---------------------- --------------------- (in feet) (in thousands) (in Mmcfe) Ohio 1,200-5,500 $ 65-140 80-150 West Virginia 1,300-6,000 100-220 150-500 Pennsylvania: Coalbed Methane 900-1,800 75-100 180-250 Clarendon 1,100-2,000 35-45 30-50 Medina 5,000-6,200 150-200 180-300 New York 3,000-5,000 100-150 75-300 Michigan 1,000-1,200 200-250 400-600 Kentucky 1,200-1,800 90-120 125-250
The Company plans to drill approximately 208 wells to highly developed or blanket formations in 1998. Less Developed Formations. The Appalachian Basin has productive and potentially productive sedimentary formations to depths of 30,000 feet or more, but the combination of long-lived production and high drilling success rates in the shallow formations has curbed the development of the deeper formations in the basin. The Company believes it possesses the technological expertise and the acreage position needed to explore the deeper formations in a cost effective manner. 8 10 The less developed formations in the Appalachian Basin include the Knox sequence of sandstones and dolomites which includes the Rose Run, Beekmantown and Trempeleau productive zones, at depths ranging from 2,500 feet to 8,000 feet. The geographical boundaries of the Knox sequence, which lies approximately 2,000 feet below the highly developed Clinton Sandstone, are generally well defined in Ohio with less definition in New York and Pennsylvania. Nevertheless, the Knox group has been only lightly explored, with fewer than 2,000 wells drilled to this sequence of formations during the past 10 years. The Company began testing the Knox sequence in 1989 by selecting certain wells that were targeted to be completed to the Clinton formation and drilling them an additional 2,000 feet to 2,500 feet to test the Knox formations. In 1991, the Company began using seismic analysis and other geophysical tools to select drilling locations specifically targeting the Knox formations. Since 1991, the Company has added substantially to its technical staff to enhance its ability to develop drilling prospects in the Knox and other less developed formations in the Appalachian Basin and the deeper formations in the Michigan Basin. The following table shows the Company's drilling results in the Knox sequence:
Drilling Results in the Knox Formations -------------------------------------------------------------------------------------- Average Gross Reserves per Wells Drilled Wells Completed (1) Completed Well ---------------------- ----------------------- Period Gross Net Gross Net (Mmcfe) ----------------- -------- -------- -------- ------- --------------------- 1989-1990 18 14.5 5 4.0 456 1991 11 10.3 5 4.7 170 1992 15 12.5 8 6.4 285 1993 30 20.2 16 8.8 360 1994 25 14.2 17 9.8 389 1995 34 16.3 18 8.8 343 1996 38 22.0 25 15.5 422 1997 54 26.6 30 16.4 450 - ------------
(1) Completed as producing wells in the Knox formations. The Company's historical experience is that the average Knox well produces 20% to 25% of its recoverable reserves in the first year of production and approximately 50% of its recoverable reserves in the first three years with a steady decline thereafter. Wells in the Knox formations have an expected productive life ranging from 10 to 25 years. 9 11 As shown in the following table, the Company's production from Knox formation wells has increased steadily as additional wells have been drilled.
PRODUCING WELLS AND PRODUCTION FROM KNOX FORMATIONS -------------------------------------------------------------------- 1993 1994 1995 1996 1997 ---------- ----------- ------------- ------------ ------------ Number of wells in production: Gross 23 41 66 82 112 Net 20.6 29.7 41.5 58.9 75.6 Percent of total net wells 0.7 % 0.8 % 0.7 % 0.9 % 1.0 % Annual production (net): Oil (Mbbl) 13.9 67.1 74.9 78.2 111.2 Gas (Mmcf) 731 1,041 1,624 2,788 3,600 Combined (Mmcfe) 814 1,444 2,074 3,257 4,267 Percent of total combined production 8 % 11 % 10 % 11 % 13 %
Productive Knox wells represented approximately 1% of the Company's total productive wells at December 31, 1997. Production from Knox wells in 1997, however, equaled 13% of the Company's total production on an Mcfe basis. The Company is well positioned to exploit the undeveloped potential of the Knox formations in the future. At December 31, 1997, it held leases on approximately 598,000 net acres overlying potential Knox drilling locations. The Company plans to drill or participate in joint ventures to drill 48 gross (28.2 net) wells to the Knox formations in 1998. In addition, the Company has also tested the Niagaran Carbonate, Dundee Carbonate, Onondaga Limestone, Oriskany Sandstone and Newburg Sandstone formations. The Company plans to drill approximately 18 gross (16 net) wells to these formations in 1998. Certain typical characteristics of the less developed or deeper formations drilled by the Company in 1997 are described below:
Average Drilling Costs Average -------------------------- Gross Range of Dry Completed Reserves Formation Location Well Depths Hole Well per Well -------------------------- ------------ ---------------- -------- --------------- --------------- (in feet) (in thousands) (in Mmcfe) Knox formations OH, NY 2,500-8,000 $130 $240 450 Niagaran Carbonate MI 4,500-5,500 275 525 1,200 Dundee Carbonate MI 3,000-3,500 330 500 750 Onondaga Limestone PA 4,000-5,500 100 190 400 Oriskany Sandstone PA, NY 4,500-7,000 150 225 500 Newburg Sandstone WV 5,500-6,000 175 275 1,000
10 12 Drilling Results. The following table sets forth drilling results with respect to wells drilled during the past five years:
HIGHLY DEVELOPED OR BLANKET FORMATIONS (1) LESS DEVELOPED OR DEEPER FORMATIONS (2) -------------------------------------------- ------------------------------------------ 1993 1994 1995 1996 1997 1993 1994 1995 1996 1997 ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Productive: Gross 42 58 106 153 187 16(3) 22(4) 23(5) 34 39(6) Net 31.4 45.6 92.5 126.3 156.5 8.8 12.7 11.5 22.2 24.5 Dry: Gross 2 2 4 2 7 14 10 22 18 28 Net 0.7 0.4 3.2 2.0 6.3 11.4 4.8 10.7 10.2 12.3 Reserves discovered- net (Mmcfe) 3,019 4,813 18,474 32,664 32,840 3,173 5,196 5,194 7,740 9,017 Approximate cost (in thousands) $4,847 $5,762 $15,079 $22,198 $31,242 $3,413 $5,509 $5,284 $9,029 $9,277
(1) Consists of wells drilled to the Berea and Clinton Sandstone formations in Ohio, the Berea Sandstone, Devonian Brown Shale, Ravencliff Sandstone and Big Lime Limestone formations in West Virginia, the Clarendon, Upper Devonian, Coalbed Methane and Medina formations in Pennsylvania, the Medina Sandstone formation in New York and the New Albany Shale formation in Kentucky and the Antrim Shale formation in Michigan. (2) Consists of wells drilled to the Trenton Limestone and Knox formations in Ohio, the Niagaran and Dundee Carbonates in Michigan and the Oriskany Sandstone and Onondaga Limestone formations in Pennsylvania and the Oriskany Sandstone, Onondaga Limestone and Knox formations in New York. (3) Two additional wells which were dry in the Knox formations were subsequently completed in the shallower Clinton formation. (4) One additional well which was dry in the Knox formations was subsequently completed in the shallower Clinton formation. (5) Two additional wells which were dry in the Knox formations were subsequently completed in the shallower Clinton formation. One additional well which was dry in the Oriskany formation was subsequently completed in the shallower Berea/Shale formations. (6) Three additional wells which were dry in the Knox formations were subsequently completed in shallower formations. GAS GATHERING AND MARKETING Gas Gathering. The Company operates approximately 3,000 miles of natural gas gathering lines in Ohio, West Virginia, Pennsylvania, New York, Michigan and Kentucky which are tied directly to various interstate natural gas transmission systems. The interconnections with these interstate pipelines afford the Company potential marketing access to numerous major gas markets. The Company earned gathering revenues of $6.7 million in 1997. Direct costs associated with gas gathering in 1997 totaled approximately $1.7 million. Gas Marketing. The major industrial centers of Akron, Buffalo, Canton, Chicago, Cleveland, Detroit and Pittsburgh are all located in close proximity to the Company's operations and provide a large potential market for direct natural gas sales. At present, the Company markets directly to approximately 225 customers in a six-state area. The Company focuses its gas marketing efforts on small to mid-sized industrial customers that require more service and have the potential to generate higher margins per Mcf than large industrial users. 11 13 The Company sells the gas it produces to its commercial and industrial customers, local distribution companies and on the spot market. In addition to its own production, the Company buys gas from other producers and third parties and resells it. At December 31, 1997, the Company marketed approximately 141 Mmcf of gas per day of which approximately 53% consisted of its own production. Gas sold by the Company to end users and local distribution companies is usually sold pursuant to contracts which extend for periods of one or more years at either fixed prices or market sensitive prices. Gas sold on the spot market is generally priced on the basis of a regional index. Since late 1995, the Company has attempted to maintain a balance between gas volumes sold under fixed price contracts and volumes sold under market sensitive contracts. At December 31, 1997, approximately 50% of the gas marketed by the Company was at fixed prices and 50% was at market sensitive prices. This contract strategy is intended to reduce price volatility and place a partial floor under the price received while still maintaining the potential for gains from upward movement in market sensitive prices. The Company has a policy which governs its ability to trade in the financial futures markets. The Company may, from time to time, partially hedge its physical gas sales prices by selling futures contracts on the New York Merchantile Exchange ("NYMEX") or by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. At December 31, 1997, the Company had 310 open futures contracts covering 1998, at an average price of $2.37 per Mcf. To offset these hedges, the Company has contracted for the physical delivery of gas into various pipelines in its producing areas at a NYMEX price plus a fixed basis. On February 6, 1998 the Company entered into an identical arrangement as above for 144 futures contracts covering June 1998 through May 1999, at an average NYMEX price of $2.44. The following table shows the type of buyer for gas marketed by the Company at December 31, 1997:
Marketed Gas ------------------------- Mmcf per Percent Purchaser Day of Total --------------------------------- ----------- ----------- End users 59.2 42% Local distribution companies 53.6 38% Spot markets 28.2 20% ----------- ----------- Total 141.0 100% =========== ===========
OILFIELD SALES AND SERVICE The Company has provided its own oilfield services for more than 30 years in order to assure quality control and operational and administrative support to its exploration and production operations. In 1992, Arrow Oilfield Service Company, a separate service division, was organized. Arrow provides the Company and third party customers with necessary oilfield services such as well workovers, well completions, brine hauling and disposal and oil trucking. Arrow is currently the largest oilfield service company in Ohio. In 1997, approximately 54% of Arrow's revenues were generated by sales to third parties. Target Oilfield Pipe & Supply Company, a wholly-owned subsidiary of the Company, operates retail sales outlets in the Appalachian and Michigan Basins from which it sells a broad range of equipment, including pipe, tanks, fittings, valves and pumping units. The Company originally entered the oilfield 12 14 supply business to ensure the quality and availability of supplies for its own operations. In 1997, approximately 70% of TOPS' revenues were generated by sales to third parties. The Company plans to expand its oilfield sales and service business through continued growth in its six-state market area. EMPLOYEES As of February 27, 1998, the Company had 625 full-time employees, including 220 oilfield sales and service employees, 321 oil and gas production employees, 19 petroleum engineers, 9 geologists and 3 geophysicists. COMPETITION AND CUSTOMERS The oil and gas industry is highly competitive. Competition is particularly intense with respect to the acquisition of producing properties and the sale of oil and gas production. There is competition among oil and gas producers as well as with other industries in supplying energy and fuel to users. The competitors of the Company in oil and gas exploration, development, production and marketing include major integrated oil and gas companies as well as numerous independent oil and gas companies, individual proprietors, natural gas pipelines and their affiliates and natural gas marketers and brokers. Many of these competitors possess and employ financial and personnel resources substantially in excess of those available to the Company. Such competitors may be able to pay more for desirable prospects or producing properties and to evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources of the Company will permit. The ability of the Company to add to its reserves in the future will be dependent on its ability to exploit its current developed and undeveloped lease holdings and its ability to select and acquire suitable producing properties and prospects for future exploration and development. During the years ended December 31, 1996 and 1997 there was no customer which accounted for 10% or more of the Company's consolidated revenues. The only customer which accounted for 10% or more of the Company's consolidated revenues during the year ended December 31, 1995 was The East Ohio Gas Company with purchases of $11.1 million. REGULATION Regulation of Production. In all states in which the Company is engaged in oil and gas exploration and production, its activities are subject to regulation. Such regulations may extend to requiring drilling permits, spacing of wells, the prevention of waste and pollution, the conservation of natural gas and oil, and other matters. Such regulations may impose restrictions on the production of natural gas and oil by reducing the rate of flow from individual wells below their actual capacity to produce which could adversely affect the amount or timing of the Company's revenues from such wells. Moreover, future changes in local, state or federal laws and regulations could adversely affect the operations of the Company. Environmental Regulation. The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the 13 15 environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from the Company's operations. Management believes the Company is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company. Regulation of Sales and Transportation. The Federal Energy Regulatory Commission (the "FERC") regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). In the past, the federal government has regulated the prices at which oil and gas could be sold. Currently, sales by producers of natural gas and all sales of crude oil and condensate in natural gas liquids can be made at uncontrolled market prices. ITEM 2. PROPERTIES ---------- OIL AND GAS RESERVES The following table sets forth the Company's proved oil and gas reserves as of December 31, 1995, 1996 and 1997 determined in accordance with the rules and regulations of the Securities and Exchange Commission. Proved reserves are the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
December 31 --------------------------------------- 1995 1996 1997 ----------- ----------- ----------- Estimated proved reserves Gas (Bcf) 239.4 288.6 291.6 Oil (thousands of barrels) 6,283 7,389 5,552
See Note 15 to the Consolidated Financial Statements for more detailed information regarding the Company's oil and gas reserves. The following table sets forth the estimated future net cash flows from the proved reserves of the Company and the present value of such future net cash flows as of December 31, 1997 determined in accordance with the rules and regulations of the Securities and Exchange Commission. 14 16 Estimated future net cash flows (before income taxes) (in thousands) attributable to estimated production during [S] [C] 1998 $ 51,955 1999 56,954 2000 52,408 2001 and thereafter 359,982 ----------------- Total $ 521,299 ================= Present value before income taxes (discounted at 10% per annum) $ 292,591 ================= Present value after income taxes (discounted at 10% per annum) $ 219,720 ================= Estimated future net cash flows represent estimated future gross revenues from the production and sale of proved reserves, net of estimated production costs (including production taxes, ad valorem taxes, operating costs and development costs). Estimated future net cash flows were calculated on the basis of prices and costs estimated to be in effect at December 31, 1997 without escalation, except where changes in prices were fixed and readily determinable under existing contracts. The weighted average prices for oil and gas at December 31, 1997 were $14.59 per barrel and $2.73 per Mcf, respectively. PRODUCING WELL DATA The following table summarizes by state the Company's productive wells at December 31, 1997:
December 31, 1997 ------------------------------------------------------------------------------------- Oil Wells Gas Wells Total ---------------------- ----------------------- ----------------------- State Gross Net Gross Net Gross Net ------------------------ --------- -------- --------- --------- --------- --------- Ohio 2,067 1,913 1,642 1,473 3,709 3,386 West Virginia 381 378 1,276 1,289 1,657 1,667 Pennsylvania 318 314 656 519 974 833 New York 7 7 1,018 998 1,025 1,005 Michigan 7 3 595 235 602 238 Kentucky -- -- 103 103 103 103 --------- -------- --------- --------- --------- --------- 2,780 2,615 5,290 4,617 8,070 7,232 ========= ======== ========= ========= ========= =========
15 17 ACREAGE DATA The following table summarizes by state the Company's gross and net developed and undeveloped leasehold acreage at December 31, 1997:
December 31, 1997 ------------------------------------------------------------------------------------ Developed Acreage Undeveloped Acreage Total Acreage ------------------------ ------------------------- ---------------------------- State Gross Net Gross Net Gross Net ----------------- ---------- ---------- ------------ ---------- ------------ ------------- Ohio 318,695 286,544 228,148 190,101 546,843 476,645 West Virginia 80,236 74,013 135,151 81,245 215,387 155,258 Pennsylvania 58,880 46,418 180,353 174,015 239,233 220,433 New York 130,844 118,054 39,163 36,827 170,007 154,881 Michigan 24,538 24,255 37,725 33,593 62,263 57,848 Kentucky 11,583 11,583 4,910 4,910 16,493 16,493 ---------- ---------- ------------ ---------- ------------ ------------- 624,776 560,867 625,450 520,691 1,250,226 1,081,558 ========== ========== ============ ========== ============ =============
Item 3. LEGAL PROCEEDINGS The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on the Company's financial position or the results of operations. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. PART II Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS There is no established public trading market for the Company's equity securities. The number of record holders of the Company's equity securities at February 28, 1998 was as follows: Number of Title of Class Record Holders --------------------------------------- -------------------- Common Stock 7 DIVIDENDS 16 18 No dividends have been paid on the Company's Common Stock. Item 6. SELECTED FINANCIAL DATA
BELDEN & BLAKE CORPORATION | SUCCESSOR PREDECESSOR COMPANY | COMPANY ------------------------------------------------------------------- | ------------- SIX MONTHS | SIX MONTHS ENDED | ENDED AS OF OR FOR THE YEAR ENDED DECEMBER 31, JUNE 30, | DECEMBER 31, --------------------------------------------------- | (IN THOUSANDS) 1993 1994 1995 1996 1997 | 1997 ---------- ---------- ---------- ---------- ----------- | ------------- | OPERATIONS: | Revenues $ 72,874 $ 79,365 $110,067 $153,235 $79,397 | $84,126 Depreciation, | depletion | and amortization 9,693 11,886 19,717 29,752 15,366 | 31,694 Income (loss) from | continuing | operations 3,265 4,180 6,260 15,194 (9,873) | (11,372) Preferred dividends | paid 180 180 180 180 45 | -- | BALANCE SHEET DATA: | AS OF | 12/31/97 | ------------- Working capital 28,850 13,612 17,359 22,110 | 19,846 Oil and gas | properties and | gathering systems, | net 86,192 106,710 216,848 222,127 | 491,183 Total assets 135,174 148,173 297,298 303,763 | 599,320 | Long-term liabilities, | less current portion 43,516 47,858 110,523 97,642 | 355,649 | Preferred stock 2,400 2,400 2,400 2,400 | -- | Total shareholders' | equity 76,857 81,142 142,291 158,918 | 96,858
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS As disclosed in the accompanying notes to consolidated financial statements, on March 27, 1997 the Company entered into a merger agreement with TPG which resulted in all of the Company's common stock being acquired by TPG and certain other investors on June 27, 1997 in a transaction accounted for as a purchase. For financial reporting purposes, the merger is considered effective June 30, 1997 and the operations of the Company prior to July 1, 1997 are classified as predecessor company operations. The consolidated balance sheet at December 31, 1997 includes the application of purchase accounting to measure the Company's assets and liabilities at fair value and is not comparable to the historical balance sheet as of December 31, 1996. Debt incurred to finance the acquisition and related transaction costs are reflected in the December 31, 1997 financial statements. A vertical black line is shown in the financial statements to separate the results of operations of the predecessor and successor companies. The allocation of the purchase price at fair value resulted in a significant increase in the book value of the Company's assets. The increase in the book value of assets resulted in materially higher charges for depreciation, depletion and amortization in the second half of 1997. These higher charges are expected to continue in subsequent accounting periods. The Company incurred transaction costs associated with the acquisition by TPG of $16.8 million. These costs were expensed in the second quarter of 1997. As a result of the acquisition by TPG, the 17 19 Company is highly leveraged, resulting in materially higher interest charges in the second half of 1997. These higher interest charges are expected to continue in subsequent accounting periods. The Company's principal business is the acquisition, development and production of, and exploration for, oil and gas reserves, principally in Ohio, West Virginia, Pennsylvania, Michigan, New York and Kentucky, and the gathering and marketing of natural gas. The Company utilizes the "successful efforts" method of accounting for its oil and gas properties. Under this method, property acquisition and development costs and productive exploration costs are capitalized while non-productive exploration costs, which include dry holes, expired leases and delay rentals, are expensed as incurred. Capitalized costs related to proved properties are depleted using the unit-of-production method. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized. The Company's gas gathering and marketing operations consist of purchasing gas at the wellhead and from interstate pipelines and selling gas to industrial customers and local gas distribution companies. The Company provides oilfield sales and services to its own operations and to third parties. Oilfield sales and service provided to the Company's own operations are provided at cost and all intercompany revenues and expenses are eliminated in consolidation. 18 20 RESULTS OF OPERATIONS As a result of the merger with TPG, the results of operations for the periods subsequent to June 30, 1997 are not necessarily comparable to those prior to July 1, 1997. The following table combines the six-month predecessor company period ended June 30, 1997 with the six-month successor company period ended December 31, 1997 for purposes of the discussion of year-end results (dollars are stated in thousands and as a percentage of revenue).
YEAR ENDED DECEMBER 31 ----------------------------------------------------------- 1997 1996 1995 ------------------ ------------------- ------------------- REVENUES Oil and gas sales $ 85,756 52.4% $ 79,491 51.9% $ 46,853 42.6% Gas marketing and gathering 44,371 27.1 44,527 29.0 40,436 36.7 Oilfield sales and service 30,206 18.5 25,517 16.7 20,066 18.2 Interest and other 3,190 2.0 3,700 2.4 2,712 2.5 ------------------ ------------------- ------------------- 163,523 100.0 153,235 100.0 110,067 100.0 EXPENSES Production expense 21,496 13.2 18,098 11.8 11,756 10.7 Production taxes 3,172 1.9 3,168 2.1 2,060 1.9 Cost of gas and gathering expense 37,784 23.1 37,556 24.5 33,831 30.7 Oilfield sales and service 28,021 17.1 23,142 15.1 18,266 16.6 Exploration expense 10,360 6.3 6,064 4.0 4,924 4.5 General and administrative expense 4,258 2.6 4,573 3.0 3,802 3.4 Depreciation, depletion and amortization 47,060 28.8 29,752 19.4 19,717 17.9 Franchise, property and other taxes 1,875 1.2 1,739 1.1 1,228 1.1 ------------------ ------------------- ------------------- 154,026 94.2 124,092 81.0 95,584 86.8 ------------------ ------------------- ------------------- OPERATING INCOME 9,497 5.8 29,143 19.0 14,483 13.2 Interest expense 19,132 11.7 7,383 4.8 6,073 5.5 Transaction-related expenses 16,758 10.3 ------------------ ------------------- ------------------- 35,890 22.0 7,383 4.8 6,073 5.5 ------------------ ------------------- ------------------- (LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES (26,393) (16.2) 21,760 14.2 8,410 7.7 (Benefit) provision for income taxes (5,148) (3.2) 6,566 4.3 2,150 2.0 ------------------ ------------------- ------------------- (LOSS) INCOME FROM CONTINUING OPERATIONS (21,245) (13.0) 15,194 9.9 6,260 5.7 LOSS FROM DISCONTINUED OPERATIONS (439) (0.3) (1,139) (1.0) ------------------ ------------------- ------------------- NET (LOSS) INCOME $ (21,245) (13.0)% $ 14,755 9.6% $ 5,121 4.7% ================== =================== =================== EBITDAX $ 66,917 40.9% $ 64,959 42.4% $ 39,124 35.5%
1997 COMPARED TO 1996 Operating income decreased $19.6 million (67%) from $29.1 million in 1996 to $9.5 million in 1997. The operating income from the oil and gas operations segment decreased $18.9 million (76%) from $24.8 million in 1996 to $5.9 million in 1997. The operating income from the oilfield sales and service segment decreased $462,000 from $963,000 in 1996 to $501,000 in 1997. The decrease in operating income was due primarily to an $17.3 million increase in depreciation, depletion and amortization expense from significant increases in the book value of property, equipment and other assets as a result of the purchase accounting associated with the merger discussed above. Income from continuing operations decreased $36.4 million from income of $15.2 million in 1996 to a loss of $21.2 million in 1997. This decrease was the result of $16.8 million of transaction-related expenses, the $17.3 million increase in depreciation, depletion and amortization expense and an increase of $11.7 million in interest expense offset by a decrease in the provision for income taxes of $11.7 million. This decrease in the provision for income taxes was primarily due to the decrease in income from 19 21 continuing operations before income taxes combined with a change in the effective tax rate due to the nondeductibility of certain transaction-related expenses and a decrease in the utilization of nonconventional fuel source tax credits in 1997. Earnings before interest, income taxes, depreciation, depletion and amortization and exploration expense ("EBITDAX") was $66.9 million in 1997 compared to $65.0 million in 1996. Total revenues increased $10.3 million (7%) in 1997 compared to the same period of 1996. Gross operating margins in 1997 were consistent when compared to the same period in 1996. Oil volumes increased 34,000 Bbls (5%) from 719,000 Bbls in 1996 to 753,000 Bbls in 1997 resulting in an increase in oil sales of approximately $700,000. Gas volumes increased 1.8 Bcf (7%) from 25.4 Bcf in 1996 to 27.2 Bcf in 1997 resulting in an increase in gas sales of approximately $4.6 million. These volume increases were primarily due to production from properties acquired and wells drilled in 1996 and 1997. The average price paid for the Company's oil decreased from $20.24 per barrel in 1996 to $18.10 per barrel in 1997 which decreased oil sales by approximately $1.6 million. The average price paid for the Company's natural gas increased $.09 per Mcf to $2.65 per Mcf in 1997 compared to 1996 which increased gas sales in 1997 by approximately $2.4 million. Production expense increased $3.4 million (19%) from $18.1 million in 1996 to $21.5 million in 1997. The average production cost increased from $.61 per Mcfe in 1996 to $.68 per Mcfe in 1997. These increases were due to an anticipated steep decline in production volumes from certain high volume wells with low production costs coupled with a reduction in operating fees received from third parties primarily due to the purchase of certain third party working interests by the Company. Such fees are recorded as a reduction of production expense. Production taxes were consistent at $3.2 million in 1997 and 1996. Depreciation, depletion and amortization increased by $17.3 million (58%) from $29.8 million in 1996 to $47.1 million in 1997. Depletion expense increased $15.5 million (68%) from $23.0 million in 1996 to $38.5 million in 1997. Depletion per Mcfe increased from $.77 per Mcfe in 1996 to $1.21 per Mcfe in 1997. These increases were primarily the result of significant increases in the book value of property, equipment and other assets as a result of the purchase accounting associated with the merger discussed above. Interest expense increased $11.7 million (159%) from $7.4 million in 1996 to $19.1 million in 1997. This increase was due to substantial additional debt incurred primarily to finance the merger. 1996 COMPARED TO 1995 Operating income increased $14.6 million (101%) from $14.5 million in 1995 to $29.1 million in 1996. The operating income from the oil and gas operations segment increased $12.4 million (99%) from $12.4 million in 1995 to $24.8 million in 1996. The operating income from the oilfield sales and service segment increased $290,000 (43%) from $673,000 in 1995 to $963,000 in 1996. The increase in operating income was due primarily to a $25.2 million increase in gross margin on oil and gas sales offset by a $10.0 million increase in depreciation, depletion and amortization expense. Income from continuing operations increased $8.9 million from $6.3 million in 1995 to $15.2 million in 1996. This increase was the result of the increases in operating income above offset by an 20 22 increase in the provision for income taxes of $4.4 million. This increase in the provision for income taxes was attributable to the increase in income from continuing operations before income taxes and an increase in the effective tax rate. The increase in the effective tax rate was primarily due to the decrease of nonconventional fuel source tax credits as a percentage of income from continuing operations. EBITDAX was $65.0 million in 1996 compared to $39.1 million in 1995. Total revenues increased $43.2 million (39%) in 1996 compared to 1995. Gross operating margins increased $26.1 million (63%) in 1996 when compared to 1995. The increase in operating income was due primarily to a $25.2 million increase in gross margin on oil and gas sales. Oil volumes increased 163,000 Bbls (29%) from 556,000 Bbls in 1995 to 719,000 Bbls in 1996 resulting in an increase in oil sales of approximately $2.7 million. Gas volumes increased 8.4 Bcf (50%) from 17.0 Bcf in 1995 to 25.4 Bcf in 1996 resulting in an increase in gas sales of approximately $18.7 million. These volume increases were primarily due to increased production from properties acquired in 1995 and wells drilled in 1995 and 1996. The average price paid for the Company's oil increased from $16.78 per barrel in 1995 to $20.24 per barrel in 1996 which increased oil sales by approximately $2.5 million. The average price paid for the Company's natural gas increased $.35 per Mcf to $2.56 per Mcf in 1996 compared to 1995 which increased gas sales in 1996 by approximately $8.9 million. Production expense increased $6.3 million (54%) from $11.8 million in 1995 to $18.1 million in 1996. The average production cost increased from $.58 per Mcfe in 1995 to $.61 per Mcfe in 1996. This increase was primarily due to the increased production volumes discussed above and a reduction in operating fees charged to third parties. Such fees are recorded as a reduction of production expense. Production taxes increased $1.1 million (54%) from $2.1 million in 1995 to $3.2 million in 1996. This increase was primarily due to the increased production volumes discussed above. Depreciation, depletion and amortization increased by $10.1 million (51%) from $19.7 million in 1995 to $29.8 million in 1996. Depletion expense increased $7.9 million (53%) from $15.1 million in 1995 to $23.0 million in 1996. This increase was primarily due to additional depletion expense associated with the increased production volumes discussed above. Depletion per Mcfe increased from $.74 per Mcfe in 1995 to $.77 per Mcfe in 1996. This increase was primarily the result of proved reserves added through acquisitions and drilling at a higher cost per Mcfe. Interest expense increased $1.3 million (22%) from $6.1 million in 1995 to $7.4 million in 1996. This increase was primarily due to higher average debt balances incurred to finance the 1995 acquisitions (Note 4 "Acquisitions"). LIQUIDITY AND CAPITAL RESOURCES The Company's liquidity and capital resources are closely related to and dependent on the current prices paid for its oil and gas. The Company's current ratio at December 31, 1997 was 1.51 to 1.00. During 1997, working capital decreased $2.3 million from $22.1 million to $19.8 million. The decrease was primarily due to an increase in accrued expenses of $7.5 million offset by an increase in accounts receivable and a decrease in the current portion of long-term debt. The Company's operating activities provided cash flows of $38.4 21 23 million in 1997. On June 27, 1997, the Company entered into a senior revolving credit agreement with several lenders. These lenders have committed, subject to compliance with the borrowing base, to provide the Company with revolving credit loans of up to $200 million, of which $25 million will be available for the issuance of letters of credit. The initial borrowing base has been set at $180 million. The borrowing base is determined based on the Company's oil and gas reserves and other assets and is subject to annual or semiannual adjustment. The Company borrowed $104 million under the new credit agreement to partially finance the acquisition of the Company by TPG, to repay certain existing outstanding indebtedness of the Company and to pay certain fees and expenses related to the transaction. The new credit agreement will mature on June 27, 2002. Outstanding balances under the agreement incur interest at the Company's choice of several indexed rates, the most favorable being 7.219% at December 31, 1997. The new credit agreement contains a number of covenants that, among other things, restrict the ability of the Company and its subsidiaries to dispose of assets, incur additional indebtedness, prepay other indebtedness or amend certain debt instruments, pay dividends, create liens on assets, enter into sale and leaseback transactions, make investments, loans or advances, make acquisitions, engage in mergers or consolidations, change the business conducted by the Company or its subsidiaries, make capital expenditures or engage in certain transactions with affiliates and otherwise restrict certain corporate activities. In addition, under the new credit agreement, the Company is required to maintain specified financial ratios and tests, including minimum interest coverage ratios and maximum leverage ratios. The Company issued $225 million of 9.875% Senior Subordinated Notes on June 27, 1997. The notes mature June 15, 2007. Interest will be payable semiannually on June 15 and December 15 of each year, commencing December 15, 1997. The notes are general unsecured obligations of the Company and are subordinated in right of payment to senior debt. Except as otherwise described below, the notes are not redeemable prior to June 15, 2002. Thereafter, the notes are subject to redemption at the option of the Company at specific redemption prices. Prior to June 15, 2000, the Company may, at its option, on any one or more occasions, redeem up to 40% of the original aggregate principal amount of the notes at a redemption price equal to 109.875% of the principal amount, plus accrued and unpaid interest, if any on the redemption date, with all or a portion of net proceeds of public sales of common stock of the Company; provided that at least 60% of the original aggregate principal amount of the notes remains outstanding immediately after the occurrence of such redemption; and provided, further, that such redemption shall occur within 60 days of the date of the closing of the related sale of common stock of the Company. Prior to June 15, 2002, the notes may be redeemed as a whole at the option of the Company upon the occurrence of a change in control. The indenture contains certain covenants that limit the ability of the Company and its subsidiaries to incur additional indebtedness and issue stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens, and engage in mergers and consolidations. On March 31, 1997, the Company redeemed all of the outstanding Class II Series A preferred stock for $2.4 million in cash. On April 3, 1997, the Company gave notice of redemption of all of the outstanding 9.25% convertible subordinated debentures for 104% of face value. Redemption of these debentures occurred 22 24 June 10, 1997 when holders of the debentures elected to convert them into 275,425 shares of predecessor common stock. On June 25, 1997, the Company redeemed all $35 million of its 7% fixed-rate senior notes. On June 27, 1997, the Company repaid all outstanding amounts due under the then existing revolving bank facility in the amount of $94.0 million. The Company currently expects to spend approximately $38 million during 1998 on its drilling activities and approximately $13 million for other capital expenditures. The Company's acquisition program may be financed with available cash flow, available revolving credit line, additional borrowings or additional equity. The level of the Company's cash flow in the future will depend on a number of factors including the demand and price levels for oil and gas, its ability to acquire additional producing properties and the scope and success of its drilling activities. The Company intends to finance such activities principally through its available cash flow and through additional borrowings under its new credit agreement. From time to time the Company may enter into interest rate swaps to hedge the interest rate exposure associated with the credit facility, whereby a portion of the Company's floating rate exposure would be exchanged for a fixed interest rate. During October 1997, the Company entered into two interest rate swap arrangements covering $90 million of debt. The Company swapped $40 million of floating three-month LIBOR +1.5% for a fixed rate of 7.485% for three years, extendible at the institution's option for an additional two years. The Company also swapped $50 million of floating three-month LIBOR +1.5% for a fixed rate of 7.649% for five years. INFLATION AND CHANGES IN PRICES During 1995, the price paid for the Company's crude oil increased from $15.50 per barrel to a high of $17.50 per barrel, then decreased to $16.50 per barrel at year-end, with an average price for the year of $16.78 per barrel. During 1996, the price paid for the Company's crude oil increased from a low of $16.50 per barrel at year-end 1995 to a high of $22.50 per barrel at year-end 1996, with an average price of $20.24 per barrel. During 1997, the price paid for the Company's crude oil increased from $22.50 per barrel at year-end 1996 to a high of $23.50 per barrel, then decreased to a low of $14.25 at year-end 1997, with an average price of $18.10 per barrel. The average price of the Company's natural gas increased from $2.21 per Mcf in 1995 to $2.56 per Mcf in 1996, then increased to $2.65 per Mcf in 1997. The price of oil and gas has a significant impact on the Company's results of operations. Oil and gas prices fluctuate based on market conditions and, accordingly, cannot be predicted. As a result of increased competition among drilling contractors and suppliers and continuing low levels of drilling activity in the Company's operating area, costs to drill, complete, and service wells have remained relatively constant in recent years. Historically, a large portion of the Company's natural gas sales has been under long-term fixed price contracts. As a result of recent acquisitions, certain natural gas sales are currently based on indexed prices. Many of these contracts contain "trigger" clauses which allow the Company to fix the price at which deliveries in future months will be sold at the NYMEX price for one or more future months. The Company may also, from time to time, enter into hedging transactions with financial institutions to reduce its exposure to variable commodity pricing. 23 25 READINESS FOR YEAR 2000 The Company has taken actions to understand the nature and extent of the work required to make its systems and operations Year 2000 compliant. The Company has prepared or is in the process of preparing its operations and its financial, information and other computer-based systems for the Year 2000, including the replacing or updating of its legacy systems. The Company will continue to evaluate the estimated costs associated with these actions compared with actual experience. While this may involve additional costs, the Company currently believes that it will manage the Year 2000 conversion without any material effect on its operations or results of operations. FORWARD-LOOKING INFORMATION The forward-looking statements regarding future operating and financial performance contained in this report involve risks and uncertainties that include, but are not limited to, the Company's future production and costs of operation, the market demand for, and prices of, oil and natural gas, results of the Company's future drilling and gas marketing activity, the uncertainties of reserve estimates, environmental risks, and other factors detailed in the Company's filings with the Securities and Exchange Commission. Actual results may differ materially from forward-looking statements made in this report. Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Index to Consolidated Financial Statements and Schedules on page F-1 sets forth the financial statements included in this Annual Report on Form 10-K and their location herein. Schedules have been omitted as not required or not applicable because the information required to be presented is included in the financial statements and related notes. The financial statements have been prepared by management in conformity with generally accepted accounting principles. Management is responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary to make informed estimates and judgments based on currently available information on the effects of certain events and transactions. The Company maintains accounting and other controls which management believes provide reasonable assurance that financial records are reliable, assets are safeguarded, and that transactions are properly recorded. However, limitations exist in any system of internal control based upon the recognition that the cost of the system should not exceed benefits derived. The Company's independent auditors, Ernst & Young LLP, are engaged to audit the financial statements and to express an opinion thereon. Their audit is conducted in accordance with generally accepted auditing standards to enable them to report whether the financial statements present fairly, in all material respects, the financial position and results of operations in accordance with generally accepted accounting principles. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 24 26 Executive officers and directors of the Company as of February 28, 1998 were as follows:
Name Age Position - ---- --- -------- Ronald L. Clements 55 Chief Executive Officer and Director Ronald E. Huff 42 President, Chief Financial Officer and Director Joseph M. Vitale 56 Senior Vice President Legal, General Counsel, Secretary and Director Tommy L. Knowles 47 Senior Vice President Exploration and Production Leo A. Schrider 59 Senior Vice President Technical Development Dennis D. Belden 52 Vice President Supply and Service Duane D. Clark 42 Vice President Gas Marketing James C. Ewing 55 Vice President Human Resources Charles P. Faber 56 Vice President Corporate Development Robert W. Peshek 43 Vice President Finance Dean A. Swift 45 Vice President, Assistant General Counsel and Assistant Secretary Henry S. Belden, IV 58 Director Lawrence W. Kellner 39 Director Max L. Mardick 63 Director William S. Price, III 42 Director Gareth Roberts 45 Director David M. Stanton 35 Director
All executive officers of the Company serve at the pleasure of its Board of Directors. None of the executive officers of the Company is related to any other executive officer or director, except that Henry S. Belden, IV and Dennis D. Belden are brothers. The Board of Directors consists of nine members each of whom is elected annually to serve one year terms. The business experience of each executive officer and director is summarized below. 25 27 RONALD L. CLEMENTS has been Chief Executive Officer and a Director of the Company since 1997. Previously he served as Senior Vice President of Exploration and Production and managed the Company's Exploration and Production Division from 1993 to 1997. He joined Belden & Blake in 1990 and served as Vice President of Producing Operations. He has more than 30 years of petroleum engineering and production experience. Prior to joining Belden & Blake he served as Vice President and District Manager of TXO Production Corporation in Corpus Christi, Texas. From 1967 to 1982, Mr. Clements held various operational management positions with Shell Oil Company. Mr. Clements received a BS degree in Electrical Engineering from the University of North Dakota and a MS degree in Petroleum Engineering from the University of Tulsa. He is a member of the Society of Petroleum Engineers and the Ohio Oil and Gas Association. RONALD E. HUFF has been President and Chief Financial Officer of the Company since 1997, having previously served as its Senior Vice President and Chief Financial Officer from 1989 to 1996 and Senior Controller from 1986 to 1989. Mr. Huff has been a director of Belden & Blake since 1991. He is a Certified Public Accountant with 20 years of experience in oil and gas finance and accounting. From 1983 to 1986, Mr. Huff served as Vice President and Chief Accounting Officer of Towner Petroleum Company. From 1980 to 1983 he worked for Sonat Exploration Company as Manager of Financial Accounting; and from 1977 to 1980 he served as Corporate Accounting Supervisor for Transco Companies, Incorporated. Mr. Huff received a BS degree in Accounting from the University of Wyoming. He is a member of the Ohio Petroleum Accountants Society and the Financial Executives Institute-Northeast Ohio Chapter. JOSEPH M. VITALE has been Senior Vice President Legal of the Company since 1989 and has served as its General Counsel since 1974. He has been a director of the Company since 1991. Prior to joining Belden & Blake, Mr. Vitale served for four years in the Army Judge Advocate General's Corps. He holds a BS degree from John Carroll University and a JD degree from Case Western Reserve Law School. He is a member of the Ohio Oil and Gas Association, the Stark County, Ohio State and American Bar Associations, and the Interstate Oil Compact Commission. Mr. Vitale is a past Chairman of the Natural Resources Law Committee of the Ohio State Bar Association. TOMMY L. KNOWLES has been Senior Vice President of Exploration and Production of the Company since 1997. Previously he served as Vice President of Production from 1996 to 1997. He has 25 years of petroleum engineering and production experience. Prior to joining Belden & Blake, Mr. Knowles served as President of FWA Drilling Company, a subsidiary of Texas Oil & Gas Corporation. From 1982 to 1988 he worked for TXO Production Corporation in Sacramento, California, serving in various management positions including Vice President; from 1979 to 1982 he held the position of Drilling and Production Manager for Texas Oil & Gas Corporation; and, from 1973 to 1979 he held various engineering, supervisory and management positions with Exxon Corporation. Mr. Knowles holds a BS degree in Mechanical Engineering from the University of Texas at Austin where he graduated with honors. He is a member of the Society of Petroleum Engineers, the American Petroleum Institute, and the Independent Association of Drilling Contractors. LEO A. SCHRIDER has been Senior Vice President of Technical Development since 1993. He previously served as Senior Vice President of Exploration, Drilling and Engineering for the Company since 1986. Mr. Schrider is a Petroleum Engineer with 35 years of experience in oil and gas production, principally in the Appalachian Basin. Prior to joining Belden & Blake in 1981, he served as Assistant and Deputy Director of Morgantown Energy Technology Center from 1976 to 1980. From 1973 to 1976, Mr. 26 28 Schrider served as Project Manager of the Laramie Energy Research Center. He has also held various research positions with the U.S. Department of Energy in Wyoming and West Virginia. Mr. Schrider received his BS degree from the University of Pittsburgh in 1961 and did graduate work at West Virginia University. He has published more than 35 technical papers on oil and gas production. He was an Adjunct Professor at West Virginia University and also served as a member of the International Board of Directors of the Society of Petroleum Engineers. In 1994, Mr. Schrider was elected to the Board of Directors of the Petroleum Technology Transfer Council and is chairman of the producer advisory group representing the Appalachian region. DENNIS D. BELDEN has served as Vice President of Supply and Service for the Company since 1989 and has managed the Oilfield Supply and Service Division since 1992. He joined Belden & Blake in 1980 and served as the Company's land manager from 1980 to 1989. From 1976 to 1980 he was employed by Wilmot Mining Company as Special Projects Manager; from 1974 to 1976 he was Treasurer and General Manager of Cabbages & Kings Restaurant of Ohio; and from 1972 to 1974 he was employed by T & M Fuel as General Supervisor. Mr. Belden attended Kent State University. He is a member of the Ohio Oil and Gas Association. DUANE D. CLARK has been Vice President of Gas Marketing for the Company since 1997. Previously, he served as General Manager of Gas Marketing from 1996 to 1997. He joined the Company in 1995 as a Gas Marketing Analyst. Prior to joining Belden & Blake, Mr. Clark held various management positions with Quaker State Corporation from 1978 to 1995. He has 20 years of experience in the oil and gas industry . Mr. Clark received his BA degree in Mathematics and Economics from Ohio Wesleyan University. His professional affiliations include the Ohio Oil and Gas Association, the Independent Oil and Gas Association of West Virginia and the Pennsylvania Oil and Gas Association. JAMES C. EWING has been Vice President of Human Resources for the Company since 1997. He previously served as Human Resources Manager. Mr. Ewing joined Belden & Blake in April of 1986 and has 12 years of experience in the oil and gas industry and more than 20 years of experience in the Human Resource field. Prior to joining Belden & Blake, he was the Director of Personnel for the Union Metal Manufacturing Company from 1978 to 1986. Mr. Ewing holds a Bachelor of Arts degree in Psychology from West Liberty State College. He is a member of the Society for Human Resource Management. He is a founder and current member of the Stark County Health Care Coalition; President of the Stark County Historical Society; and, Chairman of the Business Advisory Board and adjunct faculty member of Kent State University. CHARLES P. FABER has been Vice President of Corporate Development for the Company since 1993. He previously served as Senior Vice President of Capital Markets from 1988 to 1993. Prior to joining Belden & Blake, Mr. Faber was employed as Senior Vice President of Marketing for Heritage Asset Management from 1986 to 1988. From 1983 to 1986 he served as President and Chief Executive Officer of Samson Properties, Incorporated. Mr. Faber holds a BA degree in Marketing and an MBA in Finance from the University of Wisconsin. He is a member of the Independent Petroleum Association of America, the National Investor Relations Institute and the Petroleum Investor Relations Association. ROBERT W. PESHEK has served as Vice President of Finance for the Company since 1997. Previously, he served as Corporate Controller and Tax Manager from 1994 to 1997. Prior to joining Belden & Blake, Mr. Peshek served as a Senior Manager of the Tax Department at Ernst & Young LLP from 1981 to 1994. He is a Certified Public Accountant with extensive experience in taxation, accounting and auditing. Mr. Peshek holds a Bachelor of Business Administration degree in Accounting from Kent 27 29 State University where he graduated with honors. His professional affiliations include the American Institute of Certified Public Accountants and the Ohio Society of Certified Public Accountants. DEAN A. SWIFT has served as Vice President, Assistant General Counsel and Assistant Secretary of the Company since 1989. He served as Assistant General Counsel of the Company from 1981 to 1989. From 1978 to 1981 he was associated with the law firm of Hahn, Loeser and Parks in Cleveland, Ohio. Mr. Swift received a BA degree from the University of the South and a JD degree from the University of Virginia. He is a member of the Stark County, Ohio State and American Bar Associations. HENRY S. BELDEN, IV served as Chairman and Chief Executive Officer of the Company from 1982 to 1997. He resigned as Chairman and Chief Executive Officer upon the Company's acquisition by TPG (the "Acquisition"), and was appointed to serve on the Board of Directors upon consummation of the Acquisition. Mr. Belden has been involved in oil and gas production since 1955 and associated with Belden & Blake since 1967. Prior to joining Belden & Blake, he was employed by Ashland Oil & Refining Company and Halliburton Services, Incorporated. Mr. Belden attended Florida State University and the University of Akron and is a member of the 25-Year Club of the Petroleum Industry and the Board of Trustees of the Ohio Oil and Gas Association. He is also a member of the Regional Advisory Board of the Independent Petroleum Association of America and a director and a member of the Executive Committee of the Pennsylvania Grade Crude Oil Association. He is a member of the Interstate Oil Compact Commission. Other professional memberships include the World Business Council and the Association of Ohio Commodores. He is a director of KeyBank-Canton District and Phoenix Packaging Corporation. LAWRENCE W. KELLNER is Executive Vice President and Chief Financial Officer of Continental Airlines, Inc. In this position, Mr. Kellner is responsible for Treasury activities, Fleet Management, Financial Planning, Information Technology, Fuel Purchasing, Accounting and Risk Management. Most recently, he was Executive Vice President and Chief Financial Officer for American Savings Bank, with approximately $20 billion in assets, where he was responsible for all financial operations and strategic planning. Prior to joining American Savings Bank, Mr. Kellner was Executive Vice President and Chief Financial Officer for The Koll Company. While at The Koll Company, he managed the $5 billion domestic and international real estate portfolio of both the company and its 250 affiliated partnerships. Mr. Kellner began his career at Ernst & Young LLP where he was responsible for the operation and administration of the company's real estate consulting and accounting division in Southern California. Mr. Kellner graduated magna cum laude with a Bachelor of Science, Business Administration degree from the University of South Carolina. He is a Certified Public Accountant and has been active in numerous community and civic organizations including past positions on several boards of directors. MAX L. MARDICK was President and Chief Operating Office of the Company from 1990 to 1997, a director from 1992 to 1997 and a director of predecessor companies from 1988 to 1992. He resigned as President and Chief Operating Officer upon consummation of the Acquisition and was appointed to serve on the Board of Directors upon consummation of the Acquisition. He previously served as Executive Vice President and Chief Operating Officer from 1988 to 1990. Mr. Mardick is a Petroleum Engineer with more than 35 years of experience in domestic and international production, engineering, drilling operations and property evaluation. Prior to joining Belden & Blake, he was employed for more than 30 years by Shell Oil Company in various engineering, supervisory and senior management positions, including: Manager, Property Acquisitions and Business Development (1986-1988); Production Manager for Shell's Onshore and Eastern Divisions (1981-1986); Production Manager of Shell's Rocky Mountain Division (1980-1981); Operations Manager (1977-1980); and Engineering Manager (1975-1977). Mr. Mardick holds a BS degree in Petroleum Engineering from the University of Kansas. He is a member of the Society of Petroleum Engineers and the Ohio Oil and Gas Association. He has served as Vice Chairman of the Alabama-Mississippi section of the Mid-Continent Oil and Gas Association. 28 30 WILLIAM S. PRICE, III, who became a director upon consummation of the Acquisition, was a founding partner of Texas Pacific Group in 1993. Prior to forming Texas Pacific Group, Mr. Price was Vice President of Strategic Planning and Business Development for G.E. Capital, and from 1985 to 1991 he was employed by the management consulting firm of Bain & Company, attaining partnership status and acting as co-head of the Financial Services Practice. Mr. Price is a 1978 graduate of Stanford University and received a JD degree from the Boalt Hall School of Law at the University of California, Berkeley. Mr. Price is Chairman of the Board of Favorite Brands International, Inc. and Co-Chairman of the Board of Beringer Wine Estates. He also serves on the Boards of Directors of Continental Airlines, Inc., Continental Micronesia, Inc., Denbury Resources, Inc. and Vivra Specialty Partners, Inc. GARETH ROBERTS is President, Chief Executive Officer and a Director of Denbury Resources, Inc. ("Denbury"), and is the founder of the operating subsidiary of Denbury, which was founded in April 1990. Mr. Roberts has 25 years of experience in the exploration and development of oil and natural gas properties with Texaco, Inc., Murphy Oil Corporation and Coho Resources, Inc. His expertise is particularly focused in the Gulf Coast region where he specializes in the acquisition and development of old fields with low productivity. Mr. Roberts holds honors and masters degrees in Geology and Geophysics from St. Edmund Hall, Oxford University. DAVID M. STANTON, who became a director upon consummation of the Acquisition, is a partner of Texas Pacific Group. From 1991 until he joined Texas Pacific Group in 1994, Mr. Stanton was a venture capitalist with Trinity Ventures, where he specialized in information technology, software and telecommunications investing. Mr. Stanton earned a BS degree in Chemical Engineering from Stanford University and received an MBA from the Stanford Graduate School of Business. Mr. Stanton serves on the Boards of Directors of Denbury Resources, Inc., TPG Communications, Inc. and Paradyne Partners, L.P. 29 31 Item 11. EXECUTIVE COMPENSATION ---------------------- The following table shows the annual and long-term compensation for services in all capacities to the Company during the fiscal years ended December 31, 1997, 1996 and 1995 of the Company's Chief Executive Officer and its other four most highly compensated executive officers. SUMMARY COMPENSATION TABLE
Long-Term Compensation All Other Annual Compensation Award Compensation(2) ------------------------------------------------- ---------------- --------------- No. of Shares Name and Other Annual Underlying Principal Position Year Salary Bonus Compensation Options/SARs (1) - ------------------- ---- ------ ----- ------------ ---------------- Henry S. Belden IV 1997 $180,600 -- -- -- $20,568(4) Chairman of the Board 1996 $322,038 $ 161,962 -- 40,000 $25,869(4) and Chief Executive 1995 $310,994 $ 145,765 -- 40,000 $18,720(4) Officer (3) Max L. Mardick 1997 $146,892 -- -- -- $ 5,575 President and Chief 1996 $236,731 $ 83,793 -- 25,000 $13,439 Operating Officer (5) 1995 $229,808 $ 72,445 -- 25,000 $ 7,042 Ronald L. Clements 1997 $239,154 $ 84,390 -- 137,366 $14,625 Chief Executive Officer 1996 $171,173 $ 66,303 $4,000 20,000 $11,342 1995 $161,373 $ 62,568 $5,000 20,000 $ 7,629 Ronald E. Huff 1997 $208,646 $ 83,192 -- 137,366 $13,767 President and Chief 1996 $166,462 $ 66,175 -- 20,000 $11,550 Financial Officer 1995 $168,466 $ 32,706 -- 20,000 $ 8,016 Joseph M. Vitale 1997 $168,800 $ 66,627 -- 54,946 $11,863 Senior Vice President 1996 $162,069 $ 66,020 -- 20,000 $10,078 Legal, General Counsel 1995 $156,066 $ 52,810 -- 20,000 $ 8,768 and Secretary Tommy L. Knowles 1997 $167,154 $ 46,563 -- 54,946 $72,009(6) Senior Vice President 1996 $141,923 $ 12,772 -- 20,000 $57,041(7) of Exploration and Production Leo A. Schrider 1997 $128,504 $ 20,065 -- 20,000 $10,046 Senior Vice President 1996 $124,261 $ 19,616 -- 12,500 $ 8,416 of Technical Development 1995 $120,954 $ 14,078 -- 12,500 $ 6,194 - ---------------------
(1) All awards prior to June 27, 1997 relate to options to purchase stock in the predecessor company. 30 32 (2) Represents contributions of cash and Common Stock to the Company's 401(k) Profit Sharing Plan for the account of the named executive officers. (3) Mr. Belden served as Chairman and Chief Executive Officer until his resignation on June 27, 1997. (4) Includes $9,012, $8,316 and $7,641 as the portion of the total premium paid by the Company in 1997, 1996 and 1995, respectively, under a split-dollar insurance plan that is attributable to term life insurance coverage for Mr. Belden. (5) Mr. Mardick served as President and Chief Operating Officer until his resignation on June 27, 1997. (6) Includes stock grants amounting to $60,803. (7) Includes stock grants amounting to $17,500 and moving expenses of $34,269. OPTION/SAR GRANTS IN LAST FISCAL YEAR Individual Grants - --------------------------------------------------------------
% of Total Options/SARs Options/ Granted to SARs Employees in Exercise or Expiration Grant Date Name Granted(1) Fiscal Year Base Price Date Present Value(3) ---- ---------- ----------- ---------- ---------- ---------------- Ronald L. Clements 137,366(1) 21.0% $10.82 6/26/07 $243,138 Ronald E. Huff 137,366(1) 21.0% 10.82 6/26/07 243,138 Joseph M. Vitale 54,946 (2) 8.4% 10.82 11/30/07 117,035 Tommy L. Knowles 54,946 (2) 8.4% 10.82 11/30/07 117,035 Leo A. Schrider 20,000 (2) 3.1% 10.82 11/30/07 42,600
(1) These options are exercisable starting 12 months after the date of grant, with 25% of the shares covered thereby becoming exercisable at that time and the balance becoming exercisable at the rate of 8.33% at the end of each quarter thereafter. (2) These options are exercisable starting 12 months after the date of grant, with 25% of the shares covered thereby becoming exercisable at that time and an additional 25% becoming exercisable on each successive anniversary date. The options were granted for a term of ten years, subject to earlier termination on cessation of employment. (3) This is a hypothetical valuation using the Black-Scholes valuation method. The Company's use of this model should not be considered as an endorsement of its accuracy at valuing options. All stock option valuation methods, including the Black-Scholes model, require a prediction about the future movement of the stock price. Since all options are granted at an exercise price equal to the market value of the Company's Common Stock on the date of grant, no value will be realized if there is no appreciation in the market price of the stock. 31 33 AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION/SAR VALUE
Value of Unexercised Number of Unexercised In-the Money Options/SARs at FY-End Options/SARs at FY-End ---------------------- -------------------------- Shares Acquired Value Name on Exercise(1) Realized(2) Exercisable Unexercisable Exercisable Unexercisable ---- ------------ --------- ----------- ------------- ----------- ------------- Henry S. Belden IV 69,750 $1,063,219 63,360 -- $567,706 $ -- Max L. Mardick 41,250 625,781 39,387 -- 352,908 -- Ronald L. Clements 16,250 217,656 31,168 137,366 279,265 -- Ronald E. Huff 31,250 472,656 31,168 137,366 279,265 -- Joseph M. Vitale 70,000 806,875 -- 54,946 -- -- Tommy L. Knowles 20,000 155,000 -- 54,946 -- -- Leo A. Schrider 35,000 354,063 -- 20,000 -- --
(1) There were no options exercised in 1997. The amounts shown represent the number of shares related to options which were surrendered in connection with the merger. (2) Represents cash received on surrender of options equal to the amount by which the per share amount received by shareholders in exchange for their shares of common stock in the merger exceeded the option price. COMPENSATION OF DIRECTORS Directors of the Company are not compensated for their services as such nor for their participation on any committees of the Board of Directors. EMPLOYMENT AND SEVERANCE AGREEMENTS The Company has severance agreements with Messrs. Clements, Huff and Vitale which entitle each of them to receive a lump sum severance payment equal to 300% of the sum of (i) his respective annual base salary at the highest rate in effect for any period prior to his employment termination plus (ii) his highest annual bonus and incentive compensation during the three-year period preceding a change in control, in the event of the termination of his employment by the Company other than for "cause" (as defined therein) or his resignation in response to a substantial reduction in responsibilities, authority, position, compensation or location of his place of work within three years following a change in control. In addition, each of them would be entitled to receive an additional payment sufficient to cover any excise tax imposed by Section 4999 of the Code on the severance payments or other payment considered "contingent on a change in ownership or control" of the Company within the meaning of Section 280G of the Code. Messrs. Clements and Huff each entered into employment agreements dated as of June 27, 1997 (the "Employment Agreements") providing for their employment as Chief Executive Officer and President, respectively, of the Company. The Employment Agreements provide for an annual base salary of not less than $300,000 payable to Mr. Clements and $250,000 payable to Mr. Huff. Messrs. Clements and Huff will each be entitled to earn an annual bonus of up to 50% of his annual base salary based on the attainment of certain goals to be set by the Company's Board of Directors. Each of Messrs. Clements and Huff agreed to continue to hold, and not surrender, certain stock options previously granted to him under the Company's Stock Option Plan, thereby foregoing the right to receive $334,220 each in cash upon the surrender of such options. The Employment Agreements provide for the granting to each of Messrs. Clements and Huff of additional options to purchase shares of common stock of the Company constituting 1.25% of the outstanding common stock (on a fully-diluted basis) at an option price equivalent to the price 32 34 paid by TPG in connection with the Acquisition. The options will vest over a four year period, with one-fourth (1/4) vesting one year after the date of grant and the balance at the rate of one-twelfth (1/12) at the end of each quarter thereafter during the continuation of employment with the Company. The Employment Agreements provide for certain call options and rights of first refusal in connection with the shares of common stock obtainable upon the exercise of stock options. The Employment Agreements provide that Messrs. Clements and Huff will be entitled to employee welfare and retirement benefits substantially comparable to those presently provided by the Company and to any other employee benefits later made available to senior executive management of the Company. The Employment Agreements further provide that the existing severance agreements that Messrs. Clements and Huff have with the Company will remain in force and upon the expiration thereof will be replaced by new severance agreements providing substantially the same benefits. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION Until June 27, 1997, the Compensation Committee of the Board of Directors consisted of George M. Smart, Raymond D. Saunders and Gary R. Petersen, all of whom are outside directors. Henry S. Belden IV, who was the Chairman of and Chief Executive Officer of the Company until completion of the merger on June 27, 1997, is a director of Phoenix Packaging Corporation of which Mr. Smart is President and Chief Executive Officer. 33 35 Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND --------------------------------------------------- MANAGEMENT ---------- The following table sets forth certain information as of February 28, 1998 regarding the beneficial ownership of the Company's common stock by each person who beneficially owns more than five percent of the Company's outstanding common stock, each director, the chief executive officer and the four other most highly compensated executive officers and by all directors and executive officers of the Company, as a group:
FIVE PERCENT SHAREHOLDERS NUMBER OF SHARES PERCENTAGE OF SHARES ------------------------- ---------------- -------------------- TPG Advisors II, Inc. 201 Main Street, Suite 2420 Fort Worth, Texas 76102 9,353,038(1) 92.5% State Treasurer of the State of Michigan, Custodian of the Public School Employees' Retirement System, State Employees Retirement System, Michigan State Police Retirement System and Michigan Judges Retirement System 554,376 5.5% OFFICERS AND DIRECTORS ---------------------- William S. Price, III 9,353,038 (1) 92.5% Henry S. Belden IV 63,360 (2) * Ronald L. Clements 31,168 (2) * Ronald E. Huff 31,168 (2) * Lawrence W. Kellner -0- -0- Max L. Mardick 39,387 (2) * Tommy L. Knowles -0- -0- Gareth Roberts -0- -0- David M. Stanton -0- -0- Leo A. Schrider -0- -0- Joseph M. Vitale -0- -0- All directors and executive 9,518,121 94.1% officers as a group
*Less than 1% (1) Neither TPG Advisors II, Inc. nor Mr. Price is the record owner of any shares of the Company's common stock. Mr. Price is, however, a director, executive officer and shareholder of TPG Advisors II, Inc., which is the general partner of TPG GenPar II, L.P., which in turn is the general partner of each of TPG II, TPG Investors II, L.P. and TPG Parallel II, L.P. which are the direct beneficial owners of 7,976,645, 832,047 and 544,346 shares of common stock, respectively. (2) Consists of shares subject to stock options exercisable within 60 days. 34 36 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS In connection with the Acquisition, the Company entered into a Transaction Advisory Agreement with TPG Partners II, L.P. pursuant to which TPG Partners II, L.P. received a cash financial advisory fee of $5.0 million upon the closing of the Acquisition as compensation for its services as financial advisor in connection with the Acquisition. TPG Partners II, L.P. also will be entitled to receive (but, at its discretion, may waive) fees of up to 1.5% of the "transaction value" for each subsequent transaction (a tender offer, acquisition, sale, merger, exchange offer, recapitalization, restructuring or other similar transaction) in which the Company is involved. The term "transaction value" means the total value of any subsequent transaction, including, without limitation, the aggregate amount of the funds required to complete the subsequent transaction (excluding any fees payable pursuant to the Transaction Advisory Agreement and fees, if any, paid to any other person or entity for financial advisory, investment banking, brokerage or any other similar services rendered in connection with such transaction) including the amount of any indebtedness, preferred stock or similar items assumed (or remaining outstanding). The Transaction Advisory Agreement shall continue until the earlier of (i) 10 years from the execution date or (ii) the date on which TPG Partners II, L.P. and its affiliates cease to own, beneficially, directly or indirectly, at least 25% of the voting power of the securities of the Company. In management's opinion, the fees provided for under the Transaction Advisory Agreement reasonably reflect the benefits received and to be received by the Company. Messrs. Belden and Mardick have each entered into non-competition agreements with the Company dated March 27, 1997 (the "Non-Competition Agreements"), which became effective contemporaneously with consummation of the Acquisition. Pursuant to the terms of the Non-Competition Agreements, Messrs. Belden and Mardick have each agreed, for a period of three (3) years from June 27, 1997 that he will not, in any county in the United States in which the Company does business, directly or indirectly, either for himself or as a member of a partnership or as a shareholder, investor, agent, associate or consultant engage in any business in which the Company is engaged immediately prior to June 27, 1997. Messrs. Belden and Mardick have each further agreed that he will not, directly or indirectly, make any misleading or untrue statement that disparages or would have the effect of disparaging the Company or any of its affiliates or employees or of adversely affecting the reputation, business or credit rating of the Company or any of its affiliates or employees, and that, for a period of three years from June 27, 1997, he will not, directly or indirectly, interfere with, or take any action that would have the effect of interfering with, the contractual and other relationships between the Company or any of its affiliates and any of its or their employees, customers or suppliers. In consideration of such agreements, Mr. Belden will receive $2,400,616.44 and Mr. Mardick will receive $983,711.16 in each case payable in 36 monthly installments. 35 37 PART IV ------- Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON ------------------------------------------------------- FORM 8-K -------- (a) Documents filed as a part of this report: 1. Financial Statements The financial statements listed in the accompanying Index to Consolidated Financial Statements and Schedules are filed as part of this Annual Report on Form 10-K. 2. Financial Statement Schedules No financial statement schedules are required to be filed as part of this Annual Report on Form 10-K. 3. Exhibits
No. Description - -- ----------- 2.1 Agreement and Plan of Merger dated as of March 27, 1997 by and among TPG Partners II, BB Merger Corp. and Belden & Blake Corporation-incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407) 3.1 Amended and Restated Articles of Incorporation of Belden & Blake Corporation (fka Belden & Blake Energy Corporation)--incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407) 3.2 Code of Regulations of Belden & Blake Corporation-- incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407)
36 38
4.1 Indenture dated as of June 27, 1997 between the Company, the Subsidiary Guarantors and LaSalle National Bank, as trustee, relating to the Notes--incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407) 4.2 Registration Rights Agreement dated as of June 27, 1997 between the Company, the Guarantors and Chase Securities, Inc. --incorporated by reference to Exhibit 4.2 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407) 4.3 Form of 9 7/8% Senior Subordinated Notes due 2007, Original Notes (included in Exhibit 4.1)--incorporated by reference to Exhibit 4.3 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407) 4.4 Form of 9 7/8% Senior Subordinated Notes due 2007, Exchange Notes (included in Exhibit 4.1)--incorporated by reference to Exhibit 4.4 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407) 10.1 Credit Agreement dated as of June 27, 1997 by and among the Company, each of the Lenders named therein and The Chase Manhattan Bank, as Agent--incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407) 10.2 Transaction Advisory Agreement dated as of June 27, 1997 by and between the Company and TPG Partners II, L.P.-- incorporated by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407) 10.3 Employment Agreement dated as of June 27, 1997 by and between the Company and Ronald L. Clements--incorporated by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407) 10.4 Employment Agreement dated as of June 27, 1997 by and between the Company and Ronald E. Huff--incorporated by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-4 (Registration No. 333-33407) 10.5 Belden & Blake Corporation Non-Qualified Stock Option Plan-- incorporated by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-4 (Registration No 333-33407) 10.6 Form of Severance Agreement between the Company and the following officers: Ronald E. Huff, Ronald L. Clements and Joseph M. Vitale-- incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996. 10.7 Form of Severance Agreement between the Company and the following officers and managerial personnel: Dennis D. Belden, James C. Ewing, Charles P. Faber, Tommy L. Knowles, Donald A. Rutishauser, L. H. Sawatsky, Leo A. Schrider and Dean A. Swift -- incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996 10.8 Severance Pay Plan for Key Employees of Belden & Blake Corporation-- incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996 10.9(a) Stock Option Plan of the Company--incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209) 10.9(b) Stock Option Plan of the Company (as amended)--incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8 (Registration No. 33-62785) 21* Subsidiaries of the Registrant 23* Consent of Ernst & Young, LLP, Independent Auditors 27* Financial Data Schedule *Filed herewith
37 39 (b) Reports on Form 8-K No reports on Form 8-K were filed by the Company during the last quarter of the year covered by this report. (c) Exhibits required by Item 601 of Regulation S-K Exhibits required to be filed by the Company pursuant to Item 601 of Regulation S-K are contained in the Exhibits listed under Item 14(a)3. (d) Financial Statement Schedules required by Regulation S-X The items listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K. 38 40 SIGNATURES ---------- Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BELDEN & BLAKE CORPORATION March 25, 1998 By: /s/ Ronald L. Clements - ---------------------------- ------------------------------ Date Ronald L. Clements Chief Executive Officer and Director Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/ Ronald L. Clements Chief Executive Officer March 25, 1998 - -------------------------- and Director -------------- Ronald L. Clements (Principal Executive Officer) Date /s/ Ronald E. Huff President, Chief Financial March 25, 1998 - -------------------------- Officer and Direct -------------- Ronald E. Huff (Principal Financial and Date Accounting Officer) /s/ Joseph M. Vitale Senior Vice President Legal, March 25, 1998 - -------------------------- General Counsel, -------------- Joseph M. Vitale Secretary and Director Date Director March 25, 1998 - -------------------------- -------------- Henry S. Belden IV Date /s/ Lawrence W. Kellner Director March 25, 1998 - -------------------------- -------------- Lawrence W. Kellner Date /s/ Max L. Mardick Director March 25, 1998 - -------------------------- -------------- Max L. Mardick Date Director March 25, 1998 - -------------------------- -------------- William S. Price Date 39 41 Director March 25, 1998 - ---------------------- --------------------- Gareth Roberts Date /s/ David M. Stanton Director March 25, 1998 - ---------------------- --------------------- David M. Stanton Date 40 42
BELDEN & BLAKE CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES ITEM 14(a) (1) AND (2) PAGE ---- CONSOLIDATED FINANCIAL STATEMENTS - --------------------------------- Report of Independent Auditors....................................................................... F-2 Consolidated Balance Sheet as of December 31, 1997 (Successor Company) .............................. F-3 Consolidated Statements of Operations: Six months ended December 31, 1997 (Successor Company) Six months ended June 30, 1997 (Predecessor Company) Years ended December 31, 1996 and 1995 (Predecessor Company) ..................................... F-4 Consolidated Statements of Shareholders' Equity: Six months ended December 31, 1997 (Successor Company) Six months ended June 30, 1997 (Predecessor Company) Years ended December 31, 1996 and 1995 (Predecessor Company) ..................................... F-5 Consolidated Statements of Cash Flows: Six months ended December 31, 1997 (Successor Company) Six months ended June 30, 1997 (Predecessor Company) Years ended December 31, 1996 and 1995 (Predecessor Company) ..................................... F-6 Notes to Consolidated Financial Statements .......................................................... F-7
All financial statement schedules have been omitted since the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements. F-1 43 REPORT OF INDEPENDENT AUDITORS To the Shareholders and Board of Directors Belden & Blake Corporation We have audited the accompanying consolidated balance sheet of Belden & Blake Corporation ("Successor Company") as of December 31, 1997, and the related consolidated statements of operations, shareholders' equity and cash flows for the six month period ended December 31, 1997 ("Successor period"). We have also audited the accompanying consolidated statements of operations, shareholders' equity and cash flows of Belden & Blake Corporation ("Predecessor Company") for the six month period ended June 30, 1997 and each of the two years in the period ended December 31, 1996 ("Predecessor periods"). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Belden & Blake Corporation at December 31, 1997 and the consolidated results of their operations and their cash flows for the Successor period and the Predecessor periods in conformity with generally accepted accounting principles. ERNST & YOUNG LLP Cleveland, Ohio March 5, 1998 F-2 44 BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEET December 31, 1997 (in thousands)
ASSETS - ------ CURRENT ASSETS Cash and cash equivalents $ 6,552 Accounts receivable, net 35,743 Inventories 9,614 Deferred income taxes 2,702 Other current assets 4,052 --------------- TOTAL CURRENT ASSETS 58,663 PROPERTY AND EQUIPMENT, AT COST Oil and gas properties (successful efforts method) 499,864 Gas gathering systems 20,713 Land, buildings, machinery and equipment 25,602 --------------- 546,179 Less accumulated depreciation, depletion and amortization 31,036 --------------- PROPERTY AND EQUIPMENT, NET 515,143 OTHER ASSETS 25,514 --------------- $ 599,320 =============== LIABILITIES AND SHAREHOLDERS' EQUITY - ------------------------------------ CURRENT LIABILITIES Accounts payable $ 9,078 Accrued expenses 28,442 Current portion of long-term liabilities 1,297 --------------- TOTAL CURRENT LIABILITIES 38,817 LONG-TERM LIABILITIES Bank and other long-term debt 126,269 Senior subordinated notes 225,000 Other 4,380 --------------- 355,649 DEFERRED INCOME TAXES 107,996 SHAREHOLDERS' EQUITY Common stock without par value; $.10 stated value per share; authorized 58,000,000 shares; issued and outstanding 10,000,000 shares 1,000 Paid in capital 107,230 Deficit (11,372) --------------- TOTAL SHAREHOLDERS' EQUITY 96,858 --------------- $ 599,320 ===============
See accompanying notes. F-3 45 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands)
Successor | Company | Predecessor Company -------------- | ---------------------------------------------- Six months | Six months Year Year ended | ended ended ended December 31, | June 30, December 31, December 31, 1997 | 1997 1996 1995 ============== | ============== ============== ============== REVENUES | | Oil and gas sales $ 44,165 | $ 41,591 $ 79,491 $ 46,853 Gas marketing and gathering 22,714 | 21,657 44,527 40,436 Oilfield sales and service 15,541 | 14,665 25,517 20,066 Interest and other 1,706 | 1,484 3,700 2,712 -------------- | -------------- -------------- -------------- 84,126 | 79,397 153,235 110,067 EXPENSES | Production expense 11,338 | 10,158 18,098 11,756 Production taxes 1,525 | 1,647 3,168 2,060 Cost of gas and gathering expense 19,444 | 18,340 37,556 33,831 Oilfield sales and service 14,085 | 13,936 23,142 18,266 Exploration expense 5,980 | 4,380 6,064 4,924 General and administrative expense 1,813 | 2,445 4,573 3,802 Depreciation, depletion and amortization 31,694 | 15,366 29,752 19,717 Franchise, property and other taxes 967 | 908 1,739 1,228 -------------- | -------------- -------------- -------------- 86,846 | 67,180 124,092 95,584 -------------- | -------------- -------------- -------------- OPERATING (LOSS) INCOME (2,720) | 12,217 29,143 14,483 | Interest expense 15,417 | 3,715 7,383 6,073 Transaction-related expenses | 16,758 -------------- | -------------- -------------- -------------- 15,417 | 20,473 7,383 6,073 -------------- | -------------- -------------- -------------- (LOSS) INCOME FROM CONTINUING | OPERATIONS BEFORE INCOME TAXES (18,137) | (8,256) 21,760 8,410 (Benefit) provision for income taxes (6,765) | 1,617 6,566 2,150 -------------- | -------------- -------------- -------------- (LOSS) INCOME FROM | CONTINUING OPERATIONS (11,372) | (9,873) 15,194 6,260 LOSS FROM DISCONTINUED OPERATIONS | (439) (1,139) -------------- | -------------- -------------- -------------- NET (LOSS) INCOME $ (11,372) | $ (9,873) $ 14,755 $ 5,121 ============== | ============== ============== ==============
See accompanying notes. F-4 46 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (in thousands)
Successor Company Predecessor Company =================== ======================= Common Common Common Common Preferred Shares Stock Shares Stock Stock ========= ======== ========= ============= ========== Predecessor Company: JANUARY 1, 1995 -- $ -- 7,085 $ 709 $ 2,400 Stock issued 4,028 403 Net income Preferred stock dividend Stock options exercised 2 -- Employee stock bonus 22 2 Restricted stock vested - ------------------------------------------------------------------------------------------- DECEMBER 31, 1995 -- -- 11,137 1,114 2,400 Net income Preferred stock dividend Stock options exercised and related tax benefit 3 -- Employee stock bonus 26 3 Restricted stock activity 4 -- Conversion of debentures 62 6 - ------------------------------------------------------------------------------------------- DECEMBER 31, 1996 -- -- 11,232 1,123 2,400 Net loss Preferred stock redeemed (2,400) Preferred stock dividend Subordinated debentures converted to common stock 275 27 Stock options exercised and surrendered and related tax benefit 1 -- Employee stock bonus 36 4 Restricted stock activity Redemption of common stock (11,544) (1,154) Sale of common stock 10,000 1,000 SUCCESSOR COMPANY: - ------------------------------------------------------------------------------------------- JUNE 30, 1997 10,000 1,000 -- -- -- Net loss - ------------------------------------------------------------------------------------------- DECEMBER 31, 1997 10,000 $ 1,000 -- $ -- $ -- =========================================================================================== Retained Unearned Paid in Earnings Restricted Capital (Deficit) Stock Total ============ ============ ========== ============ Predecessor Company: January 1, 1995 $ 70,379 $ 7,879 $ (225) $ 81,142 Stock issued 55,264 55,667 Net income 5,121 5,121 Preferred stock dividend (180) (180) Stock options exercised 25 25 Employee stock bonus 251 253 Restricted stock vested 144 119 263 - -------------------------------------------------------------------------------------- December 31, 1995 126,063 12,820 (106) 142,291 Net income 14,755 14,755 Preferred stock dividend (180) (180) Stock options exercised and related tax benefit 47 47 Employee stock bonus 418 421 Restricted stock activity 263 71 334 Conversion of debentures 1,244 1,250 - -------------------------------------------------------------------------------------- December 31, 1996 128,035 27,395 (35) 158,918 Net loss (9,873) (9,873) Preferred stock redeemed (2,400) Preferred stock dividend (45) (45) Subordinated debentures converted to common stock 5,523 5,550 Stock options exercised and surrendered and related tax benefit 1,596 1,596 Employee stock bonus 926 930 Restricted stock activity 17 35 52 Redemption of common stock (136,097) (17,477) (154,728) Sale of common stock 107,230 108,230 Successor Company: - -------------------------------------------------------------------------------------- June 30, 1997 107,230 -- -- 108,230 Net loss (11,372) (11,372) - -------------------------------------------------------------------------------------- December 31, 1997 $ 107,230 $ (11,372) $ -- $ 96,858 ======================================================================================
See accompanying notes. F-5 47 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands)
Successor | Company | Predecessor Company -------------------- | -------------------------------------------------- Six months | Six months Year Year ended | ended ended ended December 31, | June 30, December 31, December 31, 1997 | 1997 1996 1995 ==================== | ================ ================ =============== CASH FLOWS FROM OPERATING ACTIVITIES: | | Net (loss) income $ (11,372) | $ (9,873) $ 14,755 $ 5,121 Adjustments to reconcile net (loss) income to net cash | provided by operating activities: | Depreciation, depletion and amortization 31,694 | 15,366 29,752 20,154 Transaction-related expenses | 15,903 Loss on disposal of property and equipment 51 | 356 534 177 Deferred income taxes (6,379) | 3,125 4,232 488 Deferred compensation and stock grants 380 | 1,756 1,311 1,067 Change in operating assets and liabilities, net of | effects of purchases of businesses: | Accounts receivable and other operating assets (5,280) | 1,237 (4,385) (14,485) Inventories 597 | 112 (144) 469 Accounts payable and accrued expenses (4,064) | 4,800 476 8,958 -------------------- | ---------------- ---------------- --------------- NET CASH PROVIDED BY OPERATING ACTIVITIES 5,627 | 32,782 46,531 21,949 | CASH FLOWS FROM INVESTING ACTIVITIES: | Acquisition of businesses, net of cash acquired (14,276) | (9,263) (4,543) (99,837) Proceeds from property and equipment disposals 785 | 704 2,227 589 Additions to property and equipment (23,663) | (18,419) (37,074) (23,855) Increase in other assets (274) | (9,496) (705) (867) -------------------- | ---------------- ---------------- --------------- NET CASH USED IN INVESTING ACTIVITIES (37,428) | (36,474) (40,095) (123,970) | CASH FLOW FROM FINANCING ACTIVITIES: | Proceeds from revolving line of credit and long-term debt | 46,000 16,105 73,000 Proceeds from new credit agreement 24,020 | 104,000 Proceeds from senior subordinated notes | 225,000 Sale of common stock | 108,230 Repayment of long-term debt and other obligations (2,989) | (140,325) (26,117) (17,818) Payment to shareholders and optionholders | (312,164) Transaction-related expenses | (15,903) Preferred stock redeemed | (2,400) Preferred stock dividends | (45) (180) (180) Proceeds from sale of common stock and stock options | 15 40 59,438 Common stock placement cost | (3,746) -------------------- | ---------------- ---------------- --------------- NET CASH PROVIDED BY (USED IN) | FINANCING ACTIVITIES 21,031 | 12,408 (10,152) 110,694 -------------------- | ---------------- ---------------- --------------- NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (10,770) | 8,716 (3,716) 8,673 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 17,322 | 8,606 12,322 3,649 -------------------- | ---------------- ---------------- --------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 6,552 | $ 17,322 $ 8,606 $ 12,322 ==================== | ================ ================ ===============
See accompanying notes. F-6 48 BELDEN & BLAKE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) MERGER On March 27, 1997, the Company signed a definitive merger agreement with TPG Partners II, L.P. ("TPG"), a private investment partnership, pursuant to which TPG and certain other investors acquired the Company in an all-cash transaction valued at $440 million. Under the terms of the agreement, TPG and such investors paid $27 per share for all common shares outstanding plus an additional amount to redeem certain stock options held by directors and employees. The transaction was completed on June 27, 1997 and for financial reporting purposes has been accounted for as a purchase effective June 30, 1997. The acquisition resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date. Accordingly, the financial statements for the period subsequent to June 30, 1997 are presented on the Company's new basis of accounting, while the results of operations for the periods ended June 30, 1997 and December 31, 1996 and 1995 reflect the historical results of the predecessor company. A vertical black line is presented to separate the financial statements of the predecessor and successor companies. Following are unaudited pro forma results of operations as if the merger occurred at the beginning of 1996 (in thousands):
YEAR ENDED DECEMBER 31 ----------------------------- 1997 1996 -------------- ------------- Total revenues $ 163,523 $ 153,235 Loss from continuing operations (19,970) (14,701)
The unaudited pro forma information presented above assumes the transaction-related expenses were incurred prior to the period presented and does not purport to be indicative of the results that actually would have been obtained if the merger had been consummated at the beginning of 1996 and is not intended to be a projection of future results or trends. In connection with the merger, the Company entered into a Transaction Advisory Agreement with TPG pursuant to which TPG received a cash financial advisory fee of $5.0 million for services as financial advisor in connection with the merger. The fee is included in the $16.8 million of transaction-related expenses. TPG also will be entitled to receive (but, at its discretion, may waive) fees of up to 1.5% of the transaction value for each subsequent transaction (a tender offer, acquisition, sale, merger, exchange offer, recapitalization, restructuring or other similar transaction) entered into by the successor company. Certain former officers have entered into non-competition agreements with the Company dated March 27, 1997, which became effective contemporaneously with consummation of the merger. These agreements have a term of 36 months and a total value of $3.0 million. The obligation for these agreements is included in the balance sheet. (2) BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES BUSINESS The Company operates primarily in the oil and gas industry. The Company's principal business is the acquisition, exploration, development and production of oil and gas reserves, and the gathering and marketing of natural gas. Sales of oil are ultimately made to refineries. Sales of gas are ultimately made to industrial consumers in Ohio, Michigan, West Virginia, Pennsylvania, New York and Kentucky and to gas utilities. The Company also provides oilfield services and is a distributor of a broad range of oilfield F-7 49 equipment and supplies. Its customers include other independent oil and gas companies, dealers and operators throughout Ohio, Michigan, West Virginia, Pennsylvania and New York. The price of oil and gas has a significant impact on the Company's working capital and results of operations. PRINCIPLES OF CONSOLIDATION AND FINANCIAL PRESENTATION The accompanying consolidated financial statements include the financial statements of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. USE OF ESTIMATES IN THE FINANCIAL STATEMENTS The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts. Significant estimates used in the preparation of the Company's financial statements which could be subject to significant revision in the near term include estimated oil and gas reserves. Although actual results could differ from these estimates, significant adjustments to these estimates historically have not been required. CASH EQUIVALENTS For purposes of the statements of cash flows, cash equivalents are defined as all highly liquid debt instruments purchased with an initial maturity of three months or less. CONCENTRATIONS OF CREDIT RISK Credit limits, ongoing credit evaluation and account monitoring procedures are utilized to minimize the risk of loss. Collateral is generally not required. Expected losses are provided for currently and actual losses have been within management's expectations. INVENTORIES Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural gas inventories are stated at average cost. PROPERTY AND EQUIPMENT The Company utilizes the "successful efforts" method of accounting for its oil and gas properties. Under this method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, dry holes, expired leases and delay rentals, are expensed as incurred. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized. Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense. Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery F-8 50 and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is charged to income as incurred, and significant renewals and betterments are capitalized. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and carrying value of the asset. INTANGIBLE ASSETS These costs ($22,611,000) include deferred debt issuance costs, goodwill and other intangible assets and are being amortized over 25 years or the shorter of their respective terms. REVENUE RECOGNITION Oil and gas production revenue is recognized as production and delivery take place. Oil and gas marketing revenues are recognized when title passes. Oilfield sales and service revenues are recognized when the goods or services have been provided. INCOME TAXES The Company uses the liability method of accounting for income taxes. Deferred income taxes are provided for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred income taxes also are recognized for operating losses that are available to offset future taxable income and tax credits that are available to offset future federal income taxes. STOCK-BASED COMPENSATION The Company measures expense associated with stock-based compensation under the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." (3) NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED In June 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. (SFAS) 130, "Reporting Comprehensive Income" and Statement of Financial Accounting Standards No. (SFAS) 131, "Disclosures about Segments of an Enterprise and Related Information." The Company will adopt these statements in 1998. SFAS 130 establishes standards for reporting and displaying comprehensive income and its components in general-purpose financial statements. The Company does not believe this pronouncement will have a material impact on its financial statements. SFAS 131 establishes standards for public business enterprises for reporting information about operating segments in annual financial statements and requires that such enterprises report selected information about operating segments in interim financial reports issued to shareholders. This Statement also establishes standards for related disclosures about products and services, geographic areas, and major customers. The Company will begin presenting any additional information required by the Statement in its financial statements for the year ended December 31, 1998. (4) ACQUISITIONS F-9 51 The following acquisitions were accounted for as purchase business combinations. Accordingly, the results of operations of the acquired businesses are included in the Company's consolidated statements of operations from the date of the respective acquisitions. During 1997, the Company acquired working interests in oil and gas wells in Ohio, Pennsylvania, West Virginia and Michigan for approximately $13.5 million for the successor company's six months ended December 31, 1997 and $7.8 million for the predecessor company's six months ended June 30, 1997. Estimated proved developed reserves associated with the wells totaled 32.8 Bcf of natural gas and 101,000 Bbls of oil net to the Company's interest at time of the acquisitions. During 1996, the Company acquired for approximately $4.1 million working interests in 323 oil and gas wells in Ohio and Kentucky. Estimated proved developed reserves associated with the wells totaled 6.0 Bcf of natural gas and 205,000 Bbls of oil net to the Company's interest at July 1, 1996. Effective July 1995, the Company purchased from Quaker State Corporation most of its oil and gas properties and related assets in the Appalachian Basin (the "Quaker State Properties") for approximately $50 million. The Quaker State Properties included approximately 1,460 gross (1,100 net) wells with estimated proved reserves of 2.2 Mmbbl of oil and 46.8 Bcf of gas at December 31, 1994, approximately 250 miles of gas gathering systems, undeveloped oil and gas leases and fee mineral interests covering approximately 250,000 acres, an extensive geologic and geophysical database and other assets. In January 1995, the Company purchased Ward Lake Drilling, Inc. ("Ward Lake"), a privately-held exploration and production company headquartered in Gaylord, Michigan, for $15.1 million. At the time of acquisition Ward Lake operated and held a production payment interest and working interests averaging 13.6% in approximately 500 Antrim Shale gas wells located in Michigan's lower peninsula. The purchase also included approximately 5,500 undeveloped leasehold acres that Ward Lake owns in Michigan. At December 31, 1994, the wells had estimated proved developed natural gas reserves totaling 98 Bcf (14 Bcf net to the Company's interest). Approximately one half of the purchase price represented payment for the proved reserves, with the balance associated with other oil and gas and corporate assets. Through the end of 1996, the Company purchased additional working interests averaging 24% in the wells operated by Ward Lake for approximately $12 million. The interests acquired had estimated proved developed reserves of 16 Bcf at December 31, 1994. In addition, during 1995 the Company, in four separate transactions, acquired for approximately $29.2 million working interests in oil and gas wells in Michigan, Ohio, Pennsylvania and New York and drilling rights on more than 250,000 acres in Ohio. Estimated proved developed reserves associated with the wells totaled 35 Bcfe of natural gas net to the Company's interest at December 31, 1994. The unaudited pro forma results of operations for the year ended December 31, 1995 as if the acquisitions above occurred at the beginning of the period are as follows: revenues of $124.9 million and net income of $8.5 million. The pro forma effects of the 1997 (predecessor and successor periods) and the 1996 acquisitions were not material. F-10 52
(5) DETAILS OF BALANCE SHEET DECEMBER 31, 1997 ----------------- ACCOUNTS RECEIVABLE (IN THOUSANDS) Accounts receivable $ 20,234 Allowance for doubtful accounts (948) Oil and gas production receivable 15,959 Current portion of notes receivable 498 ----------------- $ 35,743 ================= INVENTORIES Oil $ 2,429 Natural gas 387 Material, pipe and supplies 6,798 ----------------- $ 9,614 ================= PROPERTY AND EQUIPMENT, GROSS OIL AND GAS PROPERTIES Producing properties $ 466,491 Non-producing properties 12,792 Other 20,581 ----------------- $ 499,864 ================= LAND, BUILDINGS, MACHINERY AND EQUIPMENT Land, buildings and improvements $ 8,530 Machinery and equipment 17,072 ----------------- $ 25,602 ================= ACCRUED EXPENSES Accrued expenses $ 11,126 Accrued drilling and completion costs 3,736 Ad valorem and other taxes 4,020 Compensation and related benefits 3,524 Undistributed production revenue 6,036 ----------------- $ 28,442 ================= (6) LONG-TERM DEBT Long-term debt consists of the following (in thousands): DECEMBER 31, 1997 ----------------- New credit agreement $ 126,000 Senior subordinated notes 225,000 Other 418 ----------------- 351,418 Less current portion 149 ----------------- Long-term debt $ 351,269 =================
On June 27, 1997, the Company completed a private placement (pursuant to Rule 144A) of $225 million of 9 7/8% Senior Subordinated Notes, Series A, which mature on June 15, 2007. The notes were issued under an indenture which requires interest to be paid semiannually on June 15 and December 15 of each year, commencing December 15, 1997. The notes are subordinate to the new credit agreement. In September 1997, the Company completed a registration statement on Form S-4 providing for an exchange offer under which each Series A Senior Subordinated Note would be exchanged for a Series B Senior Subordinated Note. The terms of the Series B Notes are the same in all respects as the Series A Notes F-11 53 except that the Series B Notes have been registered under the Securities Act of 1933 and therefore will not be subject to certain restrictions on transfer. The notes are redeemable in whole or in part at the option of the Company, at any time on or after June 15, 2002, at the redemption prices set forth below plus, in each case, accrued and unpaid interest, if any, thereon.
YEAR PERCENTAGE ---- ---------- 2002.......................................... 104.938% 2003.......................................... 103.292% 2004.......................................... 101.646% 2005 and thereafter........................... 100.000%
Prior to June 15, 2000, the Company may, at its option, on any one or more occasions, redeem up to 40% of the original aggregate principal amount of the notes at a redemption price equal to 109.875% of the principal amount, plus accrued and unpaid interest, if any, on the redemption date, with all or a portion of net proceeds of public sales of common stock of the Company; provided that at least 60% of the original aggregate principal amount of the notes remains outstanding immediately after the occurrence of such redemption; and provided, further, that such redemption shall occur within 60 days of the date of the closing of the related sale of common stock of the Company. The indenture under which the subordinated notes were issued contains certain covenants that limit the ability of the Company and its subsidiaries to incur additional indebtedness and issue stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens, and engage in mergers and consolidations. On June 27, 1997, the Company also entered into a new credit agreement with several lenders. These lenders have committed, subject to compliance with the borrowing base, to provide the Company with revolving credit loans of up to $200 million, of which $25 million will be available for the issuance of letters of credit. The new credit agreement is a senior revolving credit facility which is secured by substantially all of the Company's assets. The initial borrowing base has been set at $180 million. The borrowing base is the sum of the Company's proved developed reserves, proved developed non-producing reserves, proved undeveloped reserves and related processing and gathering assets and other assets of the Company, adjusted by the engineering committee of the bank in accordance with their standard oil and gas lending practices. If less than 75% of the borrowing base is utilized, the borrowing base will be re-determined annually. If more than 75% of the borrowing base is utilized, the borrowing base will be re-determined semi-annually. The Company borrowed $104 million under the new credit agreement to partially finance the acquisition of the Company by TPG; to repay certain existing outstanding indebtedness of the Company and to pay certain fees and expenses related to the transaction. The new credit agreement will mature on June 27, 2002. Outstanding balances under the agreement incur interest at the Company's choice of several indexed rates, the most favorable being 7.219% at December 31, 1997. The new credit agreement contains a number of covenants that, among other things, restrict the ability of the Company and its subsidiaries to dispose of assets, incur additional indebtedness, prepay other indebtedness or amend certain debt instruments, pay dividends, create liens on assets, enter into sale and leaseback transactions, make investments, loans or advances, make acquisitions, engage in mergers or consolidations, change the business conducted by the Company or its subsidiaries, make capital expenditures or engage in certain transactions with affiliates and otherwise restrict certain corporate F-12 54 activities. In addition, under the new credit agreement, the Company is required to maintain specified financial ratios and tests, including minimum interest coverage ratios and maximum leverage ratios. In connection with the senior subordinated notes and the new credit agreement, the Company allocated $9.5 million of fees paid to investment bankers to deferred debt issuance costs. The Company may enter into interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of the Company's floating rate exposure would be exchanged for a fixed interest rate. During October 1997, the Company entered into two interest rate swap arrangements with a major financial institution covering $90 million of debt. The Company swapped $40 million of floating three-month LIBOR +1.5% for a fixed rate of 7.485% for three years, extendible at the institution's option for an additional two years. The Company also swapped $50 million of floating three-month LIBOR +1.5% for a fixed rate of 7.649% for five years. The Company had no such derivative financial instruments at December 31, 1996 or 1995. Under the deferral method gains and losses on these instruments are deferred on the balance sheet and the interest rate differential to be received or paid is recognized as an adjustment to interest expense for the month hedged. On April 3, 1997, the Company gave notice of redemption of all of the outstanding 9.25% convertible subordinated debentures for 104% of face value. Redemption of these debentures occurred June 10, 1997 when holders of the debentures elected to convert them into 275,425 shares of common stock in the predecessor company. On June 25, 1997, the Company redeemed all $35 million of its 7% fixed-rate senior notes. On June 27, 1997, the Company repaid all outstanding amounts due under the then existing revolving bank facility in the amount of $94.0 million. At December 31, 1997, the aggregate long-term debt maturing in the next five years is as follows: $149,000 (1998); $99,000 (1999); $18,000 (2000); $18,000 (2001); $126,019,000 (2002); and $225,115,000 (2003 and thereafter). (7) LEASES The Company leases certain computer equipment, vehicles and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $1.0 million for the successor company's six months ended December 31, 1997, $1.0 million, $1.6 million and $1.4 million for the predecessor company's six months ended June 30, 1997 and the years ended December 31, 1996 and 1995, respectively. Future commitments under leasing arrangements were not significant at December 31, 1997. (8) SHAREHOLDERS' EQUITY In November 1997, the Company awarded 110,915 shares of successor company common stock to employees as profit sharing and bonuses. These shares were issued in February 1998. On December 31, 1992, the Company issued 24,000 shares of Class II Serial Preferred Stock with a stated value of $100 per share. In preference to shares of predecessor company common stock, each share was entitled to cumulative cash dividends of $7.50 per year, payable quarterly. The Preferred Stock was subject to redemption at $100 per share at any time by the Company and was convertible into predecessor company common stock, at the holder's election, at any time after five years from the date of issuance at a conversion price of $15.00 per predecessor company common share. Holders of the Preferred F-13 55 Stock were entitled to one vote per preferred share. On March 31, 1997, the Company redeemed all of the outstanding Class II Series A preferred stock for $2.4 million in cash. In December 1996 and 1995, the Company awarded 36,077 and 26,085 shares of predecessor company common stock, respectively, to employees as profit sharing and bonuses. These shares were issued in each subsequent year. In November 1996, $1,250,000 of convertible subordinated debentures were converted by the debenture holders at the rate of one share of the Company's predecessor company common stock for each $20.15 of principal into 62,034 shares of predecessor company common stock. (9) STOCK OPTION PLANS In connection with the merger, certain executives of the predecessor company had agreed that they would not exercise or surrender certain stock options having an aggregate value of $1.8 million at June 27, 1997, based on the intrinsic value of the options (the difference between the exercise price of the options and a purchase price of $27 per share). These options were exchanged for 165,083 in new stock options of the successor company based on the intrinsic value of the predecessor company's options at the date of the transaction. The Company has an employee stock option plan which is authorized to issue up to 824,195 shares of common stock to officers and employees. The option price per share is the fair value of a share of common stock on the date of grant, as determined by the Company's board of directors. The expiration date of each option is fixed by the board of directors at not more than ten years from the date of grant. The options become exercisable from time to time over periods and upon terms and conditions as the board of directors determines. Current outstanding options become exercisable in 25% increments over a four-year period beginning one year from date of grant. As of December 31, 1997, there were 171,571 shares available for grant under the Plan. The Company has an employee stock option plan which is authorized to issue up to 1,070,000 shares of common stock to officers and employees. The exercise price of options may not be less than the fair market value of a share of common stock on the date of grant. Options expire on the tenth anniversary of the grant date unless cessation of employment causes earlier termination. The options became exercisable in 25% increments over a four-year period beginning one year from date of grant. The Company has a Non-Employee Directors Stock Option Plan authorizing the issuance of up to 120,000 shares of common stock. Options for 2,000 shares will be granted each year to each non-employee director. The exercise price of options under the Plan is equal to the fair market value on the date of grant. Options expire on the tenth anniversary of the grant date. The options become exercisable on the anniversary of the grant date at a rate of one third of the shares each year. Currently, non-employee directors of the Company are not compensated for their services. The Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25) and related Interpretations in accounting for its employee stock options because, as discussed below, the alternative fair value accounting provided for under SFAS 123, "Accounting for Stock-Based Compensation" requires use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, no compensation expense is recognized because the exercise price of the Company's employee stock options equals the market price of the underlying stock on the date of the grant. F-14 56 Pro forma information regarding net income is required by Statement 123, and has been determined as if the Company had accounted for its employee stock options under the fair value method of that Statement. The fair value for these stock options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 1995, 1996 and 1997 (predecessor and successor periods), respectively: risk-free interest rates of 6.4%, 6.5% and 6.1%; volatility factors of the expected market price of the Company's common stock of .36, .36 and near zero; dividend yield of zero; and a weighted-average expected life of the option of seven years. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its stock options. For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The Company's pro forma information for grants made after January 1, 1995, follows: net loss of $11,432,000 for the successor company's six months ended December 31, 1997, net loss of $12,387,000, net income of $14,286,000 and $5,016,000 for the predecessor company's six months ended June 30, 1997 and the years ended December 31, 1996 and 1995, respectively. The effects of applying Statement 123 for providing pro forma disclosures are not indicative of future amounts until the new rules are applied to all outstanding, nonvested awards. Stock option activity under the three plans consisted of the following:
SUCCESSOR COMPANY | PREDECESSOR COMPANY -------------------------- | ------------------------ WEIGHTED | WEIGHTED NUMBER AVERAGE | NUMBER AVERAGE OF EXERCISE | OF EXERCISE SHARES PRICE | SHARES PRICE ------------ ------------ | ------------ ----------- | BALANCE AT DECEMBER 31, 1994 | 288,000 $ 11.59 Granted | 260,000 16.37 Exercised | (2,250) 11.32 Forfeited | (1,000) 10.00 | ------------ BALANCE AT DECEMBER 31, 1995 | 544,750 13.88 Granted | 292,000 20.74 Exercised | (3,250) 12.38 Forfeited | (30,000) 15.75 | ------------ BALANCE AT DECEMBER 31, 1996 | 803,500 16.31 Exercised | (937) 16.38 Surrendered | (598,063) 15.61 Re-quantified and re-priced 165,083 $ .10 | (204,500) 18.34 Granted 652,624 10.82 | -- ------------ | ------------ BALANCE AT DECEMBER 31, 1997 817,707 8.66 | -- ============ | ============ OPTIONS EXERCISABLE AT DECEMBER 31, 1997 165,083 $ .10 | ============ |
The weighted average fair value of options granted during the years 1997, 1996 and 1995 were $1.98, $10.59 and $8.27 per share, respectively. The exercise price for the options outstanding as of F-15 57 December 31, 1997 ranged from $.10 to $10.82 per share. At December 31, 1997 the weighted average remaining contractual life of the outstanding options is 9.4 years. (10) TAXES The provision (benefit) for income taxes on continuing operations includes the following (in thousands):
| SUCCESSOR | COMPANY | PREDECESSOR COMPANY ------------- | ----------------------------------------- SIX MONTHS | SIX MONTHS ENDED | ENDED YEAR ENDED DECEMBER 31 | JUNE 30 DECEMBER 31 1997 | 1997 1996 1995 ------------- | --------------- ------------ ----------- CURRENT | Federal $ (345) | $ (1,397) $ 2,011 $ 1,103 State (41) | (111) 217 111 ------------- | --------------- ------------ ----------- (386) | (1,508) 2,228 1,214 DEFERRED | Federal (6,038) | 2,945 4,257 826 State (341) | 180 81 110 ------------- | --------------- ------------ ----------- (6,379) | 3,125 4,338 936 ------------- | --------------- ------------ ----------- TOTAL $ (6,765) | $ 1,617 $ 6,566 $ 2,150 ============= | =============== ============ ===========
The effective tax rate for continuing operations differs from the U.S. federal statutory tax rate as follows:
| SUCCESSOR | COMPANY | PREDECESSOR COMPANY ------------ | ---------------------------------------- SIX MONTHS | SIX MONTHS ENDED | ENDED YEAR ENDED DECEMBER 31 | JUNE 30 DECEMBER 31 1997 | 1997 1996 1995 ------------ | ------------ ------------ ------------ Statutory federal income tax rate 35.0 % | 35.0 % 35.0 % 34.0 % Increases (reductions) in taxes resulting from: | State income taxes, net of federal tax | benefit 2.0 | (.8) 1.9 1.7 Nonconventional fuel source tax credits -- | (3.8) (5.9) (10.0) Transaction-related expenses -- | (49.9) -- -- Statutory depletion 0.5 | -- (0.6) (0.3) Other, net (0.2) | -- (0.2) 0.2 | ------------ | ------------ ------------ ------------ Effective income tax rate for the period 37.3 % | (19.5) % 30.2 % 25.6 % ============ | ============ ============ ============
F-16 58 Significant components of deferred income tax liabilities and assets are as follows (in thousands):
DECEMBER 31 1997 -------------- Deferred income tax liabilities: Property and equipment, net $ 119,650 Other, net 433 -------------- Total deferred income tax liabilities 120,083 Deferred income tax assets: Accrued expenses 2,195 Inventories 80 Net operating loss carryforwards 12,019 Tax credit carryforwards 1,895 Other, net 463 Valuation allowance (1,863) -------------- Total deferred income tax assets 14,789 -------------- Net deferred income tax liability $ 105,294 ============== Long-term liability $ 107,996 Current asset (2,702) -------------- Net deferred income tax liability $ 105,294 ==============
SFAS No. 109 requires a valuation allowance to be recorded when it is more likely than not that some or all of the deferred tax assets will not be realized. The valuation allowance at December 31, 1997 relates principally to certain net operating loss carryforwards of the predecessor which management estimates will expire before they can be utilized. At December 31, 1997, the Company had approximately $33 million of net operating loss carryforwards available for federal income tax reporting purposes. Approximately $4 million of the net operating loss carryforwards are limited as to their annual utilization as a result of prior ownership changes. These net operating loss carryforwards, if unused, will expire from 2001 to 2006. The remaining net operating loss carryforwards will expire in 2012. The Company has alternative minimum tax credit carryforwards of approximately $1.8 million which have no expiration date. The Company has approximately $500,000 of statutory depletion carryforwards, which have no expiration date. (11) PROFIT SHARING AND RETIREMENT PLANS The Company has a non-qualified profit sharing arrangement under which the Company contributes discretionary amounts determined by the compensation committee of its Board of Directors. Amounts are allocated to substantially all employees based on relative compensation. The Company contributed $749,500 for the successor company's six months ended December 31, 1997, $588,900, $1,256,600 and $458,000 for the predecessor company's six months ended June 30, 1997 and the years ended December 31, 1996 and 1995, respectively, to the profit sharing plan of which one half was paid in cash and one half was paid in shares of the Company's common stock contributed into each eligible employee's 401(k) plan account. Additional discretionary bonuses are also made. The Company has a qualified defined contribution plan (a 401(k) plan) covering substantially all of the employees of the Company. Under the plan, an amount equal to 2% of participants' compensation is contributed by the Company to the plan each year. Eligible employees may also make voluntary contributions which the Company matches $.25 for every $1.00 contributed up to 6% of an employee's annual compensation. Effective January 1, 1998, the Company increased its match to $.50 for every $1.00 F-17 59 contributed up to 6% of an employee's annual compensation. Retirement plan expense amounted to $285,000 for the successor company's six months ended December 31, 1997, $266,000, $457,000 and $372,000 for the predecessor company's six months ended June 30, 1997 and the years ended December 31, 1996 and 1995, respectively. The Company also has non-qualified deferred compensation plans which permit certain key employees to elect to defer a portion of their compensation. (12) COMMITMENTS AND CONTINGENCIES The Company is involved in various legal actions arising in the normal course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the financial position of the Company. (13) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
| SUCCESSOR | COMPANY | PREDECESSOR COMPANY ------------- | ----------------------------------- SIX MONTHS | SIX MONTHS YEAR ENDED ENDED | ENDED DECEMBER 31 DECEMBER 31 | JUNE 30 ---------------------- (IN THOUSANDS) 1997 | 1997 1996 1995 ------------- | ---------- ---------- --------- CASH PAID DURING THE PERIOD FOR: | Interest $ 13,867 | $ 4,153 $ 7,830 $ 5,592 Income taxes (1,517) | 288 1,222 1,296 NON-CASH INVESTING AND FINANCING ACTIVITIES: | Acquisition of assets in exchange for | long-term liabilities -- | 792 -- 8,460 Debentures converted to common stock -- | 5,550 1,250 --
(14) FAIR VALUE OF FINANCIAL INSTRUMENTS The fair value of the financial instruments disclosed herein is not representative of the amount that could be realized or settled, nor does the fair value amount consider the tax consequences, if any, of realization or settlement. The amounts in the financial statements for cash equivalents, accounts receivable and notes receivable approximate fair value due to the short maturities of these instruments. The recorded amounts of outstanding bank and other long term debt approximate fair value because interest rates are based on LIBOR or the prime rate or due to the short maturities. The $225,000,000 in senior subordinated notes had an approximate fair value of $228,375,000 at December 31, 1997 based on rates available for similar instruments. The fair value of interest rate swaps was not material at December 31, 1997. F-18 60 (15) SUPPLEMENTARY INFORMATION ON OIL AND GAS ACTIVITIES The following disclosures of costs incurred related to oil and gas activities are presented in accordance with SFAS 69.
SUCCESSOR | COMPANY | PREDECESSOR COMPANY --------------- | -------------------------------------------------- SIX MONTHS | SIX MONTHS | ENDED | ENDED YEAR ENDED | DECEMBER 31 | JUNE 30 DECEMBER 31 | --------------------------------- (IN THOUSANDS) 1997 | 1997 1996 1995 --------------- | --------------- --------------- --------------- Acquisition costs | | Proved properties $ 13,501 | $ 9,249 $ 4,275 $ 79,464 Unproved properties 1,342 | 1,267 2,320 4,705 Developmental costs 21,822 | 11,322 30,750 19,906 Exploratory costs 5,980 | 4,380 6,131 4,968
The amounts reflected in the above table do not include the effects of purchase accounting which resulted from the TPG merger. See Note 1. PROVED OIL AND GAS RESERVES (UNAUDITED) The Company's proved developed and proved undeveloped reserves are all located within the United States. The Company cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made. The estimates of proved developed reserves have been reviewed by independent petroleum engineers. The estimates of proved undeveloped reserves were prepared by the Company's petroleum engineers and the December 31, 1997 proved undeveloped reserves have been reviewed by independent petroleum engineers. F-19 61 The following table sets forth changes in estimated proved and proved developed reserves for the periods indicated:
SUCCESSOR COMPANY PREDECESSOR COMPANY TOTAL --------------------------- --------------------------- --------------------------- OIL GAS OIL GAS OIL GAS (BBL) (MCF) (BBL) (MCF) (BBL) (MCF) ------------ ------------ ------------ ------------ ------------ ------------ DECEMBER 31, 1994 4,113,470 122,991,609 4,113,470 122,991,609 Extensions and discoveries 229,957 22,287,564 229,957 22,287,564 Purchase of reserves in place 2,197,414 111,360,991 2,197,414 111,360,991 Sale of reserves in place (28,693) (278,013) (28,693) (278,013) Revisions of previous estimates 326,771 (419) 326,771 (419) Production (555,913) (16,961,424) (555,913) (16,961,424) ------------ ------------ ------------ ------------ DECEMBER 31, 1995 6,283,006 239,400,308 6,283,006 239,400,308 Extensions and discoveries 387,414 38,079,620 387,414 38,079,620 Purchase of reserves in place 336,279 8,182,402 336,279 8,182,402 Sale of reserves in place (7,664) (250,021) (7,664) (250,021) Revisions of previous estimates 1,108,538 28,601,277 1,108,538 28,601,277 Production (718,667) (25,410,233) (718,667) (25,410,233) ------------ ------------ ------------ ------------ DECEMBER 31, 1996 7,388,906 288,603,353 7,388,906 288,603,353 Extensions and discoveries 244,242 26,550,917 282,999 12,142,158 527,241 38,693,075 Purchase of reserves in place 78,149 20,093,436 71,905 13,191,547 150,054 33,284,983 Sale of reserves in place (12,780) (400,196) (21,196) (337,814) (33,976) (738,010) TPG merger 6,514,982 276,776,629 (6,514,982) (276,776,629) Revisions of previous estimates (899,930) (16,909,297) (826,900) (24,075,426) (1,726,830) (40,984,723) Production (372,651) (14,466,129) (380,732) (12,747,189) (753,383) (27,213,318) ------------ ------------ ------------ ------------ ------------ ------------ DECEMBER 31, 1997 5,552,012 291,645,360 -- -- 5,552,012 291,645,360 ============ ============ ============ ============ ============ ============ PROVED DEVELOPED RESERVES December 31, 1995 5,592,579 206,998,924 5,592,579 206,998,924 ============ ============ ============ ============ December 31, 1996 6,410,344 225,693,651 6,410,344 225,693,651 ============ ============ ============ ============ December 31, 1997 4,830,163 251,851,000 4,830,163 251,851,000 ============ ============ ============ ============
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (UNAUDITED) The following tables, which present a standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves, are presented pursuant to SFAS No. 69. In computing this data, assumptions other than those required by the FASB could produce different results. Accordingly, the data should not be construed as representative of the fair market value of the Company's proved oil and gas reserves. The following assumptions have been made: - Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements. - Production and development costs were computed using year-end costs assuming no change in present economic conditions. - Future net cash flows were discounted at an annual rate of 10%. - Future income taxes were computed using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion. F-20 62 The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is presented below:
DECEMBER 31 ------------------------------------------------ 1997 1996 1995 -------------- -------------- -------------- (IN THOUSANDS) Estimated future cash inflows (outflows) Revenues from the sale of oil and gas $ 876,464 $ 1,087,997 $ 679,286 Production and development costs (355,165) (419,504) (293,601) -------------- -------------- -------------- Future net cash flows before income taxes 521,299 668,493 385,685 Future income taxes (130,306) (185,768) (80,715) -------------- -------------- -------------- Future net cash flows 390,993 482,725 304,970 10% timing discount (171,273) (223,496) (134,053) -------------- -------------- -------------- Standardized measure of discounted future net cash flows $ 219,720 $ 259,229 $ 170,917 ============== ============== ==============
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):
YEAR ENDED DECEMBER 31 ----------------------------------------------- 1997 1996 1995 ------------- ------------- --------------- (IN THOUSANDS) Beginning of year $ 259,229 $ 170,917 $ 89,854 Sale of oil and gas, net of production costs (61,088) (58,023) (32,874) Extensions and discoveries, less related estimated future development and production costs 54,979 60,738 24,441 Purchase of reserves in place less estimated future production costs 33,233 10,694 104,270 Sale of reserves in place less estimated future production costs (588) (191) (329) Revisions of previous quantity estimates (43,111) 38,204 1,129 Net changes in prices and production costs (73,956) 83,530 (4,723) Change in income taxes 19,618 (55,494) (17,756) Accretion of 10% timing discount 35,596 21,425 11,647 Changes in production rates (timing) and other (4,192) (12,571) (4,742) ------------- ------------- --------------- End of year $ 219,720 $ 259,229 $ 170,917 ============= ============= ===============
F-21 63 (16) INDUSTRY SEGMENT FINANCIAL INFORMATION The table below presents certain financial information regarding the Company's industry segments of its continuing operations. Intersegment sales are billed on an intercompany basis at prices for comparable third party goods and services.
SUCCESSOR | COMPANY | PREDECESSOR COMPANY ---------- | ------------------------------------ SIX MONTHS | SIX MONTHS ENDED | ENDED YEAR ENDED DECEMBER 31 DECEMBER 31| JUNE 30 ----------------------- (IN THOUSANDS) 1997 | 1997 1996 1995 ---------- | ---------- ---------- ---------- REVENUES | | Oil and gas operations $ 66,958 | $ 63,248 $ 124,294 $ 88,632 Oilfield sales and service 19,929 | 18,698 32,827 25,178 Intersegment sales (4,388) | (4,033) (7,310) (5,112) | --------- | --------- --------- --------- $ 82,499 | $ 77,913 $ 149,811 $ 108,698 ========= | ========= ========= ========= OPERATING INCOME | Oil and gas operations $ (4,872) | $ 10,757 $ 24,756 $ 12,444 Oilfield sales and service 525 | (24) 963 673 --------- | --------- --------- --------- $ (4,347) | $ 10,733 $ 25,719 $ 13,117 ========= | ========= ========= ========= IDENTIFIABLE ASSETS | Oil and gas operations $ 572,170 | $ 281,761 $ 274,021 Oilfield sales and service 27,150 | 20,492 20,348 --------- | --------- --------- $ 599,320 | $ 302,253 $ 294,369 ========= | ========= ========= DEPRECIATION, DEPLETION AND | AMORTIZATION EXPENSE | Oil and gas operations $ 30,923 | $ 14,777 $ 28,598 $ 18,729 Oilfield sales and service 771 | 589 1,154 988 --------- | --------- --------- --------- $ 31,694 | $ 15,366 $ 29,752 $ 19,717 ========= | ========= ========= ========= CAPITAL EXPENDITURES | Oil and gas operations $ 37,235 | $ 27,184 $ 35,486 $ 129,219 Oilfield sales and service 541 | 1,428 1,240 4,735 --------- | --------- --------- --------- $ 37,776 | $ 28,612 $ 36,726 $ 133,954 ========= | ========= ========= =========
No customer exceeded 10% of consolidated revenue during the periods ended June 30, 1997 and December 31, 1997 and the year ended December 31, 1996. One customer exceeded 10% of consolidated revenue during the year ended December 31, 1995 which amounted to $11.1 million. F-22 64 (17) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The results of operations for the four quarters of 1997 and 1996 are shown below (in thousands).
PREDECESSOR COMPANY | SUCCESSOR COMPANY ---------------------------- | -------------------------- FIRST SECOND | THIRD FOURTH ------------ ------------ | ----------- ------------ 1997 | ---- | | Sales and other operating revenues $ 41,546 $ 36,367 | $ 38,382 $ 44,038 Gross profit (loss) 9,512 4,135 | (1,346) (591) Net income (loss) 4,847 (14,720) | (5,810) (5,562) PREDECESSOR COMPANY ---------------------------------------------------------- FIRST SECOND THIRD FOURTH ------------ ------------ ----------- ------------ 1996 ---- Sales and other operating revenues $ 38,359 $ 32,542 $ 36,571 $ 42,339 Gross profit 7,965 7,087 7,270 8,966 Net income 3,425 3,402 3,186 4,742
(18) DISCONTINUED OPERATIONS In September 1995, the Company announced plans to sell Engine Power Systems, Inc. ("EPS"), its wholly-owned subsidiary engaged in engine, parts and service sales. The Company was unable to identify an acceptable buyer for EPS by the end of 1996. A substantial portion of the workforce was eliminated and substantial assets were sold and the Company recognized an additional charge in 1996 to reduce the remaining assets to net realizable value. The remaining assets were sold in 1997. Net revenues generated by EPS were approximately $3.9 million in 1996 and $4.2 million in 1995. Loss from operations of discontinued business was $180,000 ($117,000 net of tax benefit) in 1996 and $760,000 ($492,000 net of tax benefit) in 1995. Estimated loss on disposal was $495,000 ($322,000 net of tax benefit) in 1996 and $1,001,000 ($647,000 net of tax benefit) in 1995. The results of operations of EPS are presented as discontinued operations in the accompanying financial statements for all periods presented. (19) SALE OF TAX CREDIT PROPERTIES In February and March 1996, the Company sold certain interests that qualify for the nonconventional fuel source tax credit. The interests were sold in two separate transactions for approximately $750,000 and $100,000, respectively, in cash and a volumetric production payment under which 100% of the cash flow from the properties will go to the Company until approximately 11.7 Bcf and 3.4 Bcf, respectively, of gas has been produced and sold. In addition to receiving 100% of the cash flow from the properties, the Company will receive quarterly incentive payments based on production from the interests. The Company has the option to repurchase the interests at a future date. (20) HEDGING ACTIVITIES From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas price volatility. The Company employs a policy of hedging gas production sold under NYMEX based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. Under the deferral method gains and losses on these instruments are deferred on the balance sheet and are included as an adjustment to gas revenue for the production being hedged in the contract month. The Company incurred pretax losses on its hedging activities of $116,000 in 1997 and $258,000 in 1996. During October 1997, the Company hedged 3.1 Bcf of 1998 gas production at a weighted average NYMEX price of $2.37 per Mcf which represented a net unrealized gain of $422,000 at December 31, 1997. At December 31, 1996, the Company did not have any open futures contracts. During February F-23 65 1998, the Company hedged 1.4 Bcf of 1998 and 1999 gas production at a weighted average NYMEX price of $2.44 per Mcf. (21) SUBSEQUENT EVENTS (UNAUDITED) On March 19, 1998, the Company entered into an agreement with FirstEnergy Corp. ("FirstEnergy") to form an equally owned joint venture to be named FE Holdings, L.L.C. ("FE Holdings") to engage in the exploration for, development, production, transportation and marketing of natural gas. Under the agreement, the Company will provide FE Holdings with its gas marketing, operational and management expertise. FirstEnergy, a diversified energy services holding company headquartered in Akron, Ohio, comprises the nation's twelfth largest investor-owned electric utility system. Its electric utility operating companies - -- Ohio Edison Company and its subsidiary, Pennsylvania Power Company; The Illuminating Company; and Toledo Edison Company -- serve 2.2 million customers within 13,200 square miles of northern and central Ohio and western Pennsylvania. FirstEnergy produces approximately $5 billion in annual revenues and owns more than $18 billion in assets, including ownership in 18 power plants. In an expansion of its energy-related products and services, FirstEnergy in December 1997 acquired Roth Bros., Inc., and RPC Mechanical, Inc., which form one of the nation's largest providers of engineered heating, ventilating and air-conditioning equipment and energy management and control systems. The joint venture is expected to substantially expand the Company's market outlet for its production of natural gas and more fully utilize the capabilities and capacity of the Company's Gas Marketing Division. The venture will allow FirstEnergy to offer its customers total energy services, including natural gas, electricity and related energy products and services. The Company and FirstEnergy have also agreed to have FE Holdings acquire Marbel Energy Corporation ("Marbel"), a privately-held, fully integrated natural gas company headquartered in Canton, Ohio. Marbel owns interests in more than 1,800 gas and oil wells and holds interests in more than 200,000 undeveloped acres in eastern and central Ohio. Marbel's subsidiaries include MB Operating Company, Inc., a natural gas exploration and production company, and Northeast Ohio Operating Companies, Inc. ("NOOC"), a public utility holding company based in Lancaster, Ohio. NOOC owns and operates over 1,300 miles of gas gathering lines and a local gas distribution company with more than 3,000 customers in eastern and central Ohio. The acquisition of Marbel will provide FE Holdings with a base of exploration, development and production capability, along with utility transportation and distribution capability. Marbel's net production in 1997 was approximately 6.3 Bcfe. At September 30, 1997, Marbel had estimated proved developed oil and gas reserves of 55.7 Bcfe. F-24 EX-21 2 EXHIBIT 21 1 Exhibit 21 SUBSIDIARIES OF THE REGISTRANT SUBSIDIARY STATE OF INCORPORATION The Canton Oil & Gas Company Ohio Target Oilfield Pipe & Supply Company Ohio Ward Lake Drilling, Inc. Michigan Peake Energy, Inc. Delaware As of December 31, 1997, the other subsidiaries included in the registrant's consolidated financial statements, and all other subsidiaries considered in the aggregate as a single subsidiary, did not constitute a significant subsidiary. EX-23 3 EXHIBIT 23 1 Exhibit 23 CONSENT OF INDEPENDENT AUDITORS To the Shareholders and Board of Directors Belden & Blake Corporation We consent to the incorporation by reference of our report dated March 5, 1998, with respect to the consolidated financial statements of Belden & Blake Corporation included in the Annual Report (Form 10-K) for the year ended December 31, 1997, in the following Registration Statements and related Prospectuses. REGISTRATION NUMBER DESCRIPTION OF REGISTRATION STATEMENT - ----------------------- ---------------------------------------------------- 33-62785 Stock Option Plan; Non-Employee Director Stock Option Plan -- Form S-8 33-69802 Employee's 401(K) Profit Sharing Plan -- Form S-8 ERNST & YOUNG LLP Cleveland, Ohio March 23, 1998 EX-27 4 EXHIBIT 27
5 0000880114 BELDEN & BLAKE CORPORATION 1,000 U.S. DOLLARS YEAR DEC-31-1997 JAN-01-1997 DEC-31-1997 1 6,552 0 35,743 0 9,614 58,663 546,179 31,036 599,320 38,817 355,649 0 0 1,000 95,858 599,320 160,333 163,523 90,473 90,473 80,311 0 19,132 (26,393) (5,148) (21,245) 0 0 0 (21,245) 0 0
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