-----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, BGGXr5ft8xsIwof5DilDXuD7BmZ40LOJs670npYl7v8wNfVwu1AGOMv3B24X91bl g9GUTJxde8EjZ1SWW1M2nQ== 0000950152-02-002336.txt : 20020415 0000950152-02-002336.hdr.sgml : 20020415 ACCESSION NUMBER: 0000950152-02-002336 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20011231 FILED AS OF DATE: 20020326 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: 1934 Act SEC FILE NUMBER: 000-20100 FILM NUMBER: 02585946 BUSINESS ADDRESS: STREET 1: 5200 STONEHAM RD STREET 2: P O BOX 2500 CITY: NORTH CANTON STATE: OH ZIP: 44720 BUSINESS PHONE: 3304991660 MAIL ADDRESS: STREET 1: 5200 STONEHAM RD STREET 2: P O BOX 2500 CITY: NORTH CANTON STATE: OH ZIP: 44720 FORMER COMPANY: FORMER CONFORMED NAME: BELDEN & BLAKE ENERGY CORP /OH DATE OF NAME CHANGE: 19920427 10-K405 1 l92370ae10-k405.txt BELDEN & BLAKE CORPORATION 10-K405 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, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File No. 0-20100 BELDEN & BLAKE CORPORATION (Exact name of registrant as specified in its charter) OHIO 34-1686642 (State or other jurisdiction (I.R.S. Employer Identification Number) of incorporation or organization) 5200 STONEHAM ROAD NORTH CANTON, OHIO 44720 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (330) 499-1660 Securities registered pursuant to Section 12(b) of the Act: NONE Securities registered pursuant to Section 12(g) of the Act: COMMON STOCK, WITHOUT PAR VALUE (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X --- As of February 28, 2002, Belden & Blake Corporation had outstanding 10,314,035 shares of common stock, without par value, which is its only class of stock. The common stock of Belden & Blake Corporation is not traded on any exchange and, therefore, its aggregate market value and the value of shares held by non-affiliates cannot be determined. DOCUMENTS INCORPORATED BY REFERENCE None. The information in this document includes forward-looking statements that are made pursuant to Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements "should," "believe," "expect," "anticipate," "intend," "will," "continue," "estimate," "plan," "outlook," "may," "future," "projection," variations of these statements and similar expressions are forward-looking statements. These forward-looking statements are based on current expectations and projections about future events. Forward-looking statements, and the business prospects of Belden & Blake Corporation (the "Company") are subject to a number of risks and uncertainties which may cause the Company's actual results in future periods to differ materially from the forward-looking statements contained herein. These risks and uncertainties include, but are not limited to, the Company's access to capital, the market demand for and prices of oil and natural gas, the Company's oil and gas production and costs of operation, results of the Company's future drilling activities, the uncertainties of reserve estimates, general economic conditions, new legislation or regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described in the Company's 10-K and 10-Q reports and other filings with the Securities and Exchange Commission ("SEC"). PART I - ------ Item 1. BUSINESS -------- GENERAL Belden & Blake Corporation is a privately held company owned by TPG Partners II L.P. ("TPG") and certain other investors. The Company is an independent energy company engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. The Company provides oilfield services to itself and third-party customers through its Arrow Oilfield Service Company ("Arrow"). Until 1995, the Company conducted business exclusively in the Appalachian Basin where it has operated since 1942 through several predecessor entities. It is currently among 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 production and drilling operations in the Michigan Basin through the acquisition of Ward Lake Drilling, Inc. ("Ward Lake"), an independent energy company, which owns and operates oil and gas properties in Michigan's lower peninsula. On March 17, 2000, the Company sold a subsidiary which owned oil and gas properties in West Virginia and Kentucky. At December 31, 2001, the Company operated in Ohio, Pennsylvania, New York, Michigan, Indiana and West Virginia. At December 31, 2001, the Company's net production was approximately 51.8 Mmcf (million cubic feet) of natural gas and 1,651 Bbls (barrels) of oil per day. At that date, the Company owned interests in 6,262 gross (5,238 net) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with proved reserves totaling 334 Bcf (billion cubic feet) of natural gas and 5.6 Mmbbl (million barrels) of oil. The estimated future net cash flows from these reserves had a present value (discounted at 10 percent) before income taxes of approximately $225 million at December 31, 2001. The weighted average prices related to proved reserves at December 31, 2001 were $2.92 per Mcf (thousand cubic feet) for natural gas and $17.85 per Bbl for oil. At December 31, 2001, the Company operated approximately 5,723 wells, including wells operated for third parties. At that date, the Company held leases on 1,185,538 gross (1,053,286 net) acres, including 734,933 gross (643,574 net) undeveloped acres. The Company owned and operated 1,610 miles of gas gathering systems with access to the commercial and industrial gas markets of the northeastern United States at December 31, 2001. 1 The Company has a successful track record of reserve replacement and growth through both drilling and acquisitions. Since its formation in 1992 through December 31, 2001, the Company has added approximately 438 Bcfe (billion cubic feet of natural gas equivalent) of proved developed reserves through drilling and acquisitions at an average cost of $0.81 per Mcfe (thousand cubic feet of natural gas equivalent). This represented approximately 197% of the oil and gas produced by the Company during that period. During 2001, the Company drilled 175 gross (149.0 net) wells at a direct cost, including exploratory dry hole expense, of approximately $24.6 million for the net wells. The 2001 drilling activity added 22.9 Bcfe of proved developed reserves at an average cost of $1.08 per Mcfe. The Company also made production enhancements to existing wells during the year which increased proved developed reserves by 4.3 Bcfe at an average cost of $0.51 per Mcfe. Acquisitions of properties in 2001 added 1.9 Bcfe of proved developed reserves at an average cost of $0.91 per Mcfe. Proved developed reserves added through drilling, enhancements and acquisitions in 2001 represented approximately 130% of 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 During 2001, the Company benefited from high natural gas prices. To take advantage of the high market prices, the Company locked-in natural gas prices on over 12.6 Bcf of its natural gas production in 2001 by entering into fixed price gas contracts and through financial gas hedging instruments. The Company also locked-in natural gas prices on over 13.3 Bcf of its natural gas production in 2002 and 10.7 Bcf of its production in 2003 by entering into fixed price gas contracts and through financial gas hedging instruments. In January 2002, the Company monetized $22.7 million of these positions and entered into additional gas hedging instruments for 2002. See Note 19 to the Consolidated Financial Statements. In 2001, the Company executed a leasing and geophysical program that resulted in acquiring over 100,000 acres and shooting over 100 miles of seismic in the deeper, less developed Trenton Black River ("TBR") trend in the Appalachian Basin. As of February 1, 2002, the Company had approximately 286,000 gross (198,000 net) acres under lease in the TBR trend area. The Company believes this acreage and seismic program, coupled with recent strategic alliances, has enhanced its position to explore the TBR. The Company plans exploratory drilling on this acreage in 2002. In addition, the Company plans to continue to shoot additional seismic and lease additional Trenton Black River acreage in 2002. On June 29, 2001, the Company amended its $100 million revolving credit facility ("the Revolver") from Ableco Finance LLC and Foothill Capital Corporation. The amendment extended the Revolver's final maturity date to April 22, 2004, from August 23, 2002, increased the letter of credit sub-limit from $20 million to $30 million and eliminated the effects of Statement of Financial Accounting Standards No. (SFAS) 133, "Accounting for Derivative Instruments and Hedging Activities," from financial covenant calculations. On March 17, 2000, the Company sold the stock of Peake Energy, Inc. ("Peake"), a wholly owned subsidiary which owned oil and gas properties in West Virginia and Kentucky. The sale resulted in net proceeds of approximately $69.2 million, which were used to reduce bank debt. At the time of the sale, Peake accounted for approximately 20% of the Company's production and approximately 20% of its proved oil and gas reserves. 2 When gas prices declined sharply in 1998, the Company's previous lenders reduced the Company's borrowing base from $170 million to $126 million in January of 1999. The Company's outstanding borrowings at that time exceeded the redetermined borrowing base by $28 million. The resulting liquidity shortage forced the Company to cease virtually all drilling in 1999 and to dispose of certain non-strategic businesses and properties to reduce the Company's debt. These included the Company's oilfield supply business, Target Oilfield Pipe and Supply Company ("TOPS"), Belden Energy Services Company ("BESCO"), the Company's retail natural gas marketing outlet in Ohio, and various oil and gas properties representing approximately 0.8 Bcfe of oil and gas reserves. DESCRIPTION OF BUSINESS OVERVIEW The Company conducts operations in the United States in one reportable segment which is oil and gas exploration and production. The Company is actively engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. The Company operates exclusively in the Appalachian and Michigan Basins (a region which includes Ohio, Pennsylvania, New York, Michigan, Indiana and West Virginia) where it is one of the largest oil and gas companies in terms of reserves, acreage held and wells operated. 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 natural gas is currently produced primarily from shallow, highly developed blanket formations at depths of 1,000 to 6,200 feet. Drilling completion 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 completion rates at these shallower depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the Appalachian Basin. As a result of this environment, there has been limited testing or development of the formations below the existing shallow production in the Appalachian Basin. 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. The Company currently holds approximately 286,000 gross (198,000 net) leasehold acres and approximately 500 miles of seismic in the deeper, less developed Trenton Black River formations in the Appalachian Basin and intends to continue to lease additional acreage and shoot additional seismic. The Company plans to drill 26 gross (11.9 net) wells in the TBR formations in 2002. The Company currently operates 90 coalbed methane ("CBM") wells in Pennsylvania and holds leases on approximately 95,000 acres of CBM properties in Pennsylvania and 37,000 acres of CBM properties in West Virginia. The Company drilled 27 CBM wells in 2001 and plans to drill an additional 54 CBM wells in 2002. In January 1995, the Company purchased Ward Lake Drilling, Inc., a privately held energy company headquartered in Gaylord, Michigan, and commenced operations in the Michigan Basin. The Company's primary objective in acquiring Ward Lake was to allow the Company to pursue exploration 3 and production opportunities in the Michigan Basin with an established operating company that provided the critical mass to operate efficiently. Ward Lake currently operates 780 wells producing approximately 37.5 Mmcf (18.9 Mmcf net) of natural gas per day in Michigan. The Company's rationale for entering the Michigan Basin was based on geologic and operational similarities to the Appalachian Basin, geographic proximity to the Company's operations in the Appalachian Basin and proximity to premium gas markets. Geologically, the Michigan Basin resembles 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 the Michigan Basin 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 2,000 feet) blanket Antrim Shale formation. Completion 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. 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 proximity of the Appalachian and Michigan Basins to large commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices compared with the New York Mercantile Exchange's ("NYMEX") price for gas delivered at the Henry Hub in Louisiana. Monthly spot natural gas prices in the Company's market areas are typically ten to fifty cents per Mcf higher than comparable NYMEX prices. BUSINESS STRATEGY The Company seeks to increase shareholder value by increasing reserves, production and cash flow through the exploration and development of the Company's extensive acreage base; further improvement in profit margins through operational efficiencies; and utilization of the Company's advanced technology to enhance production and reserves discovered. The key elements of the Company's current strategy are as follows: - - MAINTAIN A BALANCED DRILLING PROGRAM. The Company's exploration and development activities focus on a well-balanced portfolio of development and exploratory drilling in both the shallow blanket formations and the deeper, potentially more prolific formations. The Company believes this portfolio approach, coupled with its extensive knowledge of its operating areas, allows the Company to enhance economic returns and minimize much of the geological risk associated with oil and gas exploration and development. 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 in the shallow coalbed methane formations in western Pennsylvania. The Company has identified numerous development and exploratory drilling locations in the deeper formations of these Basins, such as the Trenton Black River, and has established a substantial leasehold position overlying potentially productive coalbed methane formations in western Pennsylvania. In 2002, the Company plans to spend approximately 60% of its drilling capital expenditures on shallow blanket formations and approximately 40% of its drilling capital expenditures on deeper, potentially more prolific prospects. 4 - - IMPROVE THE COMPANY'S FINANCIAL POSITION. At December 31, 2001, the Company had a deficit in shareholders' equity of $27.3 million. The Company may sell additional non-strategic assets and use the proceeds, along with a portion of its available cash flow, to reduce its debt burden and enhance liquidity. The Company may also attempt to restructure portions of its existing debt to further reduce the amount of debt outstanding. - - UTILIZE ADVANCED TECHNOLOGY. The combination of long-lived production and high drilling completion rates at the shallow depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the Appalachian and Michigan Basins. The Company has applied more advanced technology, including 3-D seismic, horizontal drilling, advanced fracturing techniques and production enhancement technologies to improve drilling completion rates, reserves discovered per well, production rates, reserve recovery rates and total economics in its operating areas. - - IMPROVE PROFIT MARGINS. To become one of the most efficient operators in the Appalachian and Michigan Basins, the Company strives to improve its profit margins on production from existing and acquired properties through advanced production technologies, operating efficiencies and mechanical improvements. Through its production field offices, the Company reviews its properties, especially newly acquired properties, to determine what actions can be taken to reduce operating costs and/or improve production. The Company strives to control 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, redesigning downhole equipment and recompleting existing wells. - - EVALUATE POTENTIAL ACQUISITIONS. The Company may seek to acquire properties that complement its operations, provide exploration and development opportunities and potentially provide superior returns on investment. OIL AND GAS OPERATIONS AND PRODUCTION Operations. The Company operates 91% of the wells in which it holds working interests. It 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 deliverability enhancement techniques. The Company currently maintains production field offices in Ohio, Pennsylvania, New York and Michigan. Through these offices, the Company reviews its properties to determine what action can be taken to reduce operating costs and/or improve production. The Company has also 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. Arrow, the Company's service division, provides the Company and third-party customers with necessary oilfield services such as well workovers, well completions, brine hauling and disposal and oil trucking. The Company currently operates approximately 1,610 miles of natural gas gathering lines in Ohio, Pennsylvania, New York and Michigan which are connected directly to various intrastate and interstate natural gas transmission systems. The interconnections with these pipelines afford the Company potential marketing access to numerous gas markets. 5 Production, Sales Prices and Costs. The following table sets forth certain information regarding the Company's net oil and natural gas production, revenues and expenses for the years indicated:
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------ 1997 1998 1999 2000 2001 ----------- ------------ ----------- ----------- ----------- PRODUCTION Gas (Mmcf) 27,213 30,140 26,988 20,037 18,541 Oil (Mbbl) 753 768 713 592 646 Total production (Mmcfe) 31,734 34,750 31,267 23,591 22,415 AVERAGE PRICE Gas (per Mcf) $ 2.65 $ 2.57 $ 2.50 $ 3.17 $ 4.34 Oil (per Bbl) 18.10 12.61 16.57 27.29 23.04 Mcfe 2.70 2.51 2.54 3.38 4.26 AVERAGE COSTS (PER Mcfe) Production expense 0.68 0.68 0.70 0.89 1.01 Production taxes 0.10 0.09 0.10 0.10 0.11 Depletion 1.21 1.66 0.92 0.77 0.91 OPERATING MARGIN (PER Mcfe) 1.92 1.74 1.74 2.39 3.14
Mmcf - Million cubic feet Mmcfe - Million cubic feet equivalent Bbl - barrel Mbbl - Thousand barrels Mcf - Thousand cubic feet Operating margin (per Mcfe) - average price less production expense and production taxes The following table sets forth certain information regarding the Company's net oil and natural gas production, revenues and expenses for the years indicated excluding Peake. See Note 3 to the Consolidated Financial Statements:
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------ 1997 1998 1999 2000 2001 ----------- ------------ ----------- ----------- ----------- PRODUCTION Gas (Mmcf) 22,882 24,495 21,515 18,882 18,541 Oil (Mbbl) 658 686 642 576 646 Total production (Mmcfe) 26,828 28,613 25,367 22,339 22,415 AVERAGE PRICE Gas (per Mcf) $ 2.57 $ 2.48 $ 2.50 $ 3.20 $ 4.34 Oil (per Bbl) 18.04 12.57 16.51 27.36 23.04 Mcfe 2.63 2.43 2.54 3.41 4.26 AVERAGE COSTS (PER Mcfe) Production expense 0.70 0.69 0.74 0.90 1.01 Production taxes 0.07 0.05 0.07 0.09 0.11 Depletion 1.23 1.71 0.98 0.77 0.91 OPERATING MARGIN (PER Mcfe) 1.86 1.69 1.73 2.42 3.14
Mmcf - Million cubic feet Mmcfe - Million cubic feet equivalent Bbl - barrel Mbbl - Thousand barrels Mcf - Thousand cubic feet Operating margin (per Mcfe) - average price less production expense and production taxes 6 EXPLORATION AND DEVELOPMENT The Company's exploration and development activities include development and exploratory drilling in both the highly developed or blanket formations and the less developed formations of the Appalachian and Michigan 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 2001, the Company drilled 145 gross (133.6 net) wells to highly developed or shallow blanket formations in its operating area at a direct cost of approximately $21.1 million, including exploratory dry hole expense, for the net wells. The Company also drilled 30 gross (15.4 net) wells to less developed and deeper formations in 2001 at a direct cost of approximately $3.5 million, including exploratory dry hole expense, for the net wells. The result of this drilling activity is shown in the table on page 11. In 2002, the Company expects to spend approximately $26.6 million, including exploratory dry hole expense, on development and exploratory drilling of approximately 155 gross (114.6 net) wells. In 2002, the Company plans to spend approximately 60% of its drilling capital expenditures on shallow blanket formations and approximately 40% of its drilling capital expenditures on deeper, potentially more prolific prospects. 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 or Blanket Formations. In general, the highly developed or blanket formations found in the Appalachian and Michigan Basins are widespread in extent and hydrocarbon accumulations are not dependent upon local stratigraphic or structural trapping. Drilling completion rates of the Company and others drilling these formations historically have exceeded 90%. The principal risk of such wells is uneconomic recoverable reserves. The Company is a pioneer in coalbed methane development and production in Pennsylvania, presently operating 90 coalbed methane gas wells in Indiana and Fayette counties. CBM wells in this area range in depth from 1,200 to 1,500 feet and typically encounter three to six unmined coal seams. In September 2001, the Company acquired its partner's 40% working interest in the Blacklick CBM field giving the Company 100% ownership of this CBM project. With approximately 95,000 CBM acres currently under lease in Pennsylvania and 37,000 acres in West Virginia, the Company believes the CBM will contribute significantly to its drilling portfolio. The Company plans to drill 54 CBM wells in 2002 including seven exploratory wells to test three new areas in southwestern Pennsylvania. 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. The Company plans to drill 50 gross (33.7 net) wells to the Antrim Shale formation in 2002, including 15 wells on a 2,500 acre undeveloped lease acquired in January 2002. This lease includes 29 Antrim drill sites and has proved undeveloped reserves of 10.4 Bcfe which are not included in the Company's December 31, 2001 reserves. 7 Certain typical characteristics of the highly developed or blanket formations targeted by the Company are described below: Range of Average Range of Average Drilling and Gross Reserves Range of Well Completion Costs per Completed Depths per Well Well ---------------- --------------------- ---------------- (in feet) (in thousands) (in Mmcfe) Ohio: Clinton 3,000 - 5,500 $ 125 - 185 80 - 150 Pennsylvania: Coalbed Methane 1,200 - 1,500 125 - 150 150 - 250 Clarendon 1,100 - 2,000 45 - 55 30 - 50 Medina 5,000 - 6,200 170 - 210 150 - 300 New York: Medina 3,000 - 5,000 100 - 150 75 - 300 Michigan: Antrim 700 - 2,000 190 - 240 400 - 600 Deeper or 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 completion rates in the shallow formations has curbed the development of the deeper formations in the basin. The Company believes it possesses the technological expertise and the acreage position needed to explore the deeper formations in a cost effective manner. The Trenton Black River formations have received significant attention recently in the Appalachian Basin. Based on historical information available in public records, wells completed in the TBR have reserves in the range of 1.0 to 2.5 Bcf of natural gas per well. With significant discoveries by other operators in south-central New York and in central West Virginia, the Company believes the potential exists for numerous opportunities in the Company's existing areas of operations. While expected geologic conditions and gas shows were encountered in all tests which the Company has undertaken in the TBR since 1998, economic production has not been established to date. On June 29, 2001, the Company and Triana Energy, LLC ("Triana"), a West Virginia oil and gas exploration company, entered into an exploration agreement and a joint operating agreement ("JOA"). Pursuant to the JOA, Triana will manage the exploration of the Oriskany and Trenton Black River formations on certain properties in which the Company owns the leasehold working interest in Pennsylvania and New York. It is anticipated that the Company's contribution of its leasehold acreage coupled with the experience and professional skills contributed by Triana should enhance the Company's drilling program with respect to these properties and formations. Triana will manage all exploration and drilling activities performed on the properties covered by this agreement. The Company will be the operator following the completion of the wells. This agreement is in effect until June 29, 2006. The Company has also entered into several exploration agreements with other industry participants to jointly explore and develop the TBR in areas of New York and Ohio. 8 In 2001, the Company implemented a major leasing and geophysical program in the TBR that resulted in acquiring over 100,000 additional acres and more than 100 miles of additional seismic. As of February 1, 2002, the Company had 286,000 gross (198,000 net) acres under lease in the TBR. The Company believes this acreage and seismic program, coupled with recent strategic alliances, has enhanced its position to explore the TBR. Exploration and drilling activities in the TBR formations, found at depths ranging from 5,000 to 12,000 feet, are focused on testing many of the currently identified prospects and confirming potential future drill sites. In 2002, the Company anticipates spending approximately $7.0 million to drill 26 gross (11.9 net) wells on TBR acreage. In addition, the Company plans to spend $5.3 million to acquire additional acreage and seismic data in the TBR. The less developed formations in the Appalachian Basin also include the Knox sequence of sandstones and dolomites, which includes the Rose Run, Beekmantown and Trempealeau productive zones, at depths ranging from 2,500 feet to 8,000 feet. The Company is an industry leader in the exploration, development, and production from Knox formation wells. The geographical boundaries of the Knox are generally well defined in Ohio with less definition in New York and Pennsylvania. Through 2001, the Company had drilled 350 wells to these formations. The Company's experience in the Knox demonstrates the operational and economic potential of the deeper formations in the Appalachian Basin. The Company began testing the Knox sequence in 1989 by selecting certain wells that were targeted to be completed in the Clinton formation and drilling them an additional 2,000 feet to 2,500 feet. 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 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 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 completed in the Knox formations have an expected productive life ranging from 5 to 15 years. Productive Knox wells represented approximately 1.6% of the Company's total productive wells at December 31, 2001. Production from Knox wells in 2001, however, equaled 11% of the Company's total production on a Mcfe basis. The Company plans to drill or participate in joint ventures to drill 12 gross (7.0 net) wells to the Knox formations in 2002. In addition to the TBR and Knox, the Company has also tested the potentially more prolific Niagaran Carbonate, Onondaga Limestone and Oriskany Sandstone formations. The Company is well positioned to exploit the undeveloped potential of these deeper, less developed formations in the future because substantially all of its leased acreage overlies deeper drilling locations in less developed formations. In addition to its planned TBR and Knox drilling, the Company plans to drill approximately 13 gross (8.0 net) wells to other deep formations in 2002. 9 Certain typical characteristics of the less developed or deeper formations targeted by the Company are described below:
Average Drilling Costs ------------------------- Average Gross Range of Well Dry Completed Reserves per Formation Location Depths Hole Well Completed Well - ------------------------ -------------------- ------------------- --------- -------------- --------------- (in feet) (in thousands) (in Mmcfe) Trenton Black River Carbonates PA, NY, WV, OH 5,000 - 12,000 $500 $1,000 1,000 - 2,500 Knox formations OH, NY 2,500 - 8,000 150 300 300 - 600 Niagaran Carbonate MI 4,500 - 5,500 300 600 900 - 1,500 Onondaga Limestone PA 4,000 - 5,500 150 250 200 - 1,500 Oriskany Sandstone PA, NY 4,500 - 7,000 200 350 300 - 1,000
10 Drilling Results. The following table sets forth drilling results with respect to wells drilled by the Company during the past five years:
HIGHLY DEVELOPED OR BLANKET FORMATIONS (1) LESS DEVELOPED OR DEEPER FORMATIONS (2) ------------------------------------------ --------------------------------------------- 1997 1998 1999 2000 2001 1997 1998 1999 2000 2001 ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Productive: Gross 187 189 -- 108 142 39(3) 29(4) 9(5) 17(6) 14(7) Net 156.5 167.0 -- 83.6 130.6 24.5 14.2 2.1 7.2 7.4 Dry: Gross 7 3 -- 3 3 28 28 9 21 16 Net 6.3 2.5 -- 2.6 3.0 12.3 15.5 2.7 10.7 8.0 Reserves developed-net (Bcfe) 32.8 32.3 -- 15.4 20.6 9.0 3.0 0.5 2.5 2.3 Approximate cost (in millions) $ 31.2 $ 28.4 $ -- $ 11.5 $ 21.1 $ 9.3 $ 7.6 $ 0.8 $ 5.5 $ 3.5
(1) Consists of wells drilled to the Berea and Clinton Sandstone formations in Ohio, the Berea Sandstone, Devonian Brown Shale, Ravencliff Sandstone and Big Lime Limestone formations in West Virginia, the Clarendon, Upper Devonian, Coalbed Methane and Medina formations in Pennsylvania, the Medina Sandstone formation in New York, the New Albany Shale formation in Kentucky and the Antrim Shale formation in Michigan. (2) Consists of wells drilled to the Trenton Limestone and Knox formations in Ohio, the Niagaran and Dundee Carbonates in Michigan, the Oriskany Sandstone and Onondaga Limestone formations in Pennsylvania, and the Oriskany Sandstone, Onondaga Limestone, Trenton Black River Carbonates and Knox formations in New York. (3) Three additional wells which were dry in the Knox formations were subsequently completed in shallower formations. (4) Two additional wells which were dry in the Knox formations were subsequently completed in the shallower Clinton formation. (5) One additional well which was dry in the Knox formations was subsequently completed in shallower formations. (6) Three additional wells which were dry in the Knox formations were subsequently completed in the shallower Clinton formation. (7) 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 Trenton Black River formation was subsequently completed in the shallower Clinton formation. 11 ACQUISITION OF PRODUCING PROPERTIES The Company employs a disciplined approach to acquisition analysis that requires input and approval from all key areas of the Company. These areas include field operations, exploration and production, finance, legal, land management and environmental compliance. From 1992 through 1998, the Company completed 46 acquisition transactions adding 235 Bcfe of proved developed reserves for a combined purchase price allocated to proved developed reserves of approximately $158 million. Despite several attractive opportunities, the Company was unable to make any significant acquisitions in 1999 because of a lack of available capital. During 2000, much of the Company's available capital was used to pay down debt and restart its drilling program. In 2001, the Company completed two acquisition transactions adding 1.9 Bcfe of proved developed reserves for a combined purchase price allocated to proved developed reserves of approximately $1.7 million. The primary transaction in 2001 was the purchase of the remaining 40% working interest in a CBM project giving the Company 100% ownership of the project. In 2002, the Company will primarily focus on its drilling operations, and to a lesser extent, on the acquisition of producing properties. The Company has the option under prior Section 29 tax credit monetization transactions to purchase the remaining reserves at fair market value in the first quarter of 2003. DISPOSITION OF ASSETS On March 17, 2000, the Company sold the stock of Peake, a wholly-owned subsidiary. The sale included substantially all of the Company's oil and gas properties in West Virginia and Kentucky. The sale resulted in net proceeds of approximately $69.2 million, which were used to reduce bank debt. At the time of the sale, Peake represented approximately 20% of the Company's production and proved oil and gas reserves. The Company regularly reviews its oil and gas properties for potential disposition. EMPLOYEES As of February 28, 2002, the Company had 391 full-time employees, including 218 oil and gas exploration and production employees, 144 oilfield service employees and 29 general and administrative employees. The Company's management and technical staff in the categories above included 12 petroleum engineers, 6 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, acreage and the sale of oil and gas production. There is competition among oil and gas producers as well as with other industries in supplying energy and fuel to end-users. The competitors of the Company in oil and gas exploration, development and production include major integrated oil and gas companies as well as numerous independent oil and gas companies, individual proprietors, natural gas pipelines and their affiliates. 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 depend on the availability of capital, the ability to exploit its current developed and undeveloped lease holdings and 12 the ability to select and acquire suitable producing properties and prospects for future exploration and development. The only customer which accounted for 10% or more of the Company's consolidated revenues during each of the years ended December 31, 2001 and 2000 was FirstEnergy Corp., sales to which amounted to $21.0 million and $21.6 million, respectively. No customer accounted for more than 10% of consolidated revenues during the year ended December 31, 1999. 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 oil and natural gas and other matters. Such regulations may impose restrictions on the production of oil and natural gas 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 and economics of the Company. Environmental Regulation. The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas and impose substantial liabilities for pollution resulting from the Company's operations. Management believes the Company is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company. Regulation of Sales and Transportation. The Federal Energy Regulatory Commission regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. In the past, the federal government has regulated the prices at which oil and natural 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. 13 ITEM 2. PROPERTIES ---------- OIL AND GAS RESERVES The following table sets forth the Company's proved oil and gas reserves as of December 31, 1999, 2000 and 2001 determined in accordance with the rules and regulations of the SEC. The estimates of proved reserves as of December 31, 2001 and 2000 have been reviewed by Wright & Company, Inc., independent petroleum engineers. The estimates of proved reserves as of December 31, 1999 have been reviewed by Ryder Scott Company Petroleum Consultants, independent petroleum engineers. 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, ----------------------------------- 1999 2000 2001 ---------- --------- ---------- Estimated proved reserves Gas (Bcf) 306.7 373.5 334.2 Oil (Mbbl) 6,699 8,653 5,587 Bcfe 346.9 425.4 367.7 The higher reserves at December 31, 2000 were primarily due to the higher gas price at that date compared to the gas prices at December 31, 1999 and 2001. 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, 2001 determined in accordance with the rules and regulations of the SEC. Estimated future net cash flows (before income taxes) attributable to estimated production during (in thousands) 2002 $ 34,987 2003 16,497 2004 18,717 2005 and thereafter 477,573 --------- Total $ 547,774 ========= Present value before income taxes (discounted at 10% per annum) $ 224,988 ========= Present value after income taxes (discounted at 10% per annum) $ 181,862 ========= Estimated future net cash flows represent estimated future gross revenues from the production and sale of proved reserves, net of estimated costs (including production taxes, ad valorem taxes, operating costs, development costs and additional capital investment). Estimated future net cash flows were calculated on the basis of prices and costs estimated to be in effect at December 31, 2001 without escalation, except where changes in prices were fixed and readily determinable under existing contracts. 14 The following table sets forth the weighted average prices, including fixed price contracts, for oil and gas utilized in determining the Company's proved reserves. December 31, ---------------------------------------- 1999 2000 2001 ------------ ------------ ----------- Gas (per Mcf) $ 2.61 $ 9.73 $ 2.92 Oil (per barrel) 23.53 23.41 17.85 At December 31, 2001, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. Consequently, these may not reflect the prices actually received or expected to be received for oil and natural gas due to seasonal price fluctuations and other varying market conditions. The prices shown above are weighted average prices for the total reserves. The Company also calculated an alternative reserve case utilizing an assumed NYMEX gas price of $3.50 per Mmbtu (million British thermal units) which equated to a weighted average gas price of $3.80 per Mcf, including adjustments for regional basis, Btu and fixed price contracts. The weighted average oil price in the alternative case was $21.32 per Bbl. The alternative reserve case used all of the same assumptions as the proved reserve case at year-end, other than pricing. Total proved reserves calculated at the alternative prices were 403 Bcfe. Estimated future net cash flows from these reserves had a present value (discounted at 10 percent) before income taxes of approximately $360 million. IMPAIRMENT OF OIL AND GAS PROPERTIES AND OTHER ASSETS As described in Note 1 to the Consolidated Financial Statements, the Company evaluates long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The decline in oil and natural gas prices from 1997 to 1998 was significant and negatively impacted the quantity and value of the Company's oil and gas reserves. Given the impairment indicator at December 31, 1998, the Company computed the expected future undiscounted cash flows, employing methods consistent with those utilized to determine the estimated future net cash flows from proved reserves discussed above. For those assets in which the sum of the expected future undiscounted cash flows was less than the carrying amount, an impairment loss was recognized for the difference between the fair value and the carrying amount of the asset, with fair value determined based on discounted cash flow analysis, sale of similar properties or recent offers for specific assets. As a result of this evaluation, the Company recorded total impairment charges of $160.7 million (pre-tax) in 1998, consisting of $148.0 million relating to producing properties and related assets, $5.8 million for unproved properties and $6.9 million relating to other long-lived assets. The magnitude of the impairment charge was impacted by the merger with TPG in 1997, in which the allocation of the purchase price at fair value resulted in a significant increase in the book value of the Company's assets. No impairment was recorded in 1999. Impairments of $477,000 and $1.4 million were recorded in 2000 and 2001, respectively. 15 PRODUCING WELL DATA As of December 31, 2001, the Company owned interests in 6,262 gross (5,238 net) producing oil and gas wells and operated approximately 5,723 wells, including wells operated for third parties. By operating a high percentage of its properties, the Company is able to control expenses, capital allocation and the timing of development activities in the areas in which it operates. As of December 31, 2001, the Company's net production was approximately 51.8 Mmcf of natural gas and 1,651 Bbls of oil per day. The following table summarizes by state the Company's productive wells at December 31, 2001: December 31, 2001 ------------------------------------------------------- Gas Wells Oil Wells Total --------------- --------------- --------------- State Gross Net Gross Net Gross Net - ------------- ----- ----- ----- ----- ----- ----- Ohio 1,417 1,214 1,729 1,629 3,146 2,843 Pennsylvania 738 620 445 444 1,183 1,064 New York 875 845 7 6 882 851 Michigan 1,044 476 7 4 1,051 480 ----- ----- ----- ----- ----- ----- 4,074 3,155 2,188 2,083 6,262 5,238 ===== ===== ===== ===== ===== ===== ACREAGE DATA The following table summarizes by state the Company's gross and net developed and undeveloped leasehold acreage at December 31, 2001:
December 31, 2001 ------------------------------------------------------------------------------- Developed Acreage Undeveloped Acreage Total Acreage ----------------------- ----------------------- ----------------------- State Gross Net Gross Net Gross Net - --------------- --------- --------- --------- --------- --------- --------- Ohio 312,789 281,855 272,066 228,042 584,855 509,897 Pennsylvania 48,590 40,978 267,711 247,837 316,301 288,815 New York 70,800 68,937 123,765 100,289 194,565 169,226 Michigan 18,426 17,942 61,688 57,756 80,114 75,698 Indiana -- -- 8,559 8,506 8,559 8,506 West Virginia -- -- 1,144 1,144 1,144 1,144 --------- --------- --------- --------- --------- --------- 450,605 409,712 734,933 643,574 1,185,538 1,053,286 ========= ========= ========= ========= ========= =========
16 Item 3. LEGAL PROCEEDINGS ----------------- In February 2000, four individuals filed a suit in Chautauqua County, New York on their own behalf and on the behalf of others similarly situated, seeking damages for the alleged difference between the amount of lease royalties actually paid and the amount of royalties that allegedly should have been paid. Other natural gas producers in New York were served with similar complaints. The Company believes the complaint is without merit and is defending the complaint vigorously. Although the outcome is still uncertain, the Company believes the action will not have a material adverse effect on its financial position, results of operations or cash flows. 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, results of operations or cash flows. 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, 2002 was as follows: Number of Title of Class Record Holders ---------------------------------------- -------------------- Common Stock 14 DIVIDENDS No dividends have been paid on the Company's Common Stock. 17 Item 6. SELECTED FINANCIAL DATA ----------------------- The Selected Financial Data should be read in conjunction with the Consolidated Financial Statements at Item 14(a).
PREDECESSOR | COMPANY | SUCCESSOR COMPANY -------------- | ---------------------------------------------------------------------- SIX MONTHS | SIX MONTHS ENDED | ENDED AS OF OR FOR THE YEARS ENDED DECEMBER 31, JUNE 30, | DECEMBER 31, ----------------------------------------------------- (IN THOUSANDS) 1997 | 1997 1998 1999 2000(1) 2001 -------------- | ---------------- ------------ ------------ ------------ ------------ | OPERATIONS: | Revenues $ 79,397 | $ 84,126 $ 154,839 $ 135,761 $ 117,851 $ 131,530 Depreciation, depletion | and amortization 15,366 | 31,694 68,488 41,412 27,460 27,332 Impairment of oil and gas | properties and other assets -- | -- 160,690 -- 477 1,398 (Loss) income before | extraordinary item (9,873) | (11,372) (130,550) (18,303) 4,325 6,467 Preferred dividends paid 45 | -- -- -- -- -- BALANCE SHEET DATA: | AS OF 12/31/97 | ---------------- Working capital | 19,846 (6,268) (43,032) 4,180 13,505 Oil and gas properties and | gathering systems, net | 491,183 319,013 285,081 228,937 239,391 Total assets | 599,320 418,605 350,695 285,117 305,349 Long-term liabilities, | less current portion | 355,649 354,382 303,731 286,858 284,745 Total shareholders' equity (deficit) | 96,858 (33,014) (51,590) (48,313) (27,279)
(1) In March 2000, the Company sold Peake. See Note 3 to the Consolidated Financial Statements. Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL ------------------------------------------------- CONDITION AND RESULTS OF OPERATIONS ----------------------------------- 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. The Company's principal business is producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. The Company currently operates in Ohio, Pennsylvania, New York, Michigan, Indiana and West Virginia. The Company provides oilfield services to its own operations and to third parties. Oilfield services provided to the Company's own operations are provided at cost and all intercompany revenues and expenses are eliminated in consolidation. CRITICAL ACCOUNTING POLICIES - ---------------------------- The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States ("GAAP") and SEC guidance. See the "Notes to Consolidated Financial Statements" included in "Item 8. Financial Statements and Supplementary Data" for a comprehensive discussion of the Company's significant accounting policies. GAAP requires information in financial statements about the accounting principles and methods used and the risks and uncertainties inherent in significant estimates including choices between acceptable methods. Following is a discussion of the Company's most critical accounting policies: 18 SUCCESSFUL EFFORTS METHOD OF ACCOUNTING - --------------------------------------- The accounting for and disclosure of oil and gas producing activities requires the Company's management to choose between GAAP alternatives and to make judgments about estimates of future uncertainties. The Company utilizes the "successful efforts" method of accounting for oil and gas producing activities as opposed to the alternate acceptable "full cost" method. Under the successful efforts 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, exploratory dry hole costs and costs of carrying and retaining unproved properties, are expensed as incurred. The major difference between the successful efforts method of accounting and the full cost method is under the full cost method of accounting, such exploration costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the net income (loss) of future periods as a component of depletion expense. During 2001, 2000 and 1999, the Company recognized exploration expense of $8.3 million, $8.5 million and $6.4 million, respectively, under the successful efforts method. OIL AND GAS RESERVES The Company's proved developed and proved undeveloped reserves are all located within the Appalachian and Michigan Basins in 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 assumptions used. Proved reserves represent estimated quantities of natural gas and oil 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 accuracy of a reserve estimate is a function of: -- the quality and quantity of available data; -- the interpretation of that data; -- the accuracy of various mandated economic assumptions; and -- the judgment of the persons preparing the estimate. The Company's proved reserve information included in this Report is based on estimates it prepared. Estimates prepared by others may be higher or lower than the Company's estimates. The Company's estimates of proved reserves have been reviewed by independent petroleum engineers. CAPITALIZATION, DEPRECIATION, DEPLETION AND IMPAIRMENT OF LONG-LIVED ASSETS See the "Successful Efforts Method of Accounting" discussion above. 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. 19 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. Impairments recorded in 2001 and 2000 were $179,000 and $477,000, respectively, which reduced the book value of unproved oil and gas properties to their estimated fair value. Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed 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 the carrying amount of the asset. In performing the review for long-lived asset recoverability during 2001, the Company recorded $1.2 million of impairments which reduced the book value of producing properties to their estimated fair value. Fair value was based on management's outlook of future oil and natural gas prices and estimated future cash flows to be generated by the assets, discounted at a market rate of interest. No impairment was recorded in 2000 or 1999. DERIVATIVES AND HEDGING On January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. As a result of the adoption of SFAS 133, the Company recognizes all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss). Ineffective portions of a derivative instrument's change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be recognized as increases or decreases to oil and gas revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss). The relationship between the hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. The Company measures effectiveness on changes in the hedge's intrinsic value. The Company considers these hedges to be highly effective and expects there will be no ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging instruments and the hedged forecasted transactions are the same. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. The Company measures effectiveness on at least a quarterly basis. The adoption of SFAS 133 resulted in a January 1, 2001 transition adjustment to increase other current liabilities by $10.5 million, increase current deferred income taxes by $3.8 million and increase 20 shareholders' deficit by $6.7 million to record the fair value of open cash flow hedges and the related income tax effect. The increase in shareholders' deficit is reflected as a cumulative effect of accounting change in accumulated other comprehensive income (loss). Prior to January 1, 2001, under the deferral method, gains and losses from derivative instruments that qualified as hedges were deferred until the underlying hedged asset, liability or transaction monetized, matured or was otherwise recognized under generally accepted accounting principles. When recognized in net income (loss), hedge gains and losses were included as an adjustment to gas revenue or interest expense. 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. NEW ACCOUNTING PRONOUNCEMENTS - ----------------------------- In July 2001, the Financial Accounting Standards Board (FASB) issued Statements of Financial Accounting Standards No. 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets." The adoption of SFAS 141 as of July 1, 2001 had no effect on the Company's financial position, results of operations or cash flows. SFAS 141 eliminates the pooling-of-interests method of accounting for business combinations except for qualifying business combinations that were initiated prior to July 1, 2001. SFAS 141 further clarifies the criteria to recognize intangible assets separately from goodwill. The requirements of SFAS 141 are effective for any business combination accounted for by the purchase method that was completed after June 30, 2001. Under SFAS 142, goodwill and indefinite lived intangible assets are no longer amortized but are reviewed for impairment annually or if certain impairment indicators arise. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life). The amortization provisions of SFAS 142 apply to goodwill and intangible assets acquired after June 30, 2001. With respect to goodwill and intangible assets acquired prior to July 1, 2001, the Company is required to adopt SFAS 142 on January 1, 2002. Early adoption is not permitted for calendar year companies. At December 31, 2001, the Company had $2.7 million of unamortized goodwill which will be subject to the transition provisions of SFAS 142. Amortization expense related to goodwill amounted to $130,000, $132,000 and $208,000 for the years ended December 31, 2001, 2000 and 1999, respectively. The Company is currently assessing the impact of SFAS 142 and has not yet determined whether adoption will have a material effect on the Company's financial position, results of operations or cash flows including any transitional impairment losses which would be required to be recognized as the effect of a change in accounting principle. In August 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 addresses obligations associated with the retirement of tangible, long-lived assets and the associated asset retirement costs. This statement amends SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies", and is effective for the Company's financial statements beginning January 1, 2003. The Company is currently assessing the impact of SFAS 143 and has not yet determined whether adoption will have a material effect on the Company's financial position, results of operations or cash flows. In October 2001, the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which establishes a single accounting model to be used for long-lived assets to be 21 disposed of. The new rules supersede SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Although retaining many of the fundamental recognition and measurement provisions of SFAS 121, the new rules significantly change the criteria that would have to be met to classify an asset as held-for-sale. This distinction is important because assets to be disposed of are stated at the lower of their fair values or carrying amounts and depreciation is no longer recognized. The new rules also will supersede the provisions of Accounting Principles Board Opinion No. (APB) 30, "Reporting Results of Operations - Reporting the Effects of Disposal of a Segment of Business," and will require the expected future operating losses from discontinued operations to be displayed in discontinued operations in the periods in which the losses are incurred rather than as of the measurement date as presently required by APB 30. In addition, more dispositions will qualify for discontinued operations treatment in the income statement. SFAS 144 is effective as of January 1, 2002. The adoption of this standard is not expected to have a material effect on the Company's financial position, results of operations or cash flows. 22 RESULTS OF OPERATIONS The following table sets forth financial data for the periods indicated. Dollars are stated in thousands and as a percentage of revenues.
YEAR ENDED DECEMBER 31, -------------------------------------------------------------------- 2001 2000 1999 -------------------- --------------------- ---------------------- REVENUES Oil and gas sales $ 95,395 72.5% $ 79,743 67.7% $ 79,299 58.4% Gas gathering, marketing, and oilfield sales and service 34,087 25.9 34,850 29.6 51,445 37.9 Other 2,048 1.6 3,258 2.7 5,017 3.7 -------------------- --------------------- ---------------------- 131,530 100.0 117,851 100.0 135,761 100.0 EXPENSES Production expense 22,649 17.2 20,917 17.7 21,980 16.2 Production taxes 2,372 1.8 2,409 2.0 3,260 2.4 Gas gathering, marketing, and oilfield sales and service 29,382 22.3 31,703 26.9 46,977 34.6 Exploration expense 8,346 6.4 8,528 7.3 6,442 4.7 General and administrative expense 4,395 3.3 4,617 3.9 5,412 4.0 Franchise, property and other taxes 250 0.2 397 0.3 652 0.5 Depreciation, depletion and amortization 27,332 20.8 27,460 23.3 41,412 30.5 Impairment of oil and gas properties and other assets 1,398 1.1 477 0.4 -- -- Severance and other nonrecurring expense 1,954 1.5 241 0.3 3,285 2.4 -------------------- --------------------- ---------------------- 98,078 74.6 96,749 82.1 129,420 95.3 -------------------- --------------------- ---------------------- OPERATING INCOME 33,452 25.4 21,102 17.9 6,341 4.7 OTHER (INCOME) EXPENSE (Gain) loss on sale of subsidiaries and other income -- -- (15,064) (12.8) 1,521 1.1 Interest expense 27,476 20.9 29,473 25.0 34,302 25.3 -------------------- --------------------- ---------------------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM 5,976 4.5 6,693 5.7 (29,482) (21.7) (Benefit) provision for income taxes (491) (0.4) 2,368 2.0 (11,179) (8.2) -------------------- --------------------- ---------------------- INCOME (LOSS) BEFORE EXTRAORDINARY ITEM 6,467 4.9 4,325 3.7 (18,303) (13.5) Extraordinary item - early extinguishment of debt, net of tax benefit -- -- (1,364) (1.2) -- -- -------------------- --------------------- ---------------------- NET INCOME (LOSS) $ 6,467 4.9% $ 2,961 2.5% $ (18,303) (13.5)% ==================== ===================== ====================== EBITDAX $ 72,482 55.1% $ 57,808 49.1% $ 57,480 42.3%
23 2001 COMPARED TO 2000 Operating income increased $12.4 million (59%) from $21.1 million in 2000 to $33.5 million in 2001. This increase was primarily a result of a $15.5 million (26%) increase in operating margins partially offset by a $1.2 million decrease in other income, a $1.7 million increase in severance and other nonrecurring expense and a $921,000 increase in impairment of oil and gas properties and other assets. The increase in operating margins was primarily due to a $14.0 million increase in the oil and gas operating margin (oil and gas sales revenues less production expense and production taxes) primarily as a result of an increase in the average price realized for the Company's natural gas of approximately $21.7 million ($1.17 per Mcf) and an increase in the volumes of oil sold. These increases were partially offset by a decrease in the average price realized for the Company's oil and by a decrease in gas volumes sold as discussed below. The net increase in operating margins from changes in prices and volumes was partially offset by an increase in production expense. The operating margin from oil and gas sales on a per unit basis increased 31% from $2.39 per Mcfe in 2000 to $3.14 per Mcfe in 2001. The $1.2 million decrease in other income was primarily due to a reduction in income from the monetization of nonconventional fuel source tax credits as a result of the Peake sale and proceeds received in the second quarter of 2000 from the settlement of a lawsuit. Net income increased $3.5 million from net income of $3.0 million in 2000 to net income of $6.5 million in 2001. Gain on sale of subsidiary and other income in 2000 was $15.1 million as discussed below. Other significant changes in 2001 compared to 2000 were the $12.4 million increase in operating income discussed above, a $2.0 million decrease in interest expense, a $2.9 million decrease in provision for income taxes, a $921,000 increase in impairment of oil and gas properties and other assets and a $1.4 million (net of tax benefit) extraordinary loss from the early extinguishment of debt in 2000. Earnings before interest, income taxes, depreciation, depletion and amortization, impairment, exploration expense and severance and other nonrecurring items ("EBITDAX") increased $14.7 million from $57.8 million in 2000 to $72.5 million in 2001. This was primarily due to the $15.5 million increase in the Company's operating margins discussed above partially offset by the $1.2 million decrease in other income. Total revenues increased $13.7 million (12%) in 2001 compared to 2000 primarily as a result of a $1.17 per Mcf increase in the average price realized for the Company's natural gas and an increase in the volumes of oil sold partially offset by a $4.25 per Bbl decrease in the average price paid for the Company's oil, a decrease in gas volumes sold and the decrease in other income discussed above. Gas volumes sold decreased 1.5 Bcf (7%) from 20.0 Bcf in 2000 to 18.5 Bcf in 2001 resulting in a decrease in gas sales revenues of approximately $4.7 million. The gas volume decrease was due to the sale of Peake in the first quarter of 2000 and the natural production decline of the wells partially offset by production from wells drilled in 2000 and 2001. Oil volumes sold increased approximately 54,000 Bbls (9%) from 592,000 Bbls in 2000 to 646,000 Bbls in 2001 resulting in an increase in oil sales revenues of approximately $1.5 million. The average price realized for the Company's natural gas increased $1.17 per Mcf to $4.34 per Mcf in 2001 compared to 2000 which increased gas sales revenues in 2001 by approximately $21.7 million. As a result of the Company's hedging activities, gas sales revenues were increased by $4.5 million ($0.25 per Mcf) in 2001 and were reduced by $9.3 million ($0.47 per Mcf) in 2000. The average price paid for the Company's oil decreased from $27.29 per barrel in 2000 to $23.04 per barrel in 2001 which decreased oil sales revenues by approximately $2.7 million. 24 Production expense increased $1.7 million (8%) from $20.9 million in 2000 to $22.6 million in 2001. The average production cost increased from $0.89 per Mcfe in 2000 to $1.01 per Mcf in 2001. The per unit increase was primarily due to the sale of Peake, increased compensation related expenses, additional costs incurred in 2001 to minimize production declines in order to take advantage of higher gas prices and general cost increases due to current market conditions. Production taxes were $2.4 million in 2000 and 2001. Average per unit production taxes increased from $0.10 per Mcfe in 2000 to $0.11 per Mcfe in 2001. Exploration expense decreased $182,000 (2%) from $8.5 million in 2000 to $8.3 million in 2001 primarily due to a $1.1 million decrease in exploratory dry hole expenses in 2001 compared to 2000 partially offset by $967,000 of costs associated with increased 2001 leasing activity in exploratory areas. General and administrative expense decreased $222,000 (5%) from $4.6 million in 2000 to $4.4 million in 2001 due to decreases in employment and compensation related expenses. Franchise, property and other taxes decreased $147,000 (37%) from $397,000 in 2000 to $250,000 in 2001 primarily due to an $83,000 decrease in franchise tax and a $79,000 decrease in personal property tax from the sale of Peake in 2000, state scheduled reduction in taxable values and lower tax rates. Depreciation, depletion and amortization decreased by $128,000 from $27.5 million in 2000 to $27.3 million in 2001. This decrease was primarily due to a $930,000 reduction in amortization of loan costs from the extension of the Revolver's final maturity date, a $680,000 reduction in amortization of non-compete covenants due to expiration of the covenants in 2001 and a $660,000 reduction in the amortization of nonconventional fuel source tax credits in 2001 offset by an increase in depletion expense. Depletion expense increased $2.3 million (13%) from $18.1 million in 2000 to $20.4 million in 2001. Depletion per Mcfe increased from $0.77 per Mcfe in 2000 to $0.91 per Mcfe in 2001. These increases were primarily the result of a higher amortization rate per Mcfe due to lower reserves resulting from lower oil and gas prices at year-end 2001. Impairment of oil and gas properties and other assets increased $921,000 from $477,000 in 2000 to $1.4 million in 2001. The Company recorded a net nonrecurring charge of $2.0 million in 2001 which includes a charge of $2.3 million primarily related to the early retirement of certain senior management members of the Company and other severance charges incurred which included a non-cash charge of approximately $200,000 due to the acceleration of certain related stock options. In 2001, the Company recognized approximately $300,000 in other nonrecurring gains. Gain on sale of subsidiaries and other income in 2000 was $15.1 million primarily due to the $13.7 million gain on the sale of Peake and the $1.3 million gain on terminated interest rate swaps in 2000. Interest expense decreased $2.0 million (7%) from $29.5 million in 2000 to $27.5 million in 2001. This decrease was due to a decrease in average outstanding borrowings and lower blended interest rates. The Company's interest expense was reduced by $141,000 in 2000 due to interest rate swaps. During 2001, the Company concluded an IRS income tax examination of the years 1994 through 1997 and favorably settled other tax issues. A federal income tax benefit of $2.0 million was recorded as a result. Also during 2001, a federal income tax benefit was recorded for approximately $700,000 along 25 with a corresponding reduction in the valuation allowance as a result of certain net operating loss carryforwards which the Company now believes it can fully utilize. 2000 COMPARED TO 1999 Operating income increased $14.8 million (233%) from $6.3 million in 1999 to $21.1 million in 2000. This increase was the result of a $13.9 million decrease in depreciation, depletion and amortization expense, a $3.0 million decrease in severance and other nonrecurring expense, a $1.0 million increase in the Company's operating margin and a $795,000 decrease in general and administrative expense partially offset by a $1.8 million decrease in other income and a $2.1 million increase in exploration expense. The increase in operating margins was due to increases in the average price paid for the Company's oil and gas partially offset by a decrease in oil and gas volumes sold as a result of the sale of Peake and the natural production decline of the wells. The operating margin from oil and gas sales on a per unit basis increased 37% from $1.74 per Mcfe in 1999 to $2.39 per Mcfe in 2000. The decrease in other income was primarily due to a reduction in income from the monetization of nonconventional fuel source tax credits as a result of the Peake sale. Net income increased $21.3 million from a net loss of $18.3 million in 1999 to net income of $3.0 million in 2000. This increase was the result of the $13.7 million gain on the sale of Peake in March 2000, a $4.8 million decrease in interest expense, a $2.8 million loss due to the sale of TOPS in August 1999, a $1.3 million gain on terminated interest rate swaps in 2000 and the changes in operating income discussed above. These changes were partially offset by a $1.4 million extraordinary loss from the early extinguishment of debt, net of tax benefit (See Note 7 to the Consolidated Financial Statements), a $1.3 million gain on the sale of BESCO in November 1999 and a $13.5 million increase in the provision for income taxes primarily due to an increase in income before income taxes and extraordinary item. EBITDAX increased $328,000 from $57.5 million in 1999 to $57.8 million in 2000. This was primarily due to the $1.0 million increase in the Company's operating margin discussed above and the $795,000 decrease in general and administrative expense partially offset by a $1.8 million decrease in other income. Total revenues decreased $17.9 million (13%) in 2000 compared to 1999 due to the sale of the Company's subsidiaries, BESCO and TOPS, in the second half of 1999, the sale of Peake in the first quarter of 2000 and decreases in the volumes of oil and natural gas sold. These decreases were partially offset by increases in the average price paid for the Company's oil and natural gas. Oil volumes sold decreased approximately 121,000 Bbls (17%) from 713,000 Bbls in 1999 to 592,000 Bbls in 2000 resulting in a decrease in oil sales revenues of approximately $2.0 million. Gas volumes sold decreased 7.0 Bcf (26%) from 27.0 Bcf in 1999 to 20.0 Bcf in 2000 resulting in a decrease in gas sales revenues of approximately $17.4 million. These volume decreases were due to the sale of Peake in the first quarter of 2000, the natural production decline of the wells and curtailment of drilling to minimum levels in 1999 due to capital constraints caused by the reduction in the Company's borrowing base in 1999. The average price paid for the Company's oil increased from $16.57 per barrel in 1999 to $27.29 per barrel in 2000 which increased oil sales revenues by approximately $6.4 million. The average price paid for the Company's natural gas increased $0.67 per Mcf to $3.17 per Mcf in 2000 compared to 1999 which increased gas sales revenues in 2000 by approximately $13.4 million. As a result of the Company's hedging activities, gas sales revenues were reduced by $9.3 million ($0.47 per Mcf) in 2000 and were enhanced by $1.0 million ($0.04 per Mcf) in 1999. Production expense decreased $1.1 million (5%) from $22.0 million in 1999 to $20.9 million in 2000 primarily due to the sale of Peake partially offset by increased employment and compensation 26 related expenses. The average production cost increased from $0.70 per Mcfe in 1999 to $0.89 per Mcf in 2000 primarily due to decreased production volumes sold and to a lesser extent increased compensation related expenses. Production taxes decreased approximately $851,000 (26%) in 2000 compared to 1999 as a result of decreased oil and gas sales revenues primarily due to the sale of Peake. Average production taxes were $0.10 per Mcfe in 2000 and 1999. A decrease in the average production tax amount per Mcfe resulting from the sale of Peake was offset by an increase in per unit production taxes due to higher oil and natural gas prices in 2000. Exploration expense increased by $2.1 million (32%) from $6.4 million in 1999 to $8.5 million in 2000. Increased geophysical expenses and dry hole costs associated with the Company's active drilling program in 2000 and planned drilling activity in 2001 were partially offset by decreased employment and compensation related expense due to staff reductions in September 1999. Drilling activity in 1999 was severely curtailed due to capital constraints caused by the reduction in the Company's borrowing base. General and administrative expense decreased $795,000 in 2000 compared to 1999 due to decreases in employment and compensation related expenses and a decrease in Year 2000 ("Y2K") related costs. Severance and other nonrecurring expense decreased from $3.3 million in 1999 to $241,000 in 2000 primarily due to $2.4 million in employee reduction costs and $880,000 in costs associated with an abandoned acquisition effort and an abandoned public offering of a royalty trust in the third quarter of 1999. Depreciation, depletion and amortization decreased by $13.9 million (34%) from $41.4 million in 1999 to $27.5 million in 2000. Depletion expense decreased $10.8 million (37%) from $28.9 million in 1999 to $18.1 million in 2000. Depletion per Mcfe decreased from $0.92 per Mcfe in 1999 to $0.77 per Mcfe in 2000. These decreases were primarily the result of decreased production volumes and a lower amortization rate per Mcfe due to higher reserves resulting from higher oil and gas prices at December 31, 2000. Interest expense decreased $4.8 million (14%) from $34.3 million in 1999 to $29.5 million in 2000. This decrease was due to a decrease in average outstanding borrowings partially offset by higher blended interest rates. The Company's interest expense was reduced by $141,000 in 2000 and increased by $972,000 in 1999 due to interest rate swaps. (Gain) loss on sale of subsidiaries and other income increased from a $1.5 million loss in 1999 to a $15.1 million gain in 2000 due to the $13.7 million gain on the sale of Peake in 2000, a $1.3 million gain on terminated interest rate swaps in 2000 and a $2.8 million loss on the sale of the Company's TOPS subsidiary in 1999 partially offset by a $1.3 million gain on the sale of the Company's BESCO subsidiary in 1999. 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 natural gas. The Company's current ratio at December 31, 2001 was 1.53 to 1. During 2001, working capital increased $9.3 million from $4.2 million at December 31, 2000 to $13.5 million at December 31, 2001. The increase was primarily due to an increase in the fair value of derivatives in 2001 which increased working capital by $20.0 million, net of a related increase in current deferred taxes of $6.9 million and a $4.9 million decrease in accrued expenses. These increases were offset by an $8.5 million decrease in 27 accounts receivable. The Company's operating activities provided cash flows of $48.1 million during 2001. On June 29, 2001, the Company amended its $100 million revolving credit facility from Ableco Finance LLC and Foothill Capital Corporation. The amendment extended the Revolver's final maturity date to April 22, 2004, from August 23, 2002, increased the letter of credit sub-limit from $20 million to $30 million and eliminated the effects of SFAS 133 from financial covenant calculations. The Company paid approximately $200,000 in fees and expenses related to the amendment. The amendment extended the financial covenant for the senior interest coverage ratio of 3.2 to 1 for the quarters ending September 30, 2002, through March 31, 2004; and the senior debt leverage ratio of 2.7 to 1 was extended for the quarters ending September 30, 2002 through March 31, 2004. These ratios will be calculated quarterly based on the financial results of the previous four quarters. The amendment added an early termination fee equal to .25% of the facility if terminated between the effective date and May 31, 2002. If termination is after May 31, 2002 but on or before May 31, 2003, the termination fee is .125% of the facility. There is no termination fee after May 31, 2003. The Company is required to hedge, through financial instruments or fixed price contracts, at least 20% but not more than 80% of its estimated hydrocarbon production, on a Mcfe basis, for the succeeding 12 months on a rolling 12-month basis. Based on the Company's hedges currently in place and its expected production levels, the Company is in compliance with this hedging requirement through March 2003. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At December 31, 2001, the interest rate was 6.75%. At December 31, 2001, the Company had $2.3 million of outstanding letters of credit. At December 31, 2001, the outstanding balance under the credit agreement was $59.3 million with $38.4 million of borrowing capacity available for general corporate purposes. In January 2002, the Company monetized certain financial hedges and paid down the Revolver by $21.7 million. As of February 28, 2002, there was $33.0 million outstanding under the Revolver, letters of credit commitments of $2.3 million and $64.7 million available for general corporate purposes. The Revolver is secured by security interests and mortgages against substantially all of the Company's assets and is subject to periodic borrowing base determinations. The borrowing base is the lesser of $100 million or the sum of (i) 65% of the value of the Company's proved developed producing reserves subject to a mortgage; (ii) 45% of the value of the Company's proved developed non-producing reserves subject to a mortgage; and (iii) 40% of the value of the Company's proved undeveloped reserves subject to a mortgage. The price forecast used for calculation of the future net income from proved reserves is the three-year NYMEX strip for oil and natural gas as of the date of the reserve report. Prices beyond three years are held constant. Prices are adjusted for basis differential, fixed price contracts and financial hedges in place. The present value (using a 10% discount rate) of the Company's future net income at December 31, 2001, under the borrowing base formula above, was approximately $196 million for all proved reserves of the Company and $146 million for properties secured by a mortgage. The Revolver is subject to certain financial covenants. These include a senior debt interest coverage ratio ranging from 3.7 to 1 at December 31, 2001, to 3.2 to 1 at March 31, 2004; and a senior debt leverage ratio ranging from 2.6 to 1 and 3.2 to 1 for the periods from December 31, 2001 through March 31, 2004. EBITDA, as defined in the Revolver, and consolidated interest expense on senior debt in these ratios are calculated quarterly based on the financial results of the previous four quarters. In addition, the Company is required to maintain a current ratio (including available borrowing capacity in current assets, excluding current debt and accrued interest from current liabilities and excluding any effects from the application of SFAS 133 to other current assets or current liabilities) of at least 1.0 to 1 28 and maintain liquidity of at least $5 million (cash and cash equivalents including available borrowing capacity). As of December 31, 2001, the Company's current ratio including the above adjustments was 3.11 to 1. The Company had satisfied all financial covenants as of December 31, 2001. The Company issued $225 million of 9 7/8% Senior Subordinated Notes on June 27, 1997. The notes mature June 15, 2007. Interest is payable semiannually on June 15 and December 15 of each year. The notes are general unsecured obligations of the Company and are subordinated in right of payment to senior debt. Except as otherwise described in Note 7 to the Consolidated Financial Statements, 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, 2002, the notes may be redeemed as a whole at the option of the Company upon the occurrence of a change in control. The notes were issued pursuant to an indenture which 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. 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 is exchanged for a fixed interest rate. The Company's interest expense was reduced by $141,000 in 2000 due to interest rate swaps. At December 31, 2000, the Company had no open interest rate swap arrangements. There were no interest rate swaps open in 2001. During 2001, the Company invested $24.6 million, including exploratory dry hole expense, to drill 165 development wells and 10 exploratory wells. Of these wells, 153 development wells and three exploratory wells were completed as producers in the target formation, for a completion rate of 93% and 30%, respectively (an overall completion rate of 89%). In addition, $1.7 million was invested in proved developed reserve acquisitions. The Company currently expects to spend approximately $44 million during 2002 on its drilling activities, including exploratory dry hole expense, and other capital expenditures. The Company intends to finance its planned capital expenditures through its available cash flow, available revolving credit line, the sale of participating interests in its exploratory Trenton Black River prospect areas and the sale of non-strategic assets. At December 31, 2001, the Company had approximately $38.4 million available under the Revolver. At February 28, 2002, the Company had approximately $64.7 million available under the Revolver. The level of the Company's future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of its drilling activities and its ability to acquire additional producing properties. The Company has various commitments primarily related to leases for office space, vehicles, natural gas compressors and computer equipment. The Company expects to fund these commitments with cash generated from operations. The following table summarizes the Company's contractual obligations at December 31, 2001.
PAYMENTS DUE BY PERIOD ------------------------------------------------------------- CONTRACTUAL OBLIGATIONS AT LESS THAN 1 - 3 4 - 5 AFTER 5 DECEMBER 31, 2001 TOTAL 1 YEAR YEARS YEARS YEARS - ------------------------------------ -------- -------- -------- -------- -------- (IN THOUSANDS) Long term debt $284,434 $ 19 $ 59,315 $ 8 $225,092 Capital lease obligations 326 137 189 -- -- Operating leases 2,466 1,252 895 319 -- -------- -------- -------- -------- -------- Total contractual cash obligations $287,226 $ 1,408 $ 60,399 $ 327 $225,092 ======== ======== ======== ======== ========
In addition to the items above, the Company has an employment agreement with its Chief Executive Officer, a retirement agreement, a severance plan and a change of control plan. See "Executive Compensation - Employment and Severance Agreements" in Item 11 of this Report. The Company has entered into joint operating agreements, area of mutual interest agreements and joint ventures with other companies. These agreements may include drilling commitments or other obligations in the normal course of business. 29 The following table summarizes the Company's commercial commitments at December 31, 2001.
AMOUNT OF COMMITMENT EXPIRATION PER PERIOD ------------------------------------------------------ TOTAL COMMERCIAL COMMITMENTS AT AMOUNTS LESS THAN 1 - 3 4 - 5 OVER 5 DECEMBER 31, 2001 COMMITTED 1 YEAR YEARS YEARS YEARS - ----------------------------------- --------- --------- ----- ----- ------ (IN THOUSANDS) Standby Letters of Credit $ 2.3 $ 2.3 $ -- $ -- $ -- ------ ------ ------ ------ ------- Total Commercial Commitments $ 2.3 $ 2.3 $ -- $ -- $ -- ====== ====== ====== ====== =======
In the normal course of business, the Company has performance obligations which are supported by surety bonds or letters of credit. These obligations are primarily site restoration and dismantlement, royalty payments and exploration programs where governmental organizations require such support. The Company also has letters of credit with its hedging counterparty. The Company has certain other commitments and uncertainties related to its normal operations, including any obligation to plug wells. NATURAL GAS HEDGE POSITION MONETIZATION AND RESTRUCTURING On January 17 and 18, 2002, the Company monetized 9,350 Bbtu (billion British thermal units) of its 2002 natural gas hedge position at a weighted average NYMEX price of $2.53 per Mmbtu and 3,840 Bbtu of its 2003 natural gas hedge position at a NYMEX price of $3.01 per Mmbtu. The Company received net proceeds of $22.7 million that will be recognized as increases to natural gas revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss). In January 2002, the Company entered into a collar for 9,350 Bbtu of its natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a floor price of $2.25 per Mmbtu. The Company also sold a floor at $1.75 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per Mmbtu; 3) locking in a price of $2.25 per Mmbtu if prices are between $1.75 and $2.25 per Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the price if the price is $1.75 or less. All prices are based on monthly NYMEX settle. The Company paid $1.0 million for the options. The Company used the net proceeds of $21.7 million from the two transactions above to pay down on its credit facility. At February 28, 2002, the Company had $2.3 million of outstanding letters of credit. At February 28, 2002, the outstanding balance under the credit facility was $33.0 million with $64.7 million of borrowing capacity available for general corporate purposes. 30 The following table summarizes, as of January 21, 2002, the Company's deferred gains on terminated natural gas hedges. Cash has been received and the deferred gains recorded in accumulated other comprehensive income. The deferred gains will be recognized as increases to gas revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss).
2002 2003 ---------------------------------------------- ------ FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER ------- ------- ------- ------- (IN THOUSANDS) Natural Gas Hedges Terminated in January 2002 $4,521 $5,620 $5,188 $4,560 $2,851
To manage its exposure to natural gas or oil price volatility, the Company may partially hedge its physical gas or oil sales prices by selling futures contracts on the 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, collars or options. 31 The Company's financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Accordingly, the Company may modify its fixed price contract and financial hedging positions by entering into new transactions or terminating existing contracts. The following tables reflect the natural gas volumes and the weighted average prices under financial hedges (including settled hedges) and fixed price contracts at January 21, 2002:
NATURAL GAS SWAPS FIXED PRICE CONTRACTS ------------------------------------------- -------------------------------- ESTIMATED ESTIMATED NYMEX PRICE WELLHEAD ESTIMATED WELLHEAD QUARTER ENDING Bbtu PER Mmbtu PRICE PER Mcf Mmcf PRICE PER Mcf - ----------------------------- ---- ----------- ------------- --------- ------------- March 31, 2002 850 $ 4.95 $ 5.20 1,070 $ 4.48 June 30, 2002 -- -- -- 820 4.20 September 30, 2002 -- -- -- 690 4.32 December 31, 2002 -- -- -- 570 4.49 ---- ------- ------- ------ ------- 850 $ 4.95 $ 5.20 3,150 $ 4.37 ==== ======= ======= ====== ======= March 31, 2003 65 $ 2.50 June 30, 2003 65 2.50 September 30, 2003 65 2.50 December 31, 2003 65 2.50 --- ---- 260 $ 2.50 ==== ======
MONTHLY NYMEX SETTLE OF MONTHLY NYMEX SETTLE LOWER $1.75 OR HIGHER THAN $1.75 -------------------------------- -------------------------- NYMEX PRICE PER ESTIMATED NYMEX ESTIMATED Mmbtu WELLHEAD PRICE PER WELLHEAD QUARTER ENDING Bbtu FLOOR/CAP PRICE PER Mcf Mmbtu PRICE PER Mcf - ----------------- ------- -------------- -------------- --------- -------------- March 31, 2002 1,700 $ 2.25 - 4.00 $ 2.50 - 4.25 Monthly Monthly June 30, 2002 2,550 2.25 - 4.00 2.40 - 4.15 NYMEX NYMEX September 30, 2002 2,550 2.25 - 4.00 2.40 - 4.15 settle plus settle plus December 31, 2002 2,550 2.25 - 4.00 2.47 - 4.22 $0.50 $0.65 to $0.75 ------ -------------- ------------- 9,350 $ 2.25 - 4.00 $ 2.44 - 4.19 ====== ============== =============
NATURAL GAS COLLARS ------------------------------------------------ NYMEX PRICE PER ESTIMATED Mmbtu WELLHEAD Bbtu FLOOR/CAP PRICE PER Mcf ------------- -------------- --------------- March 31, 2003 1,650 $ 3.40 - 5.23 $ 3.65 - 5.48 June 30, 2003 1,650 3.40 - 5.23 3.55 - 5.38 September 30, 2003 1,650 3.40 - 5.23 3.55 - 5.38 December 31, 2003 1,650 3.40 - 5.23 3.62 - 5.45 ------ ------------- ------------- 6,600 $ 3.40 - 5.23 $ 3.59 - 5.42 ====== ============= ============= Mcf - Thousand cubic feet Mmbtu - Million British thermal units Mmcf - Million cubic feet Bbtu - Billion British thermal units 32 ENRON EXPOSURE The Company had physical natural gas sales to Enron from operated and non-operated gas wells. The Company's aggregate exposure related to Enron at December 31, 2001 was approximately $500,000. The Company has fully reserved this amount in the fourth quarter of 2001. Enron was not a counterparty to any of the Company's financial hedging positions. INFLATION AND CHANGES IN PRICES During 1999, the price paid for the Company's crude oil increased from a low of $9.25 per barrel at year-end 1998 to a high of $23.25 per barrel at year-end 1999, with an average price of $16.57 per barrel. During 2000, the price paid for the Company's crude oil fluctuated between a low of $20.75 per barrel and a high of $33.25 per barrel, with an average price of $27.29 per barrel. During 2001, the price paid for the Company's crude oil fluctuated between a low of $13.50 per barrel and a high of $28.50 per barrel, with an average price of $23.04 per barrel. The average price of the Company's natural gas increased from $2.50 per Mcf in 1999 to $3.17 per Mcf in 2000, then increased to $4.34 per Mcf in 2001. The price of oil and natural gas has a significant impact on the Company's results of operations. Oil and natural gas prices fluctuate based on market conditions and, accordingly, cannot be predicted. Costs to drill, complete and service wells can fluctuate based on demand for these services which is generally influenced by high or low commodity prices. The Company's costs and expenses may be subject to inflationary pressures if oil and gas prices are favorable. Prior to 1999, a large portion of the Company's natural gas had been sold subject to long-term fixed price contracts. In 1999, the Company shifted its price risk management procedures to reduce reliance on fixed price contracts. Currently, a large portion of its natural gas is sold subject to market sensitive contracts. Natural gas price risk is mitigated (hedged) by the utilization of over-the-counter NYMEX swaps, options or collars. Natural gas price hedging decisions are made in the context of the Company's strategic objectives, taking into account the changing fundamentals of the natural gas marketplace. 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 availability of capital, production and costs of operation, the market demand for, and prices of oil and natural gas, results of the Company's future drilling, the uncertainties of reserve estimates, environmental risks, availability of financing and other factors detailed in the Company's filings with the SEC. Actual results may differ materially from forward-looking statements made in this report. Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ---------------------------------------------------------- The Company is exposed to, among other risks, interest rate and commodity price risks. The interest rate risk relates to existing debt under the Company's revolving credit facility as well as any new debt financing needed to fund capital requirements. The Company may manage its interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of the Company's floating rate exposure is exchanged for a fixed interest rate. A portion of the Company's long-term debt consists of senior subordinated notes where the interest component is fixed. The Company had no derivative financial instruments for managing interest rate risks in place as of December 31, 2001 and 2000. If market interest rates for short-term borrowings increased 1%, the increase in the Company's interest expense would be approximately $593,000. This sensitivity analysis is based on the Company's financial structure at December 31, 2001. 33 The commodity price risk relates to natural gas and crude oil produced, held in storage and marketed by the Company. The Company's financial results can be significantly impacted as commodity prices fluctuate widely in response to changing market forces. From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to commodity price volatility. The fixed-price physical contracts generally have terms of a year or more. The Company employs a policy of hedging gas production sold under NYMEX based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. If NYMEX gas prices decreased $0.25 per Mcf, the Company's gas sales revenues would decrease by $1.3 million, after considering the effects of the hedging contracts in place at December 31, 2001. If the price of crude oil decreased $2.00 per Bbl, the Company's oil sales revenues would decrease by $1.3 million. This sensitivity analysis is based on the Company's 2001 oil and gas sales volumes. 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 accounting principles generally accepted in the United States. 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 ("E&Y"), are engaged to audit the financial statements and to express an opinion thereon. Their audit is conducted in accordance with auditing standards generally accepted in the United States 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 accounting principles generally accepted in the United States. The aggregate fees for professional services rendered by E&Y for the audit of the Company's financial statements for the year ended December 31, 2001, and the reviews of the financial information included in the Company's Form 10-Q's for the year were $136,200. E&Y did not provide the Company any financial information systems design and implementation services during 2001. The aggregate fees for other services rendered by E&Y in 2001, related primarily to tax consulting and tax compliance services, were $46,100. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ------------------------------------------------ ACCOUNTING AND FINANCIAL DISCLOSURE ----------------------------------- Not applicable. 34 PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT -------------------------------------------------- Executive officers and directors of the Company as of March 5, 2002 were as follows:
Name Age Position - --------------------- ----- ---------- John L. Schwager 53 President, Chief Executive Officer and Director Richard R. Hoffman 51 Senior Vice President Exploration and Production Robert W. Peshek 47 Vice President Finance and Chief Financial Officer David M. Becker 40 Vice President and General Manager, Michigan Exploration and Production District Duane D. Clark 46 Vice President Legal Affairs/Gas Marketing John G. Corp 42 Vice President and General Manager, Arrow Oilfield Service Company William F. Murray 40 Vice President and General Manager, Ohio Exploration and Production District Lawrence W. Kellner 43 Director Robert S. Maust 64 Director William S. Price, III 46 Director Gareth Roberts 49 Director Jeffrey C. Smith 40 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. The Board of Directors consists of six members each of whom is elected annually to serve one-year terms. The business experience of each executive officer and director is summarized below. JOHN L. SCHWAGER has been Chief Executive Officer of the Company since June of 1999. Mr. Schwager was elected to the Board of Directors in August of 1999 and was appointed to the additional position of President upon the departure of the former President in September 1999. He has over 30 years of diversified experience in the oil and gas industry. Prior to joining the Company, he spent two years as President of AnnaCarol Enterprises, Inc., an energy consulting firm specializing in financial and engineering advisory services to exploration and production sector companies. From 1984 to 1997, he was employed by Alamco, Inc., an Appalachian Basin exploration and production company, serving as President and Chief Executive Officer from 1987 to 1997; Executive Vice President from May 1987 to October 1987; and, Senior Vice President - Operations from 1984 to 1987. He also served as Chairman of the Board of TGX Corporation and led TGX out of bankruptcy in 1992. From 1980 to 1984, Mr. Schwager was employed as the Vice President of Production for Callon Petroleum Company in Natchez, 35 Mississippi. From 1970 to 1980, he worked for Shell Oil Company in New Orleans in both engineering and supervisory positions. He last worked at Shell as a Division Drilling Superintendent in the Offshore Division. Mr. Schwager graduated from the University of Missouri at Rolla in 1970 with a Bachelor of Science Degree in Petroleum Engineering. He is a past president and director of the Independent Oil and Gas Association of West Virginia and is currently a member of the Ohio Oil and Gas Association. He also was the cofounder of the Oil and Gas Political Action Committee of West Virginia, serving as cochairman for many years. RICHARD R. HOFFMAN joined the Company as Senior Vice President of Exploration and Production in March of 2001. Mr. Hoffman has worked in the oil and gas industry for 29 years and has extensive operational experience in the Appalachian Basin. From 1998 to 2000, he served as Manager of Production for Dominion Appalachian Development Inc., a subsidiary of Dominion Resources, Inc., specializing in natural gas exploration and production. From 1982 to 1997, he was Executive Vice President and Chief Operating Officer of Alamco, Inc., and served on its Board of Directors from 1988 to 1997. Mr. Hoffman served as Superintendent Production and Drilling/Field Engineer for Cabot Oil and Gas Corporation from 1980 to 1982, and from 1977 to 1980 he was employed by Flint Oil and Gas, Inc., as a Field Engineer. From 1973 to 1977, he held the title of Assistant Production Superintendent/Engineer with The Wiser Oil Company. Mr. Hoffman graduated from West Virginia University with a Bachelor of Science degree in Geology. He is affiliated with numerous oil and gas associations including the Ohio Oil and Gas Association, the West Virginia Oil and Natural Gas Association and the Independent Oil and Gas Association of West Virginia where he served as a Director from 1995 to 1997. He is also a member of the Society of Petroleum Engineers. ROBERT W. PESHEK has served as Vice President of Finance for the Company since 1997 and in 1999 was appointed Chief Financial Officer. Previously, he served as Corporate Controller and Tax Manager from 1994 to 1997. Prior to joining the Company, 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, finance, accounting and auditing. Mr. Peshek holds a Bachelor of Business Administration degree in Accounting from Kent State University where he graduated with honors. His professional affiliations include the American Institute of Certified Public Accountants and the Ohio Society of Certified Public Accountants. Mr. Peshek is a member of the Ohio Oil and Gas Association. DAVID M. BECKER was appointed Vice President of the Company in May 2000, and has been President and Chief Operating Officer of Ward Lake Drilling, Inc., a wholly-owned subsidiary of the Company, and General Manager of the Michigan Exploration and Production District since 1995. Mr. Becker joined the Company as a result of the acquisition of Ward Lake in February of 1995. He worked for Ward Lake Energy, Inc. from 1988 to 1995, serving most recently as President and COO. Previously, he served as Facility Engineer for Shell Oil Company in New Orleans, Louisiana from 1984 to 1988. He has 20 years of experience in the oil and gas industry. Mr. Becker received his Bachelor of Science degree in Mechanical Engineering from Michigan Technical University. His professional affiliations include the Michigan Oil and Gas Association and the American Petroleum Institute. 36 DUANE D. CLARK has been Vice President of Legal Affairs/Gas Marketing for the Company since April 2001. Previously, he served as Vice President of Gas Marketing. He joined the Company in 1995 as a Gas Marketing Analyst. Prior to joining the Company, Mr. Clark held various management positions with Quaker State Corporation from 1978 to 1995. He has 23 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. JOHN G. CORP was appointed Vice President of the Company in May 2000, and has been the General Manager of Arrow Oilfield Service Company, the Company's oil field service division, since November 1999. Prior to that he served as General Manager of the Company's Southern Ohio E&P District from 1987 to 1999. Mr. Corp joined the Company as a Petroleum Engineer. Previously he worked for Park-Ohio Energy as Drilling/Production Engineer from 1979 to 1986. Mr. Corp has 23 years of experience in the oil and gas industry. He attended Marietta College where he received a Bachelor of Science degree in Petroleum Engineering. He is a member of the Society of Petroleum Engineers, the Ohio Oil and Gas Association and a member of the Technical Advisory Committee for the Ohio Department of Natural Resources. WILLIAM F. MURRAY was appointed Vice President of the Company in May 2000, and has served as General Manager of the Company's Ohio E&P District since November 1999. Prior to that he served as General Manager of the Northern OH/Western NY E&P District for the Company from 1983 to 1999. He has 19 years of experience in the industry. Mr. Murray graduated from Marietta College and holds a Bachelor of Science degree in Petroleum Engineering. He is a member of the Society of Petroleum Engineers and a former Board member of the Ohio Society of Petroleum Engineers. His other professional affiliations include the New York Independent Oil and Gas Association, where he is a former member of the Board of Directors, and the Ohio Oil and Gas Association where he currently serves on the Legal Affairs Committee. LAWRENCE W. KELLNER has been a director since 1997. He has been President of Continental Airlines, Inc. since May 2001. He was Executive Vice President and Chief Financial Officer of Continental Airlines, Inc. from November 1996 to May 2001. Mr. Kellner graduated magna cum laude with a Bachelor of Science, Business Administration degree from the University of South Carolina. Mr. Kellner is also a director of Continental Airlines, Inc. ROBERT S. MAUST has been a director since February 2001. He is the Louis F. Tanner Distinguished Professor of Public Accounting at West Virginia University where he has been the Director of the Division of Accounting since 1987. He has been a professor at the University since 1963 and has received numerous teaching and professional honors during his 39-year career. He has published several papers and has contributed to various books and manuals on accounting and business. Mr. Maust is a Certified Public Accountant and has served as an officer of several state, regional and national professional organizations. He received his Bachelor and Master degrees from West Virginia University and Certificate of Ph.D. Candidacy from the University of Michigan. From 1987 to 1997, he served on the Board of Directors of Alamco, Inc., an Appalachian Basin-based firm engaged in the acquisition, exploration, development and production of domestic gas and oil. WILLIAM S. PRICE, III, who became a director upon consummation of the merger with TPG in 1997, was a founding partner of Texas Pacific Group in 1992. Prior to forming Texas Pacific, Mr. Price was Vice President of Strategic Planning and Business Development for G.E. Capital, reporting to the Chairman. In this capacity, Mr. Price was responsible for acquiring new business units and determining 37 the business and acquisition strategies for existing businesses. From 1985 to 1991, Mr. Price was employed by the management consulting firm of Bain & Company, attaining officer status and acting as co-head of the Financial Services Practice. Prior to 1985, Mr. Price was employed as an associate specializing in corporate securities transactions with the legal firm of Gibson, Dunn & Crutcher. Mr. Price is a member of the California Bar and graduated with honors in 1981 from the Boalt Hall School of Law at the University of California, Berkeley. He is a 1978, Phi Beta Kappa graduate of Stanford University. Mr. Price serves on the Board of Directors of Continental Airlines, Inc., Del Monte Foods Company, Denbury Resources, Inc., Gemplus International, S.A., Verado Holdings and several private companies. GARETH ROBERTS has been a director since 1997. He 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 27 years of experience in the exploration and development of oil and 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. JEFFREY C. SMITH has been a director since February 2001. He joined the Texas Pacific Group in 2000 in the capacity of Portfolio Operations Manager. Mr. Smith has 10 years of experience in management consulting, serving most recently as a Strategy Consultant for the management consulting firm of Bain & Company from 1993 to 1999. He was employed by the consulting firms of The L/E/K Partnership and McKinsey & Co., from 1991 to 1993. From 1987 to 1990, he was employed by Exxon USA as a Senior Engineer and from 1985 to 1986, he conducted Academic Research at the Research and Development Division of Conoco, Inc. He received his Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of Texas. Mr. Smith received his Master of Business Administration degree from the Wharton School of Business. 38 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, 2001, 2000 and 1999 of the Company's Chief Executive Officer and its other four most highly compensated executive officers. SUMMARY COMPENSATION TABLE
Long-Term Compensation Annual Compensation Awards -------------------------------------------------- -------------- No. of Shares Other Annual Underlying All Other Name and Principal Position Year Salary Bonus Compensation Options/SARs Compensation(1) - ---------------------------- ----- --------- ---------- ------------ -------------- --------------- John L. Schwager 2001 $ 317,692 $ 292,277(7) $ -- 100,000 $ 8,500 President and 2000 308,654 157,500 -- 66,692 8,500 Chief Executive Officer 1999 173,077 300,000 -- 139,383 113,358(2) Richard R. Hoffman(8) 2001 145,385 83,769 -- 82,500 43,742(3) Senior Vice President of Exploration and Production Leo A. Schrider 2001 145,948 58,380 -- -- 8,500 Senior Vice President of 2000 142,777 36,487 1,370(6) 27,500 7,804 Technical Development 1999 133,000 13,300 -- 55,000(4) 7,635 Robert W. Peshek 2001 164,915 90,703 -- 17,500 8,500 Vice President of Finance and 2000 144,721 40,851 -- 27,500 8,500 Chief Financial Officer 1999 110,617 13,000 -- 55,000(5) 5,531 David M. Becker 2001 139,644 41,893 -- -- 7,831 Vice President of 2000 128,180 33,181 -- 10,000 6,809 Michigan Operations 1999 117,996 11,120 -- 20,000 5,900
------------------------- (1) Represents contributions of cash and common stock to the Company's 401(k) Profit Sharing Plan for the account of the named executive officer. (2) Includes moving expenses of $113,358. (3) Includes moving expenses of $41,373. (4) Includes options for 54,946 shares originally granted in 1997 and repriced in 1999 plus options for 54 shares granted in 1999. (5) Includes options for 25,000 shares originally granted in 1997 and repriced in 1999 plus 30,000 options granted in 1999. (6) Includes amounts related to taxes from a prior year paid by the Company on behalf of the named executive. (7) For financial statement presentation purposes, the Company has accrued an additional bonus of $165,000 for Mr. Schwager. This represents one half of the retention bonus payable to Mr. Schwager on June 30, 2002 if he is still an employee of the Company on that date. The $292,277 represents the annual performance bonus paid to Mr. Schwager. (8) Mr. Hoffman joined the Company in March 2001. 39 OPTION/SAR GRANTS IN LAST FISCAL YEAR
Number of Percentage of Total Shares Options/SARs Underlying Granted to Exercise or Options/SARs Employees in Base Price Expiration Grant Date Name Granted Fiscal Year per Share Date Value(1) - --------------------- ------------- ---------------- ----------- ----------- ----------- John L. Schwager 25,000 6.97% $ 3.59 02/07/11 $ 26,500(2) John L. Schwager 25,000 2.14 12/05/11 14,750(2) John L. Schwager 75,000 20.92% 2.14 12/05/11 44,250 Richard R. Hoffman 82,500 23.01% 3.59 03/05/11 84,975(3) Richard R. Hoffman 82,500 2.14 12/31/11 50,325(3) Robert W. Peshek 17,500 4.88% 2.14 12/31/11 10,675
(1) 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, as determined by the Company on that date, no value will be realized if there is no appreciation in the market price of the stock. The 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: risk-free interest rate of 5.0%; volatility factor of the expected market price of the Company's common stock of near zero; dividend yield of zero; and a weighted-average expected life of the option of seven years. See Note 9 to the Consolidated Financial Statements. (2) The granted option for 25,000 shares had a value of $26,500 on the grant date of February 7, 2001. These options were repriced on December 5, 2001 to $2.14, resulting in a new fair value of $14,750 on the repricing date. (3) The granted option for 82,500 shares had a value of $84,975 on the grant date of March 5, 2001. These options were repriced on December 31, 2001 to $2.14, resulting in a new fair value of $50,325 on the repricing date. AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION/SAR VALUES
Value of Unexercised Number of Shares Underlying Unexercised In-the-Money Shares Options/SARs at FY-End Options/SARs at FY-End Acquired on Value --------------------------------------- ---------------------------- Name Exercise Realized Exercisable Unexercisable Exercisable Unexercisable - ------------------ ----------- -------- ------------ ------------- ----------- ------------- John L. Schwager 39,203 $135,991 26,134 191,471 $53,923 $186,993 Richard R. Hoffman -- -- -- 82,500 -- -- Leo A. Schrider -- -- 82,500 -- 170,225 -- Robert W. Peshek -- -- 29,219 57,031 59,830 81,107 David M. Becker -- -- 10,625 14,375 21,757 29,494
40 TEN-YEAR OPTIONS/SAR REPRICING
Market Number of Shares Price of Number of Months Underlying Stock at Exercise Price of Original Option Term Options/SARs Time of at Time of New Remaining at Date Date of Repriced or Repricing Repricing or Exercise of Repricing Name Repricing Amended or Amendment(1) Amendment Price or Amendment - ---------------------- ------------- --------- -------------- ----------- ------------- ----------------------- John L. Schwager 12/05/01 25,000 $ 2.14 $ 3.59 $ 2.14 110 (2) Richard R. Hoffman 12/31/01 82,500 2.14 3.59 2.14 111 (3) Leo A. Schrider 10/01/99 20,000 0.01 10.82 0.01 98 (4) Robert W. Peshek 10/01/99 25,000 0.01 10.82 0.01 98 (4) Duane D. Clark 10/01/99 15,000 0.01 10.82 0.01 98 (4) David M. Becker 10/01/99 15,000 0.01 10.82 0.01 98 (4) John G. Corp 10/01/99 15,000 0.01 10.82 0.01 98 (4) William F. Murray 10/01/99 15,000 0.01 10.82 0.01 98 (4)
(1) Under the stock option plan, options cannot be issued for less than fair market value at the time of a grant. Since the Company's stock is not actively traded, the Company has determined the value of the stock at October 1, 1999 to be $.01 per share and to be $2.14 per share at December 5, 2001 and December 31, 2001. These values were the basis for the repricings. (2) Options were originally granted on February 7, 2001, leaving 110 months remaining from the original grant date. (3) Options were originally granted on March 5, 2001, leaving 111 months remaining from the original grant date. (4) Options were originally granted on December 1, 1997, leaving 98 months remaining from the original grant date. COMPENSATION OF DIRECTORS The outside directors of the Company are compensated $7,500 per quarter for their services. Directors employed by the Company or by TPG are not compensated for their services. EMPLOYMENT AND SEVERANCE AGREEMENTS Effective July 1, 2001, John Schwager's employment agreement with the Company was amended and restated (the "Agreement"). The term of the Agreement is for three years, subject to extension by mutual agreement. Under the Agreement, Mr. Schwager is entitled to base compensation of $325,000 per annum beginning July 1, 2001 with an increase of $25,000 beginning on January 1, 2003. The Agreement provides for an incentive based bonus, at the discretion of the Board of Directors, of up to 100% of base compensation. There is no minimum incentive based bonus established in the Agreement. The Agreement also provides for an annual retention bonus of $330,000 each year during the term of the Agreement. The annual retention bonus is accelerated and payable in the event of change in control which is defined as any occurrence which would cause TPG's fully diluted equity ownership to drop below 35%. The Agreement further provides for a special retention bonus of $1,000,000, should a change of control occur during or within six months after the expiration of the Agreement, unless Mr. Schwager is employed as the chief executive officer of the surviving company. 41 Either Mr. Schwager or the Company may terminate the Agreement at any time, with or without cause. If Mr. Schwager terminates his employment or is removed for cause, he will not be entitled to receive any compensation or severance pay except for the base compensation, benefits, bonuses and expense reimbursements that have accrued up to and including the final day of his employment with the Company. If the Company terminates Mr. Schwager's employment without cause or if he resigns for good reason (as defined in the Agreement), Mr. Schwager will be entitled to receive monthly payments of 150% of his base salary plus the remaining annual retention bonus payments and continued health care benefits at the Company's expense for two years. In the event of a change of control, all of the aforementioned payments become due and payable at the closing. With the exception of the cost of health care benefits, the amounts payable to Mr. Schwager as outlined above cannot exceed $1,990,000. Mr. Schwager is also entitled to receive an additional payment plus any associated interest and penalties (the "gross up") sufficient to cover any tax imposed by Section 4999 of the Internal Revenue Code on payments made under the Agreement. On February 7, 2001, Mr. Schwager was granted an option to purchase 25,000 shares of the common stock of the Company at $3.59 per share which were repriced on December 5, 2001 at $2.14 per share. He was also granted an option to purchase 75,000 shares of the common stock of the Company on December 5, 2001 at $2.14 per share. One fourth of the option shares shall become exercisable on the last day of each calendar quarter commencing June 30, 2003, provided that he is then an employee or director of the Company. On December 21, 2001, the Company and Leo A. Schrider entered into a Letter of Agreement for Mr. Schrider's transition into retirement. During the transition period from January 2, 2002 through December 31, 2003, Mr. Schrider will work as a part-time employee of the Company, performing such duties as may be assigned. During the transition period, Mr. Schrider will be entitled to receive the full base salary per year that he was receiving as of December 31, 2001. Under the Company's 1999 Severance Pay Plan, all employees whose employment is terminated by the Company without "cause" (as defined therein) are eligible to receive severance benefits ranging from four weeks to twenty-four months, depending on their years of service and position with the Company. Under the Plan, Messrs. Becker, Hoffman and Peshek would be eligible to receive severance pay ranging from twelve months to twenty-four months. The Company has a 1999 Change in Control Protection Plan for Key Employees providing severance benefits for such employees if, within six months prior to a change in control or within two years thereafter, their employment is terminated without "cause" (as defined therein) or if they resign in response to a reduction in duties, responsibilities, position, compensation or medical benefits or a change in the location of their place of work as defined in the agreement. Such benefits range from twelve months to twenty-four months, depending on their position with the Company. Under the Plan, Messrs. Becker, Hoffman and Peshek would be eligible to receive severance pay of twenty-four months. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION The Compensation and Organization Committee consisted of three outside directors, William S. Price III, Gareth Roberts and Henry S. Belden IV. On September 12, 2001 Mr. Belden resigned his position of director, leaving Mr. Price and Mr. Roberts as the remaining committee members. No executive officer of the Company was a director or member of a compensation committee of any entity of which a member of the Company's Board of Directors was or is an executive member. 42 Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT --------------------------------------------------------------- The following table sets forth certain information as of February 28, 2002 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:
PERCENTAGE OF FIVE PERCENT SHAREHOLDERS NUMBER OF SHARES SHARES - ------------------------------------------------------------- ------------------ ---------------- TPG Advisors II, Inc. 201 Main Street, Suite 2420 Fort Worth, Texas 76102 9,353,038(1) 88.7% 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 430 West Allegan Lansing, MI 48922 554,376 5.3% OFFICERS AND DIRECTORS - ------------------------------------------------------------- William S. Price, III 9,353,038(1) 88.7% John L. Schwager 130,670(2) 1.2% Lawrence W. Kellner -0- -0- Gareth Roberts -0- -0- Robert S. Maust -0- -0- Jeffrey C. Smith -0- -0- Richard R. Hoffman -0- -0- Robert W. Peshek 48,126(2) * Leo A. Schrider 82,500(2) * David M. Becker 17,500(2) * All directors and executive officers (13) as a group 9,684,334 91.8%
* 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 Partners II, L.P., 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 by Mr. Schwager as to 13,066 shares, Mr. Peshek as to 34,376 shares, Mr. Schrider as to 82,500 shares and Mr. Becker as to 12,500 shares. 43 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS In connection with the merger with TPG in 1997, 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 merger as compensation for its services as financial advisor in connection with the merger. 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. 44 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) 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) 45 10.1(a) Peake Energy, Inc. Stock Purchase Agreement between the Company and North Coast Energy, Inc. --incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000. 10.1(b) Credit Agreement dated as of August 23, 2000 by and among the Company, Ableco Finance LLC and Foothill Capital Corporation. --incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000. 10.1(c)* Amendment to the Credit Agreement dated as of June 29, 2001 by and among the Company, Ableco Finance LLC and Foothill Capital Corporation. 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 Retirement and noncompetition agreement dated May 26, 1999 by and between the Company and Ronald L. Clements --incorporated by reference to Exhibit 10.3(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1999. 10.5 Belden & Blake Corporation 1997 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) 10.7 Change in Control Severance Pay Plan for Key Employees of the Company dated August 12, 1999 --incorporated by reference to Exhibit 10.7 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999. 10.8 Severance Pay Plan for Employees of Belden & Blake Corporation dated August 12, 1999 --incorporated by reference to Exhibit 10.8 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999. 10.10 Employment Agreement dated June 1, 1999 and amended November 1, 1999 by and between the Company and John L. Schwager --incorporated by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999. 10.11* Amended and Restated Employment Agreement dated July 1, 2001 by and between the Company and John L. Schwager. 10.12* Letter of Agreement dated December 21, 2001 by and between the Company and Leo A. Schrider. 21* Subsidiaries of the Registrant 23* Consent of Independent Auditors *Filed herewith 46 (b) Reports on Form 8-K On November 14, 2001 the Company filed a Current Report on Form 8-K dated November 13, 2001 related to Regulation FD disclosures. (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. 47 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 21, 2002 By: /s/ John L. Schwager - --------------------------------- ---------------------------------------- Date John L. Schwager, Director, President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. /s/ John L. Schwager Director, President March 21, 2002 - ------------------------------------- and Chief Executive Officer -------------- John L. Schwager (Principal Executive Officer) Date /s/ Robert W. Peshek Vice President Finance and March 21, 2002 - ------------------------------------- Chief Financial Officer -------------- Robert W. Peshek (Principal Financial and Date Accounting Officer) /s/ Lawrence W. Kellner Director March 21, 2002 - ------------------------------------- -------------- Lawrence W. Kellner Date /s/ Robert S. Maust Director March 21, 2002 - ------------------------------------- -------------- Robert S. Maust Date /s/ William S. Price, III Director March 13, 2002 - ------------------------------------- -------------- William S. Price, III Date /s/ Gareth Roberts Director March 21, 2002 - ------------------------------------- -------------- Gareth Roberts Date /s/ Jeffrey C. Smith Director March 15, 2002 - ------------------------------------- -------------- Jeffrey C. Smith Date
48 BELDEN & BLAKE CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES ITEM 14(a)(1) AND (2) CONSOLIDATED FINANCIAL STATEMENTS Page Report of Independent Auditors..................................... F-2 Consolidated Balance Sheets as of December 31, 2001 and 2000....... F-3 Consolidated Statements of Operations: Years ended December 31, 2001, 2000 and 1999..................... F-4 Consolidated Statements of Shareholders' Equity (Deficit): Years ended December 31, 2001, 2000 and 1999..................... F-5 Consolidated Statements of Cash Flows: Years ended December 31, 2001, 2000 and 1999..................... 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 REPORT OF INDEPENDENT AUDITORS To the Shareholders and Board of Directors Belden & Blake Corporation We have audited the accompanying consolidated balance sheets of Belden & Blake Corporation ("Company") as of December 31, 2001 and 2000, and the related consolidated statements of operations, shareholders' equity (deficit) and cash flows for each of the three years in the period ended December 31, 2001. 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 auditing standards generally accepted in the United States. 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, 2001 and 2000 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States. As discussed in Note 4 to the Consolidated Financial Statements, on January 1, 2001, Belden & Blake Corporation adopted Statements of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." ERNST & YOUNG LLP Cleveland, Ohio March 13, 2002 F-2 BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31, --------------------------- 2001 2000 --------- --------- ASSETS - ------ CURRENT ASSETS Cash and cash equivalents $ 1,935 $ 1,798 Accounts receivable, net 14,160 22,620 Inventories 1,695 2,222 Deferred income taxes -- 1,475 Other current assets 1,094 1,448 Fair value of derivatives 19,965 -- --------- --------- TOTAL CURRENT ASSETS 38,849 29,563 PROPERTY AND EQUIPMENT, AT COST Oil and gas properties (successful efforts method) 446,977 413,824 Gas gathering systems 14,094 13,445 Land, buildings, machinery and equipment 24,113 23,469 --------- --------- 485,184 450,738 Less accumulated depreciation, depletion and amortization 233,396 208,435 --------- --------- PROPERTY AND EQUIPMENT, NET 251,788 242,303 FAIR VALUE OF DERIVATIVES 3,748 -- OTHER ASSETS 10,964 13,251 --------- --------- $ 305,349 $ 285,117 ========= ========= LIABILITIES AND SHAREHOLDERS' DEFICIT - ------------------------------------- CURRENT LIABILITIES Accounts payable $ 5,253 $ 5,926 Accrued expenses 14,465 19,316 Current portion of long-term liabilities 156 141 Deferred income taxes 5,470 -- --------- --------- TOTAL CURRENT LIABILITIES 25,344 25,383 LONG-TERM LIABILITIES Bank and other long-term debt 59,415 61,535 Senior subordinated notes 225,000 225,000 Other 330 323 --------- --------- 284,745 286,858 DEFERRED INCOME TAXES 22,539 21,189 SHAREHOLDERS' DEFICIT Common stock without par value; $.10 stated value per share; authorized 58,000,000 shares; issued 10,425,103 and 10,357,255 shares (which includes 135,369 and 53,972 treasury shares, respectively) 1,029 1,030 Paid in capital 107,402 107,921 Deficit (150,797) (157,264) Accumulated other comprehensive income 15,087 -- --------- --------- TOTAL SHAREHOLDERS' DEFICIT (27,279) (48,313) --------- --------- $ 305,349 $ 285,117 ========= =========
See accompanying notes. F-3 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ------------------------------------------------- 2001 2000 1999 --------- --------- --------- REVENUES Oil and gas sales $ 95,395 $ 79,743 $ 79,299 Gas gathering, marketing, and oilfield sales and service 34,087 34,850 51,445 Other 2,048 3,258 5,017 --------- --------- --------- 131,530 117,851 135,761 EXPENSES Production expense 22,649 20,917 21,980 Production taxes 2,372 2,409 3,260 Gas gathering, marketing, and oilfield sales and service 29,382 31,703 46,977 Exploration expense 8,346 8,528 6,442 General and administrative expense 4,395 4,617 5,412 Franchise, property and other taxes 250 397 652 Depreciation, depletion and amortization 27,332 27,460 41,412 Impairment of oil and gas properties and other assets 1,398 477 -- Severance and other nonrecurring expense 1,954 241 3,285 --------- --------- --------- 98,078 96,749 129,420 --------- --------- --------- OPERATING INCOME 33,452 21,102 6,341 OTHER (INCOME) EXPENSE (Gain) loss on sale of subsidiaries and other income -- (15,064) 1,521 Interest expense 27,476 29,473 34,302 --------- --------- --------- 27,476 14,409 35,823 --------- --------- --------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM 5,976 6,693 (29,482) (Benefit) provision for income taxes (491) 2,368 (11,179) --------- --------- --------- INCOME (LOSS) BEFORE EXTRAORDINARY ITEM 6,467 4,325 (18,303) Extraordinary item - early extinguishment of debt, net of tax benefit -- (1,364) -- --------- --------- --------- NET INCOME (LOSS) $ 6,467 $ 2,961 $ (18,303) ========= ========= =========
See accompanying notes. F-4 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT) (IN THOUSANDS)
ACCUMULATED OTHER TOTAL COMMON COMMON PAID IN COMPREHENSIVE EQUITY SHARES STOCK CAPITAL DEFICIT INCOME (DEFICIT) ------ ------ -------- --------- ------------- --------- JANUARY 1, 1999 10,111 $1,011 $107,897 $(141,922) $ -- $(33,014) Net loss (18,303) (18,303) Stock options exercised 31 3 3 Stock-based compensation 118 12 (288) (276) - ------------------------------------------------------ ------ ------ -------- --------- -------- -------- DECEMBER 31, 1999 10,260 1,026 107,609 (160,225) -- (51,590) Net income 2,961 2,961 Stock options exercised 97 10 (9) 1 Stock-based compensation 336 336 Treasury stock (54) (6) (15) (21) - ------------------------------------------------------ ------ ------ -------- --------- -------- -------- DECEMBER 31, 2000 10,303 1,030 107,921 (157,264) -- (48,313) Comprehensive income: Net income 6,467 6,467 Other comprehensive income, net of tax: Cumulative effect of accounting change (6,691) (6,691) Change in derivative fair value 24,667 24,667 Reclassification adjustments - contract settlements (2,889) (2,889) --------- Total comprehensive income 21,554 --------- Stock options exercised 68 7 (1) 6 Stock-based compensation 275 275 Repurchase of stock options (772) (772) Tax benefit of repurchase of stock options and stock options exercised 260 260 Treasury stock (81) (8) (281) (289) - ------------------------------------------------------ ------ ------ -------- --------- -------- -------- DECEMBER 31, 2001 10,290 $1,029 $107,402 $(150,797) $15,087 $(27,279) ====================================================== ====== ====== ======== ========= ======== ========
See accompanying notes. F-5 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ----------------------------------- 2001 2000 1999 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ 6,467 $ 2,961 $ (18,303) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Net loss on early extinguishment of debt -- 1,364 -- Depreciation, depletion and amortization 27,332 27,460 41,412 Impairment of oil and gas properties and other assets 1,398 477 -- (Gain) loss on sale of subsidiaries -- (13,794) 1,521 Loss on disposal of property and equipment 92 500 136 Exploration expense 8,346 8,528 6,442 Deferred income taxes (605) 2,077 (11,179) Stock-based compensation 275 169 (565) Change in operating assets and liabilities, net of effects of disposition of subsidiaries: Accounts receivable and other operating assets 9,200 (442) 8,580 Inventories 571 (674) 2,413 Accounts payable and accrued expenses (5,001) (102) (7,867) --------- --------- --------- NET CASH PROVIDED BY OPERATING ACTIVITIES 48,075 28,524 22,590 CASH FLOWS FROM INVESTING ACTIVITIES: Acquisition of businesses, net of cash acquired (2,149) -- -- Disposition of businesses, net of cash 897 69,031 7,887 Proceeds from property and equipment disposals 1,162 218 3,011 Exploration expense (8,346) (8,528) (6,442) Additions to property and equipment (35,730) (18,624) (2,996) (Increase) decrease in other assets (81) (83) 2,140 --------- --------- --------- NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES (44,247) 42,014 3,600 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving line of credit and term loan 181,645 123,096 21,000 Repayment of long-term debt and other obligations (184,071) (190,814) (50,582) Debt issue costs (210) (5,537) (2,766) Proceeds from stock options exercised 6 -- 3 Repurchase of stock options (772) -- -- Purchase of treasury stock (289) (21) -- --------- --------- --------- NET CASH USED IN FINANCING ACTIVITIES (3,691) (73,276) (32,345) --------- --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 137 (2,738) (6,155) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,798 4,536 10,691 --------- --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,935 $ 1,798 $ 4,536 ========= ========= =========
See accompanying notes. F-6 BELDEN & BLAKE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES BUSINESS - -------- Belden & Blake Corporation (the "Company") is a privately held company owned by TPG Partners II L.P. ("TPG") and certain other investors. The Company operates in the oil and gas industry. The Company's principal business is the production, development, acquisition and marketing and gathering of oil and gas reserves. Sales of oil are ultimately made to refineries. Sales of natural gas are ultimately made to gas utilities and industrial consumers in Ohio, Michigan, Pennsylvania and New York. The price of oil and natural 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. Certain reclassifications have been made to conform to the presentation in 2001. 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 investments purchased with an initial maturity of three months or less. CONCENTRATIONS OF CREDIT RISK - ----------------------------- Credit limits, ongoing credit evaluation and account monitoring procedures are utilized to minimize the risk of loss. Collateral is generally not required. Expected losses are provided for currently and actual losses have been within management's expectations. INVENTORIES - ----------- Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural gas inventories are stated at the lower of average cost or market. PROPERTY AND EQUIPMENT - ---------------------- The Company utilizes the "successful efforts" method of accounting for its oil and gas properties. Under this method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry holes and costs of carrying and retaining unproved properties, 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. F-7 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. Impairments recorded in 2001 and 2000 were $179,000 and $477,000, respectively, which reduced the book value of unproved oil and gas properties to their estimated fair value. Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed 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 the carrying amount of the asset. In performing the review for long-lived asset recoverability during 2001, the Company recorded $1.2 million of impairments which reduced the book value of producing properties to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the assets, discounted at a market rate of interest. No impairment was recorded in 2000 or 1999. INTANGIBLE ASSETS - ----------------- Intangible assets totaling $9.5 million at December 31, 2001, 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. (APB) 25, "Accounting for Stock Issued to Employees" and its related interpretations. In March 2000, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. (FIN) 44, "Accounting for Certain Transactions involving Stock Compensation, an interpretation of APB 25." The Interpretation, which has been adopted prospectively as of July 1, 2000, requires that stock F-8 options that have been modified to reduce the exercise price be accounted for as variable. Prior to the adoption of the Interpretation, the Company accounted for these repriced stock options as fixed. The effect of adopting the Interpretation was to increase compensation expense by $298,000 in the second half of the year ended December 31, 2000. The Company repriced 318,892 stock options (298,392 outstanding prior to July 1, 2000) in October 1999, and reduced the exercise price to $0.01 per share. Under the Interpretation, the options are accounted for as variable from July 1, 2000 until the options are exercised, forfeited or expire unexercised. The Company repriced 227,500 stock options in December 2001, which had been granted in 2001 at $3.59 per share and reduced the exercise price to $2.14 per share. The definition of a public company under FIN 44 is less restrictive than previous practice. Specifically, a company with publicly-traded debt, but not publicly-traded equity securities, would not be considered public. Prior to July 1, 2000, Belden & Blake Corporation common stock held in the 401(k) plan was subject to variable plan accounting. The changes in share value are reported as adjustments to compensation expense. The change in share value in 2001 and 2000 resulted in an increase in compensation expense of $275,000 and $336,000, respectively. The reduction in share value in 1999 resulted in a reduction in compensation expense of $858,000. DERIVATIVES AND HEDGING - ----------------------- On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. (SFAS) 133, "Accounting for Derivative Instruments and Hedging Activities" which was issued in June, 1998 by the FASB, as amended by SFAS 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of Effective Date of SFAS 133" and SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" issued in June 1999 and June 2000, respectively. SFAS 133, as amended, was applied as the cumulative effect of an accounting change effective January 1, 2001. As a result of the adoption of SFAS 133, the Company recognizes all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss). Ineffective portions of a derivative instrument's change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be recognized as increases or decreases to oil and gas revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss). See Note 4. The relationship between the hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk, both at the inception of the contract and on an ongoing basis. The Company measures effectiveness on changes in the hedge's intrinsic value. The Company considers these hedges to be highly effective and expects there will be no ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging instruments and the hedged forecasted transactions are the same. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. The Company measures effectiveness at least on a quarterly basis. F-9 The adoption of SFAS 133 resulted in a January 1, 2001, transition adjustment to increase other current liabilities by $10.5 million, increase current deferred income taxes by $3.8 million and increase shareholders' deficit by $6.7 million to record the fair value of open cash flow hedges and the related income tax effect. The increase in shareholders' deficit is reflected as a cumulative effect of accounting change in accumulated other comprehensive income (loss). Prior to January 1, 2001, under the deferral method, gains and losses from derivative instruments that qualified as hedges were deferred until the underlying hedged asset, liability or transaction monetized, matured or was otherwise recognized under generally accepted accounting principles. When recognized in net income (loss), hedge gains and losses were included as an adjustment to gas revenue or interest expense. (2) NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the FASB issued Statements of Financial Accounting Standards No. 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets." The adoption of SFAS 141 as of July 1, 2001 had no effect on the Company's financial position, results of operations or cash flows. SFAS 141 eliminates the pooling-of-interests method of accounting for business combinations except for qualifying business combinations that were initiated prior to July 1, 2001. SFAS 141 further clarifies the criteria to recognize intangible assets separately from goodwill. The requirements of SFAS 141 are effective for any business combination accounted for by the purchase method that was completed after June 30, 2001. Under SFAS 142, goodwill and indefinite lived intangible assets are no longer amortized but are reviewed for impairment annually or if certain impairment indicators arise. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life). The amortization provisions of SFAS 142 apply to goodwill and intangible assets acquired after June 30, 2001. With respect to goodwill and intangible assets acquired prior to July 1, 2001, the Company is required to adopt SFAS 142 on January 1, 2002. Early adoption is not permitted for calendar year companies. At December 31, 2001, the Company had $2.7 million of unamortized goodwill which will be subject to the transition provisions of SFAS 142. Amortization expense related to goodwill amounted to $130,000, $132,000 and $208,000 for the years ended December 31, 2001, 2000 and 1999, respectively. The Company is currently assessing the impact of SFAS 142 and has not yet determined whether adoption will have a material effect on the Company's financial position, results of operations or cash flows including any transitional impairment losses which would be required to be recognized as the effect of a change in accounting principle. In August 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 addresses obligations associated with the retirement of tangible, long-lived assets and the associated asset retirement costs. This statement amends SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies", and is effective for the Company's financial statements beginning January 1, 2003. The Company is currently assessing the impact of SFAS 143 and has not yet determined whether adoption will have a material effect on the Company's financial position, results of operations or cash flows. In October 2001, the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which establishes a single accounting model to be used for long-lived assets to be disposed of. The new rules supersede SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Although retaining many of the fundamental recognition and measurement provisions of SFAS 121, the new rules significantly change the criteria that would have F-10 to be met to classify an asset as held-for-sale. This distinction is important because assets to be disposed of are stated at the lower of their fair values or carrying amounts and depreciation is no longer recognized. The new rules also will supersede the provisions of APB 30, "Reporting Results of Operations - Reporting the Effects of Disposal of a Segment of Business," with regard to reporting the effects of a disposal of a segment of a business and will require the expected future operating losses from discontinued operations to be displayed in discontinued operations in the periods in which the losses are incurred rather than as of the measurement date as presently required by APB 30. In addition, more dispositions will qualify for discontinued operations treatment in the income statement. SFAS 144 is effective as of January 1, 2002. The adoption of this standard is not expected to have a material effect on the Company's financial position, results of operations or cash flows. (3) SALE OF SUBSIDIARIES On March 17, 2000, the Company sold the stock of Peake Energy, Inc. ("Peake"), a wholly owned subsidiary, to North Coast Energy, Inc., an independent oil and gas company. The sale included substantially all of the Company's oil and gas properties in West Virginia and Kentucky. The sale resulted in net proceeds of approximately $69.2 million. The Company recorded a $13.7 million gain on the sale in 2000. At December 31, 1999, using Securities and Exchange Commission ("SEC") pricing parameters, Peake had proved developed reserves of approximately 66.5 Bcfe (billion cubic feet of natural gas equivalent) and proved undeveloped reserves of approximately 3.7 Bcfe. At the time of the sale, Peake's reserves represented 20.2% of the Company's total proved reserves. The unaudited pro forma results of operations of the Company for the years ended December 31, 2000 and 1999 are as follows: revenues of $113.8 million and $118.2 million, respectively. The pro forma effects on net income were not material. The unaudited pro forma information presented above assumes the disposition occurred prior to each period presented and does not purport to be indicative of the results that actually would have been obtained and is not intended to be a projection of future results or trends. In November 1999, the Company sold Belden Energy Services Company ("BESCO"), its Ohio retail natural gas marketing subsidiary, to FirstEnergy Corp. In the future, that portion of the Company's Ohio natural gas production not committed to existing sales contracts will be sold on the wholesale market. The Company recorded a $1.3 million gain on the sale in 1999. In August 1999, the Company and its wholly owned subsidiary, The Canton Oil and Gas Company ("COG"), completed a stock sale of Target Oilfield Pipe and Supply ("TOPS"), a wholly owned subsidiary of COG, to an oilfield supply company. The buyer purchased all of the issued and outstanding shares of capital stock of TOPS from COG. The Company recorded a $2.8 million loss on the sale in 1999. (4) DERIVATIVES AND HEDGING On January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. As a result of the adoption of SFAS 133, the Company recognizes all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss). The hedging relationship between the hedging instruments and hedged item must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. The Company measures effectiveness at least on a F-11 quarterly basis. Ineffective portions of a derivative instrument's change in fair value are immediately recognized in net income (loss). If there is a discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately. 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 or oil price volatility. The Company employs a policy of hedging gas production sold under New York Mercantile Exchange ("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, collars or options. At December 31, 2001, the Company's derivative contracts consisted of natural gas swaps and natural gas costless collars. All of these NYMEX based derivative contracts were designated as cash flow hedges. Adoption of SFAS 133 on January 1, 2001 resulted in recording a $10.5 million ($6.7 million net of tax) net liability related to the decline in fair value of the Company's derivative financial instruments with a corresponding reduction in shareholders' equity to other comprehensive loss. The net liability consisted of $11.8 million in current fair value of derivative liabilities and $1.3 million in current fair value of derivative assets. The fair value of derivative assets and liabilities represents the difference between hedged prices and market prices on hedged volumes of natural gas as of December 31, 2001. During 2001, a net gain on contract settlements of $4.5 million ($2.9 million after tax) was reclassified from accumulated other comprehensive income to earnings and the fair value of open hedges increased by $38.8 million ($24.7 million after tax). At December 31, 2001, the estimated net gains in accumulated other comprehensive income that are expected to be reclassified into earnings within the next 12 months are approximately $20.0 million. The Company has partially hedged its exposure to the variability in future cash flows through December 2003. On January 17 and 18, 2002, the Company monetized and restructured 9,350 Bbtu (Billion British thermal units) of its 2002 and 3,840 Bbtu of its 2003 natural gas hedge positions for net proceeds of $21.7 million. See Note 19. (5) SEVERANCE AND OTHER NONRECURRING EXPENSE Effective April 1, 2001, certain senior management members of the Company accepted early retirements. These retirements resulted in a cash charge of approximately $760,000 and an additional non-cash charge of approximately $100,000 related to the acceleration of certain stock options. The Company recorded a net nonrecurring charge of $2.0 million in 2001 which includes a charge of $2.3 million primarily related to these retirement agreements and other retirement and severance charges incurred which included non-cash charges totaling approximately $200,000 due to the acceleration of certain related stock options. In 2001, the Company recognized approximately $300,000 in other nonrecurring gains. The Company expensed approximately $241,000 and $880,000 in 2000 and 1999, respectively, for costs primarily associated with investment banking fees, an abandoned acquisition effort and the abandonment of a proposed public offering of a royalty trust. In September 1999, the Company implemented a plan to reduce costs and improve operating efficiencies. The plan included actions to bring the Company's employment level in line with current and anticipated future staffing needs which resulted in staff reductions of approximately 10%. The Company recorded a charge of $2.4 million in 1999 for severance and other costs associated with implementing this plan. F-12 (6) DETAILS OF BALANCE SHEETS DECEMBER 31, ------------------------- 2001 2000 --------- --------- ACCOUNTS RECEIVABLE (IN THOUSANDS) Accounts receivable $ 6,701 $ 12,333 Allowance for doubtful accounts (1,684) (1,245) Oil and gas production receivable 8,614 11,358 Current portion of notes receivable 529 174 --------- --------- $ 14,160 $ 22,620 ========= ========= INVENTORIES Oil $ 1,352 $ 1,272 Natural gas 27 104 Material, pipe and supplies 316 846 --------- --------- $ 1,695 $ 2,222 ========= ========= PROPERTY AND EQUIPMENT, GROSS OIL AND GAS PROPERTIES Producing properties $ 419,206 $ 390,229 Non-producing properties 12,097 7,676 Other 15,674 15,919 --------- --------- $ 446,977 $ 413,824 ========= ========= LAND, BUILDINGS, MACHINERY AND EQUIPMENT Land, buildings and improvements $ 5,526 $ 5,632 Machinery and equipment 18,587 17,837 --------- --------- $ 24,113 $ 23,469 ========= ========= ACCRUED EXPENSES Accrued expenses $ 4,877 $ 5,901 Accrued drilling and completion costs 827 1,624 Accrued income taxes 93 481 Ad valorem and other taxes 1,903 2,449 Compensation and related benefits 2,748 2,685 Undistributed production revenue 4,017 6,176 --------- --------- $ 14,465 $ 19,316 ========= ========= F-13 (7) LONG-TERM DEBT Long-term debt consists of the following (in thousands): DECEMBER 31, ------------------------ 2001 2000 -------- -------- Revolving line of credit $ 59,292 $ 61,393 Senior subordinated notes 225,000 225,000 Other 142 161 -------- -------- 284,434 286,554 Less current portion 19 19 -------- -------- Long-term debt $284,415 $286,535 ======== ======== 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"). The Notes were issued under an indenture which requires interest to be paid semiannually on June 15 and December 15 of each year, commencing December 15, 1997. The Notes are subordinate to the senior revolving credit agreement. In September 1997, the Company completed a registration statement on Form S-4 providing for an exchange offer under which each Series A Senior Subordinated Note would be exchanged for a Series B Senior Subordinated Note. The terms of the Series B Notes are the same in all respects as the Series A Notes except that the Series B Notes have been registered under the Securities Act of 1933 and therefore will not be subject to certain restrictions on transfer. The Notes are redeemable in whole or in part at the option of the Company, at any time on or after the dates below, at the redemption prices set forth plus, in each case, accrued and unpaid interest, if any, thereon. June 15, 2002....................................... 104.938% June 15, 2003....................................... 103.292% June 15, 2004....................................... 101.646% June 15, 2005 and thereafter........................ 100.000% 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 December 14, 1999, the Company and its bank group amended its senior revolving credit facility. The revolving credit commitment in the amended agreement provided for a $75 million revolving portion which would have matured on June 27, 2002 and a $50 million term portion which would have matured on March 31, 2000. Proceeds from the Peake sale were used to repay the term portion and repay and permanently reduce the revolving credit commitment. In March 2000, the Company obtained the unanimous consent of its bank group to further amend the revolving credit agreement to establish a borrowing base of $62.7 million and to forego the May 2000 borrowing base redetermination. On August 23, 2000, the Company obtained a new $125 million credit facility ("the Facility") comprised of a $100 million revolving credit facility ("the Revolver") and a $25 million term loan (the F-14 "Term Loan"). The Facility allowed for up to $40 million ($25 million under the Term Loan and $15 million under the Revolver) to be used to purchase the Company's outstanding 9 7/8% senior subordinated notes due 2007. No amounts were drawn under the Term Loan. The Term Loan commitment terminated on December 26, 2000 and the Company wrote off approximately $740,000 of unamortized deferred loan costs in 2000 due to the modification of borrowing capacity. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At December 31, 2001, the interest rate was 6.75%. Up to $30 million in letters of credit may be issued pursuant to the conditions of the Revolver. At December 31, 2001, the Company had $2.3 million of outstanding letters of credit. Initial proceeds from the Revolver of approximately $66 million in 2000 were used to pay outstanding loans and interest due under the Company's former credit facility of approximately $46 million; repay a term loan of $14 million to Chase Manhattan Bank; pay fees and expenses associated with the new credit facility of approximately $4 million; and to close out certain natural gas hedging transactions with Chase Manhattan Bank. Due to the payment of the outstanding loans under the former credit facility the Company took a charge of $2.1 million ($1.4 million net of tax benefit) in 2000 representing the unamortized deferred loan costs pertaining to the former credit facility. The charge was recorded as an extraordinary item. On June 29, 2001, the Company amended the Revolver. The amendment extended the Revolver's final maturity date to April 22, 2004, from August 23, 2002, increased the letter of credit sub-limit from $20 million to $30 million and eliminated the effects of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," from financial covenant calculations. The Company paid approximately $200,000 in fees and expenses related to the amendment. At December 31, 2001, the Company had $2.3 million of outstanding letters of credit. At December 31, 2001, the outstanding balance under the credit agreement was $59.3 million with $38.4 million of borrowing capacity available for general corporate purposes. The amendment added an early termination fee equal to .25% of the facility if terminated between the effective date and May 31, 2002. If termination is after May 31, 2002 but on or before May 31, 2003, the termination fee is .125% of the facility. There is no termination fee after May 31, 2003. The Company is required to hedge, through financial instruments or fixed price contracts, at least 20% but not more than 80% of its estimated hydrocarbon production, on an Mcfe (thousand cubic feet of natural gas equivalent) basis, for the succeeding 12 months on a rolling 12-month basis. Based on the Company's hedges currently in place and its expected production levels, the Company is in compliance with this hedging requirement through March 2003. The Revolver is secured by security interests and mortgages against substantially all of the Company's assets and is subject to periodic borrowing base determinations. The borrowing base is the lesser of $100 million or the sum of (i) 65% of the value of the Company's proved developed producing reserves subject to a mortgage; (ii) 45% of the value of the Company's proved developed non-producing reserves subject to a mortgage; and (iii) 40% of the value of the Company's proved undeveloped reserves subject to a mortgage. The price forecast used for calculation of the future net income from proved reserves is the three-year NYMEX strip for oil and natural gas as of the date of the reserve report. Prices beyond three years are held constant. Prices are adjusted for basis differential, fixed price contracts and financial hedges in place. The present value (using a 10% discount rate) of the Company's future net income at December 31, 2001, under the borrowing base formula above was approximately $196 million for all proved reserves of the Company and $146 million for properties secured by a mortgage. The Revolver is subject to certain financial covenants. These include a senior debt interest coverage ratio ranging from 3.7 to 1 at December 31, 2001, to 3.2 to 1 at March 31, 2004; and a senior debt leverage ratio ranging from 2.6 to 1 and 3.2 to 1 for the periods from December 31, 2001 through F-15 March 31, 2004. EBITDA, as defined in the Revolver, and consolidated interest expense on senior debt in these ratios are calculated quarterly based on the financial results of the previous four quarters. In addition, the Company is required to maintain a current ratio (including available borrowing capacity in current assets and excluding current debt and accrued interest from current liabilities and excluding any effects from the application of SFAS 133 to other current assets or current liabilities) of at least 1.0 to 1 and maintain liquidity of at least $5 million (cash and cash equivalents including available borrowing capacity). As of December 31, 2001, the Company's current ratio including the above adjustments was 3.11 to 1. The Company had satisfied all financial covenants as of December 31, 2001. 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 is 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 (London Interbank Offered Rate) for a fixed rate of 7.485% (which includes an applicable margin of 1.5%) 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 for a fixed rate of 7.649% (which includes an applicable margin of 1.5%) for five years. During June 1998, the Company entered into a third interest rate swap covering $50 million of debt. The Company swapped $50 million of floating rate three-month LIBOR for a fixed rate of 7.2825% (which includes an applicable margin of 1.5%) for three years. On December 27, 1999, the Company terminated $20 million of the third interest rate swap. On March 21, 2000, the Company terminated the second swap and the remainder of the third swap for a total of $80 million which resulted in a gain of $1.3 million. The remaining swap arrangements covering $40 million of debt expired in October 2000. At December 31, 2001, the aggregate long-term debt maturing in the next five years is as follows: $19,000 (2002); $19,000 (2003); $59,296,000 (2004); $4,000 (2005); and $225,096,000 (2006 and thereafter). (8) LEASES The Company leases certain computer equipment, vehicles, natural gas compressors and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $2.9 million, $2.7 million and $3.1 million for the years ended December 31, 2001, 2000 and 1999, respectively. The Company also leases certain computer equipment accounted for as capital leases. Property and equipment includes $647,000 and $239,000 of computer equipment under capital leases at December 31, 2001 and 2000, respectively. Accumulated depreciation for such equipment includes approximately $289,000 and $90,000 at December 31, 2001 and 2000, respectively. F-16 Future minimum commitments under leasing arrangements at December 31, 2001 were as follows: OPERATING CAPITAL YEAR ENDING DECEMBER 31, LEASES LEASES -------------------------------------------------- -------------- ----------- (IN THOUSANDS) 2002 $1,252 $ 137 2003 481 127 2004 414 62 2005 267 -- 2006 and thereafter 52 -- ------ ------- Total minimum rental payments $2,466 326 ====== Less amount representing interest 3 ------ Present value of net minimum rental payments 323 Less current portion 137 ------ Long-term capitalized lease obligations $ 186 ====== (9) STOCK OPTION PLANS In connection with the TPG merger, certain executives of the Company agreed not to exercise or surrender certain stock options granted under the Company's 1991 stock option plan. On June 27, 1997, these options were exchanged for 165,083 in new stock options. As of December 31, 2001, none of these options were outstanding. No additional options may be granted under the 1991 plan. The Company has a 1997 non-qualified stock option plan under which it is authorized to issue up to 1,824,195 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. As of December 31, 2001, options to purchase 781,606 shares were outstanding under the plan. These options, except for the 100,000 options described below, become exercisable at a rate of one fourth of the shares one year from the date of grant and an additional one twelfth of the remaining shares on every three-month anniversary thereafter. The remaining 100,000 options become exercisable at a rate of one fourth of the shares on the last day of each quarter commencing June 30, 2003. The Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related Interpretations in accounting for its employee stock options. 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 when the exercise price of the Company's employee stock options equals the market price of the underlying stock on the date of the grant. There were 358,500, 274,692 and 303,491 options granted in 2001, 2000 and 1999, respectively, and 227,500 and 318,892 options were repriced in 2001 and 1999, respectively, which had an immaterial effect on compensation expense in 2001 and 1999. As a result of adopting FIN 44, compensation expense increased $298,000 in the second half of 2000. In December 2001, the Company repriced 227,500 stock options from an exercise price of $3.59 to $2.14 per share. F-17 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 2001, 2000 and 1999, respectively: risk-free interest rates of 5.0%, 6.4% and 6.2%; volatility factor of the expected market price of the Company's common stock of 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 changes in net income or loss for the years ended December 31, 2001, 2000 and 1999 were not material. During 2001, certain employees that retired or were previously terminated elected to put their vested stock options back to the Company. As a result, the Company paid $772,000 to purchase and cancel 219,644 options. F-18 Stock option activity consisted of the following: WEIGHTED AVERAGE NUMBER OF EXERCISE SHARES PRICE --------- --------- BALANCE AT DECEMBER 31, 1998 817,707 $8.66 Granted 303,491 1.26 Forfeitures (333,632) 10.82 Exercised (31,268) 0.13 Reissued and repriced (318,892) 10.82 Reissued and repriced 318,892 0.01 -------- BALANCE AT DECEMBER 31, 1999 756,298 0.53 Granted 274,692 0.22 Forfeitures (65,000) 5.83 Exercised (96,798) 0.01 -------- BALANCE AT DECEMBER 31, 2000 869,192 0.09 Granted 358,500 3.14 Forfeitures (158,594) 0.56 Exercised or put (287,492) 0.08 Reissued and repriced (227,500) 3.59 Reissued and repriced 227,500 2.14 -------- BALANCE AT DECEMBER 31, 2001 781,606 0.97 ======== OPTIONS EXERCISABLE AT DECEMBER 31, 2001 225,322 $0.08 ======== The weighted average fair value of options granted during 2001, 2000 and 1999 was $0.79, $0.07 and $0.50, respectively. The exercise price for the options outstanding as of December 31, 2001 ranged from $0.01 to $2.14 per share. At December 31, 2001, the weighted average remaining contractual life of the outstanding options is 8.8 years. F-19 (10) TAXES The (benefit) provision for income taxes on income (loss) before extraordinary item includes the following (in thousands): YEAR ENDED DECEMBER 31, --------------------------------------- 2001 2000 1999 ------ ------ -------- CURRENT Federal $114 $290 $ -- State -- 1 -- ----- ------ -------- 114 291 -- DEFERRED Federal (600) 2,073 (10,449) State (5) 4 (730) ----- ------ -------- (605) 2,077 (11,179) ----- ------ -------- TOTAL $(491) $2,368 $(11,179) ===== ====== ======== The effective tax rate for income (loss) before extraordinary item differs from the U.S. federal statutory tax rate as follows:
YEAR ENDED DECEMBER 31, ------------------------------- 2001 2000 1999 ---- ---- ---- Statutory federal income tax rate 35.0% 35.0% 35.0% Increases (reductions) in taxes resulting from: State income taxes, net of federal tax benefit -- 1.8 2.0 Settlement of IRS exam and other tax issues (33.0) -- -- Change in valuation allowance (11.7) -- -- Other, net 1.5 (1.4) 0.9 ----- ----- ----- Effective income tax rate for the period (8.2)% 35.4% 37.9% ===== ===== =====
During 2001, the Company concluded an IRS income tax examination of the years 1994 through 1997 and favorably settled other tax issues. A federal income tax benefit of $2.0 million was recorded as a result. Also during 2001, a federal income tax benefit was recorded for approximately $700,000 along with a corresponding reduction in the valuation allowance as a result of certain net operating loss carryforwards which the Company now believes it can fully utilize. F-20 Significant components of deferred income tax liabilities and assets are as follows (in thousands):
DECEMBER 31, DECEMBER 31, 2001 2000 -------- -------- Deferred income tax liabilities: Property and equipment, net $ 45,086 $ 45,065 Fair value of derivatives 8,627 -- Other, net 1,608 753 -------- -------- Total deferred income tax liabilities 55,321 45,818 Deferred income tax assets: Accrued expenses 1,338 1,192 Net operating loss carryforwards 25,401 25,372 Tax credit carryforwards 1,103 990 Other, net 610 390 Valuation allowance (1,140) (1,840) -------- -------- Total deferred income tax assets 27,312 26,104 -------- -------- Net deferred income tax liability $ 28,009 $ 19,714 ======== ======== Current liability $ 5,470 $ -- Long-term liability 22,539 21,189 Current asset -- (1,475) -------- -------- Net deferred income tax liability $ 28,009 $ 19,714 ======== ========
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, 2001 relates principally to certain net operating loss carryforwards which management estimates will expire before they can be utilized. At December 31, 2001, the Company had approximately $61 million of net operating loss carryforwards available for federal income tax reporting purposes. These net operating loss carryforwards, if unused, will expire in 2012, 2018 and 2019. The Company has alternative minimum tax credit carryforwards of approximately $1.1 million which have no expiration date. The Company has approximately $823,000 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 based on attainment of performance targets. Amounts are allocated to substantially all employees based on relative compensation. The Company expensed $1.4 million, $1.6 million and $845,000 for the years ended December 31, 2001, 2000 and 1999, respectively, for contributions to the profit sharing plan and discretionary bonuses. All amounts were paid in cash. As of December 31, 2001, 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 F-21 participants' compensation is contributed by the Company to the plan each year. Eligible employees may also make voluntary contributions which the Company matches $0.50 for every $1.00 contributed up to 6% of an employee's annual compensation. Retirement plan expense amounted to $550,000, $650,000 and $830,000 for the years ended December 31, 2001, 2000 and 1999, respectively. Effective January 1, 2002, the Company modified the 401(k) plan as described above. Included as part of the modifications was the change in the amount the Company matches on voluntary contributions which was increased to $1.00 for every $1.00 contributed up to 4% of compensation and a $0.50 match for every $1.00 contributed up to the next 2% of compensation. The previous contribution made by the Company in the amount equal to 2% of participants' compensation each year was eliminated as part of the modifications. 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 In February 2000, four individuals filed a suit in Chautauqua County, New York on their own behalf and on the behalf of others similarly situated, seeking damages for the alleged difference between the amount of lease royalties actually paid and the amount of royalties that allegedly should have been paid. Other natural gas producers in New York were served with similar complaints. The Company believes the complaint is without merit and is defending the complaint vigorously. Although the outcome is still uncertain, the Company believes the action will not have a material adverse effect on its financial position, results of operations or cash flows. 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, results of operations or cash flows of the Company. (13) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
YEAR ENDED DECEMBER 31, ------------------------------------- (IN THOUSANDS) 2001 2000 1999 ------- ------- ------- CASH PAID DURING THE PERIOD FOR: Interest $27,737 $30,634 $34,426 Income taxes, net of refunds 359 1 -- NON-CASH INVESTING AND FINANCING ACTIVITIES: Acquisition of assets in exchange for long-term liabilities 443 239 125 Non-compete agreement and related obligation -- -- 705
(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. F-22 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 million in senior subordinated notes had an approximate fair value of $180 million at December 31, 2001 based on quoted market prices. From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas or oil 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, collars or options. At December 31, 2001, the Company's derivative contracts consisted of natural gas swaps and natural gas costless collars. All of these NYMEX based derivative contracts are designated as cash flow hedges. The Company incurred a pre-tax gain on its hedging activities of $4.5 million in 2001, a pre-tax loss on its hedging activities of $9.3 million in 2000 and a pre-tax gain of $1.2 million in 1999. At December 31, 2001, the fair value of futures contracts covering 2002 and 2003 natural gas production represented an unrealized gain of $23.7 million. (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. YEAR ENDED DECEMBER 31, ------------------------------- (IN THOUSANDS) 2001 2000 1999 -------- -------- ------ Acquisition costs: Proved properties $ 2,399 $ 220 $ -- Unproved properties 5,574 2,093 855 Developmental costs 23,409 13,849 186 Exploratory costs 8,346 8,528 6,442 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 reserves as of December 31, 2001 and 2000 have been reviewed by Wright & Company, Inc., independent petroleum engineers. The estimates of proved reserves as of December 31, 1999 have been reviewed by Ryder Scott Company Petroleum Consultants, independent petroleum engineers. F-23 The following table sets forth changes in estimated proved and proved developed reserves for the periods indicated: OIL GAS (Mbbl)(1) (Mmcf)(2) -------- -------- DECEMBER 31, 1998 4,243 315,259 Extensions and discoveries 12 416 Purchase of reserves in place -- -- Sale of reserves in place (29) (632) Revisions of previous estimates 3,186 18,636 Production (713) (26,988) -------- -------- DECEMBER 31, 1999 6,699 306,691 Extensions and discoveries 386 15,622 Purchase of reserves in place -- 7,223 Sale of reserves in place (606) (65,567) Revisions of previous estimates 2,766 129,597 Production (592) (20,037) -------- -------- DECEMBER 31, 2000 8,653 373,529 Extensions and discoveries 285 13,591 Purchase of reserves in place -- 28,557 Sale of reserves in place (54) (1,129) Revisions of previous estimates (2,651) (61,780) Production (646) (18,541) -------- -------- DECEMBER 31, 2001 5,587 334,227 ======== ======== PROVED DEVELOPED RESERVES December 31, 1999 5,898 267,942 ======== ======== December 31, 2000 5,954 251,747 ======== ======== December 31, 2001 4,788 218,148 ======== ======== (1) Thousand barrels (2) Million cubic feet F-24 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES (UNAUDITED) The following tables, which present a standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves, are presented pursuant to SFAS No. 69. In computing this data, assumptions other than those required by the FASB could produce different results. Accordingly, the data should not be construed as representative of the fair market value of the Company's proved oil and gas reserves. The following assumptions have been made: - Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements. - Production and development costs were computed using year-end costs assuming no change in present economic conditions. - Future net cash flows were discounted at an annual rate of 10%. - Future income taxes were computed using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is presented below:
DECEMBER 31, --------------------------------------------------- 2001 2000 1999 ----------- ------------- ----------- (IN THOUSANDS) Estimated future cash inflows (outflows) Revenues from the sale of oil and gas $ 1,075,151 $ 3,835,298 $ 957,046 Production and development costs (527,377) (805,025) (411,881) ----------- ----------- ----------- Future net cash flows before income taxes 547,774 3,030,273 545,165 Future income taxes (133,992) (1,037,843) (124,561) ----------- ----------- ----------- Future net cash flows 413,782 1,992,430 420,604 10% timing discount (231,920) (1,171,666) (203,716) ----------- ----------- ----------- Standardized measure of discounted future net cash flows $ 181,862 $ 820,764 $ 216,888 =========== =========== ===========
At December 31, 2001, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. F-25 The principal sources of changes in the standardized measure of future net cash flows are as follows:
YEAR ENDED DECEMBER 31, --------------------------------------------------- 2001 2000 1999 ----------- ----------- ----------- (IN THOUSANDS) Beginning of year $ 820,764 $ 216,888 $ 208,663 Sale of oil and gas, net of production costs (72,132) (56,416) (54,059) Extensions and discoveries, less related estimated future development and production costs 8,721 69,990 1,233 Purchase of reserves in place less estimated future production costs 7,924 13,383 -- Sale of reserves in place less estimated future production costs (3,226) (50,817) (578) Revisions of previous quantity estimates (63,294) 445,976 31,128 Net changes in prices and production costs (1,026,055) 608,442 32,836 Change in income taxes 371,059 (363,561) (2,729) Accretion of 10% timing discount 123,495 26,751 25,656 Changes in production rates (timing) and other 14,606 (89,872) (25,262) ----------- ----------- ----------- End of year $ 181,862 $ 820,764 $ 216,888 =========== =========== ===========
(16) INDUSTRY SEGMENT FINANCIAL INFORMATION The Company operates in one reportable segment, as an independent energy company engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. The Company's operations are conducted entirely in the United States. MAJOR CUSTOMERS - --------------- One customer accounted for more than 10% of consolidated revenues during each of the years ended December 31, 2001 and 2000 sales to which amounted to $21.0 million and $21.6 million, respectively. No customer accounted for more than 10% of consolidated revenues during the year ended December 31, 1999. F-26 (17) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The results of operations for the four quarters of 2001 and 2000 are shown below (in thousands).
FIRST SECOND THIRD FOURTH -------- -------- -------- -------- 2001 - ---- Sales and other operating revenues $ 34,654 $ 32,918 $ 30,373 $ 31,537 Gross profit 11,109 10,300 8,505 5,840 Net income (loss) 2,062 3,792 682 (69) FIRST SECOND THIRD FOURTH -------- -------- -------- -------- 2000 - ---- Sales and other operating revenues $ 28,238 $ 26,245 $ 26,508 $ 33,602 Gross profit 4,887 4,179 5,793 7,743 Income (loss) before extraordinary item 7,744 (1,698) (1,175) (546) Net income (loss) 7,744 (1,698) (2,535) (550)
The Company reclassified certain gas marketing revenues in the fourth quarter of 2000. This had no impact on gross profit or net income (loss). Prior quarters in 2000 have been restated to conform to the current presentation. In March 2000 the Company sold Peake. See Note 3. (18) SALE OF TAX CREDIT PROPERTIES In March 1998, the Company sold certain interests that qualify for the nonconventional fuel source tax credit. The interests were sold for approximately $730,000 in cash and a volumetric production payment under which 100% of the cash flow from the properties will go to the Company until approximately 10.8 Bcf (billion cubic feet) of gas has been produced and sold. In addition to receiving 100% of the cash flow from the properties, the Company will receive quarterly incentive payments based on production from the interests through 2002. The Company has the option to repurchase the interests after December 31, 2002. (19) SUBSEQUENT EVENTS - NATURAL GAS HEDGE POSITION MONETIZATION AND RESTRUCTURING On January 17 and 18, 2002, the Company monetized 9,350 Bbtu of its 2002 natural gas hedge position at a weighted average NYMEX price of $2.53 per Mmbtu (million British thermal units) and 3,840 Bbtu of its 2003 natural gas hedge position at a NYMEX price of $3.01 per Mmbtu. The Company received net proceeds of $22.7 million that will be recognized as increases to natural gas revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss). In January 2002, the Company entered into a collar for 9,350 Bbtu of its natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a floor price of $2.25 per Mmbtu. The Company also sold a floor at $1.75 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per Mmbtu; 3) locking in a price of $2.25 per Mmbtu if prices are between $1.75 and $2.25 per Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the price if the price is $1.75 or less. All prices are based on monthly NYMEX settle. The Company paid $1.0 million for the options. F-27 The Company used the net proceeds of $21.7 million from the two transactions above to pay down on its credit facility. The following table summarizes, as of January 21, 2002, the Company's deferred gains on terminated natural gas hedges. Cash has been received and the deferred gains recorded in accumulated other comprehensive income. The deferred gains will be recognized as increases to gas revenues during the periods in which the underlying forecasted transactions are recognized in net income (loss).
2002 2003 ------------------------------------------------- -------- FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER ------- ------- ------- ------- (IN THOUSANDS) Natural Gas Hedges Terminated in January 2002 $4,521 $5,620 $5,188 $4,560 $2,851
F-28 EX-10.1.C 3 l92370aex10-1_c.txt EXHIBIT 10.1(C) Exhibit 10.1(c) SECOND AMENDMENT TO THE AMENDED AND RESTATED CREDIT AGREEMENT SECOND AMENDMENT, dated as of June 29, 2001 (this "Amendment"), to the Amended and Restated Credit Agreement, dated as of August 23, 2000 (as so amended or otherwise modified from time to time, the "Credit Agreement"), among Belden & Blake Corporation (the "Borrower"), the several financial institutions and other entities from time to time parties thereto (the "Lenders"), Ableco Finance LLC, as the administrative agent and collateral agent (in such capacity, the "Administrative Agent"), and Foothill Capital Corporation, as the funding agent (in such capacity, the "Funding Agent"). The Borrower and the Lenders wish to amend the Credit Agreement to (a) extend the Final Maturity Date, (b) provide for a prepayment premium, (c) increase the L/C Subfacility, (d) require the maintenance of certain Hedging Agreements and (e) amend the financial covenants. Accordingly, the Borrower, the Guarantors and the Lenders hereby agree as follows: 1. DEFINITIONS. All terms used herein which are defined in the Credit Agreement and not otherwise defined herein are used herein as defined therein. 2. CHANGES TO EXISTING DEFINITION. (a) The definitions of "Consolidated Interest Expense", "Consolidated Net Income", "EBITDA", "Final Maturity Date" and "L/C Subfacility" contained in Section 1.1 of the Credit Agreement are hereby amended and restated in their entirety to read as follows: " 'CONSOLIDATED INTEREST EXPENSE': with respect to the Borrower and its Subsidiaries on a consolidated basis for any period, the sum of (i) gross interest expense (including all cash and accrued interest expense) of the Borrower and its Subsidiaries for such period on a consolidated basis, including to the extent included in interest expense in accordance with GAAP (x) the amortization of debt discounts and (y) the portion of any payments or accruals with respect to Capital Leases allocable to interest expense and (ii) capitalized interest of the Borrower and its Subsidiaries on a consolidated basis, excluding, however, any interest expense related to any income or loss resulting from the application of FASB 133." " 'CONSOLIDATED NET INCOME': for any period, net income of the Borrower and its Subsidiaries determined on a consolidated basis in accordance with GAAP, excluding, however, (i) any extraordinary or nonrecurring gain (but not loss), together with any related provision for taxes on such extraordinary or nonrecurring gain (but not loss) and (ii) any income (but not loss) resulting from the application of FASB 133, together with any related provision for taxes thereon." " 'EBITDA': with respect to the Borrower, for any period, Consolidated Net Income for that period, PLUS, each of the following determined in accordance with GAAP and without duplication and to the extent deducted from revenues in determining Consolidated Net Income for that period, (a) the aggregate amount of Consolidated Interest Expense for that period, (b) the aggregate amount of letter of credit fees paid during that period, (c) the aggregate amount of income tax expense for that period, (d) all amounts attributable to depreciation, depletion and amortization for that period, (e) the aggregate amount of exploration expenses for that period, (f) the aggregate amount of any extraordinary or nonrecurring loss (but not gain), together with any related provision for taxes for such loss (but not gain) for that period, (g) any expense (but not income) resulting from the application of FASB 133, together with any related provision for taxes thereon and (h) all non-cash or extraordinary expenses during that period, and MINUS, each of the following determined in accordance with GAAP, without duplication and to the extent added to revenues in determining Consolidated Net Income for that period, (x) all non-cash or extraordinary income and (y) all income (but not expense) resulting from the application of FASB 133, together with any related provision for taxes thereon during that period." " 'FINAL MATURITY DATE': April 22, 2004, or such earlier date on which any Loan shall become due and payable, in whole or in part, in accordance with the terms of this Agreement and the other Loan Documents." " 'L/C SUBFACILITY': that portion of the Total Revolving Credit Commitment equal to $30,000,000." 3. NEW DEFINITION. The following definition of the term "FASB 133" is hereby added to Section 1.1 of the Credit Agreement: "FASB 133": Statement No. 133 of the Financial Accounting Standards Board as it applies to Hedging Agreements." 4. REDUCTION OF COMMITMENT; PREPAYMENT OF LOANS. (a) The second sentence of clause (i) of Section 2.5(a) is amended by deleting in its entirety the phrase ", without premium or penalty,". (b) Clause (i) of Section 2.5(b) is hereby amended in its entirety to read as follows: "(i) REVOLVING CREDIT LOANS. Subject to Section 2.5(f), the Borrower may prepay the principal of any Revolving Credit Loan, in whole or in part, at any time or from time to time." (c) Clause (ii) of Section 2.5(b) is hereby amended in its entirety to read as follows: -2- "(ii) TERM LOAN. Subject to Section 2.5(f), the Borrower may upon at least three (3) Business Days' prior written notice to the Funding Agent prepay the principal amount of the Term Loan, in whole or in part on any Business Day. Each prepayment made pursuant to this clause (b)(ii) shall be accompanied by the payment of accrued interest to the date of such payment on the amount prepaid." (d) The following new paragraph (f) is hereby added to Section 2.5 of the Credit Agreement: "(f) EARLY TERMINATION BY THE BORROWER. The Borrower may, at any time upon five (5) days prior written notice to the Agents (which notice shall be irrevocable), terminate this Agreement by paying to the Funding Agent, for the benefit of the Lenders, in cash, an amount equal to the full amount of the Obligations (including either (x) providing cash collateral to be held by the Funding Agent for the benefit of the Lenders in an amount equal to 110% of the maximum amount of the Lenders' obligations under the outstanding Letters of Credit or (y) causing the original Letters of Credit to be returned to the Funding Agent), plus an amount equal to either (i) 0.25% of the Total Revolving Commitment if the termination of this Agreement pursuant to this Section 2.5(f) occurs on or before May 31, 2002 or (ii) 0.125% of the Total Revolving Commitment if the termination of this Agreement pursuant to this Section 2.5(f) occurs after May 31, 2002 and on or before May 31, 2003 (the amount determined pursuant to clause (i) or (ii) referred to herein as the "PREPAYMENT PENALTY"). If the Borrower delivers a notice of termination pursuant to the provisions of this Section 2.5(f), then the Total Commitment shall, if not earlier terminated in accordance with this Agreement, terminate, and the Borrower shall be obligated to repay the Obligations (including, without limitation, the Prepayment Penalty), in full, on the date set forth as the date of termination of this Agreement in such notice." 5. HEDGING AGREEMENTS. (a) Section 7.2 is hereby amended by (i) deleting the word "and" after the semicolon at the end of clause (g); (ii) changing the reference from clause (h) to clause (i); and (iii) adding after clause (g) and before the newly renumbered clause (i) the following new clause (h): "(h) promptly and in any event within five (5) Business Days, notify the Agents upon becoming aware that its production of Hydrocarbons could reasonably be expected to be insufficient to meet its obligations under any Hedging Agreement; and" (b) The Credit Agreement is hereby amended by adding the following new Section 7.19: "Section 7.19 HEDGING AGREEMENTS. Maintain in effect one or more Hedging Agreements with respect to its Hydrocarbon production (including, without limitation, gas sales contracts with customers of the Borrower or its -3- Subsidiaries) with one or more counterparties reasonably acceptable to the Administrative Agent. The aggregate notional volumes of Hydrocarbons covered by such Hedging Agreements shall constitute not less than 20% and not more than 80% of the Borrower's estimated Hydrocarbon production volumes on an mcf equivalent basis (where one barrel of oil is equal to six mcf of gas) for the succeeding twelve calendar months on a rolling twelve calendar month basis for such period from Oil and Gas Properties classified as Proved Developed Producing Reserves as of the date of the most recent Reserve Report delivered pursuant to Section 7.1(f) hereof plus the estimated production from anticipated drilling by the Borrower or its Subsidiaries during such succeeding twelve months. The Borrower shall use such Hedging Agreements solely as a part of its normal business operations as a risk management strategy and/or hedge against changes resulting from market conditions related to the Borrower's and its Subsidiaries' oil and gas operations and not as a means to speculate for investment purposes on trends and shifts in financial or commodities markets." 6. FINANCIAL COVENANT CONDITIONS. (a) The following fiscal quarters and ratios shall be added to the Senior Debt Interest Coverage Ratio set forth in clause (a) of Section 8.1 of the Credit Agreement: September 30, 2002 3.2:1 December 31 2002 3.2:1 March 31, 2003 3.2:1 June 30, 2003 3.2:1 September 30, 2003 3.2:1 December 31, 2003 3.2:1 March 31, 2004 3.2:1 (b) The following fiscal quarters and ratios shall be added to the Senior Debt Leverage Ratio set forth in clause (b) of Section 8.1 of the Credit Agreement: September 30, 2002 2.7:1 December 31 2002 2.7:1 March 31, 2003 2.7:1 June 30, 2003 2.7:1 September 30, 2003 2.7:1 December 31, 2003 2.7:1 March 31, 2004 2.7:1 (c) Clause (c) of Section 8.1 of the Credit Agreement is hereby amended in its entirety to read as follows: "(c) CURRENT RATIO. Permit, the ratio of current assets (which shall include an amount equal to the principal amount of Loans available under this Agreement but shall exclude an amount equal to any increase (but not decrease) resulting from the application of FASB 133) to current liabilities (excluding (i) all -4- Indebtedness and accrued interest expense otherwise included as current liabilities and (ii) an amount equal to any increase (but not decrease) in current liabilities resulting from the application of FASB 133) to be less than 1.0 to 1.0 at the end of any fiscal quarter of the Borrower." 7. EVENT OF DEFAULT. (a) Clauses (i) and (ii) of Section 9(d) of the Credit Agreement is hereby amended in its entirety to read as follows: "(i) five (5) consecutive days in respect of subsections 7.2(h), 7.7(a) or 7.7(e), (ii) ten (10) consecutive days in respect of the agreements contained in clauses (a) through (g) of subsection 7.2 or subsections 7.10, 7.11, 7.16(ii), 7.16(iii), 7.18 or 7.19" (b) Clause (iii) of Section 9(d) of the Credit Agreement is hereby amended by deleting the reference to subsection "7.2(h)" and substituting in lieu thereof "7.2(i)". 8. CONDITIONS. This Amendment shall become effective only upon satisfaction in full of the following conditions precedent (the first date upon which all such conditions have been satisfied being herein called the "Amendment Effective Date"): (a) The representations and warranties contained in this Amendment and in Section 5 of the Credit Agreement and each other Loan Document shall be correct in all material respects on and as of the Amendment Effective Date as though made on and as of such date (except where such representations and warranties relate to an earlier date in which case such representations and warranties shall be true and correct as of such earlier date). (b) No Event of Default or, event which with the giving of notice or elapse of time or both would constitute an Event of Default, shall have occurred and be continuing on the Amendment Effective Date or result from this Amendment becoming effective in accordance with its terms. (c) The Administrative Agent shall have received counterparts of this Amendment which bear the signatures of the Borrower and the Guarantors. (d) The Administrative Agent shall have received, for the ratable benefit of the Lenders, a non-refundable amendment fee in an amount equal to $175,000, which fee is earned in full by the Lenders. (e) All legal matters incident to this Amendment shall be satisfactory to the Administrative Agent and its counsel. 9. CONTINUED EFFECTIVENESS OF CREDIT AGREEMENT. The Borrower and each Guarantor hereby (a) acknowledges and consents to this Amendment, (b) confirms and agrees that each Loan Document to which it is a party is, and shall continue to be, in full force and effect and is hereby ratified and confirmed in all respects except that on and after the date hereof all references in any such Loan Document to "the Credit Agreement", "thereto", "thereof", -5- "thereunder" or words of like import referring to the Credit Agreement shall mean the Credit Agreement as amended by this Amendment, and (c) confirms and agrees that to the extent that any such Loan Document purports to assign or pledge to the Lenders, or to grant a security interest in or lien on, any collateral as security for the obligations of the Borrower from time to time existing in respect of the Credit Agreement, such pledge, assignment or grant of the security interest or lien is hereby ratified and confirmed in all respects. 10. MISCELLANEOUS. (a) This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which shall be deemed to be an original, but all of which taken together shall constitute one and the same agreement. (b) Section and paragraph headings herein are included for convenience of reference only and shall not constitute a part of this Amendment for any other purpose. (c) This Amendment shall be governed by, and construed in accordance with, the laws of the State of New York. -6- IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers or agents thereunto duly authorized as of the day and year first above written. ABLECO FINANCE LLC, as Lender By: /s/ Kevin P. Genda ------------------------------------------- Title: SVP & Chief Credit Officer FOOTHILL CAPITAL CORPORATION, as Lender By: /s/ Greg L. Gentry ------------------------------------------- Title: Vice President FOOTHILL INCOME TRUST, L.P., as Lender, By: FIT GP, LLC, its general partner By: /s/ John Nickoll ------------------------------------- Title: Managing Member BELDEN & BLAKE CORPORATION, as Borrower By: /s/ Robert W. Peshek ------------------------------------------- Title: Vice President, Finance and Chief Financial Officer THE CANTON OIL AND GAS COMPANY, as Guarantor By: /s/ Robert W. Peshek ------------------------------------------- Title: Vice President, Finance and Chief Financial Officer -7- WARD LAKE DRILLING, INC., as Guarantor By: /s/ James L. Goist ------------------------------------------ Title: Treasurer -8- EX-10.11 4 l92370aex10-11.txt EXHIBIT 10.11 Exhibit 10.11 AMENDED AND RESTATED EMPLOYMENT AGREEMENT THIS AMENDED AND RESTATED EMPLOYMENT AGREEMENT (this "Agreement") is made and entered into effective as of the 1st day of July, 2001 (the "Effective Date") by and between Belden & Blake Corporation, an Ohio corporation ("Employer"), and John L. Schwager ("Executive"). WHEREAS, Executive presently serves as Chief Executive Officer of Employer pursuant to the terms of an Employment Agreement, dated as of June 1, 1999, as amended by the first and second amendment thereto (the "Prior Agreement"); and WHEREAS, Employer desires to continue to employ Executive as its Chief Executive Officer as of and after the Effective Date and Executive desires to be so employed by Employer, upon the terms and subject to the conditions set forth in this Agreement; NOW, THEREFORE, in consideration of the mutual promises and covenants herein set forth and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Employer and Executive, intending to be legally bound, agree as follows: 1. EMPLOYMENT. Employer hereby employs Executive as its Chief Executive Officer upon the terms and conditions and for the compensation herein provided. Executive hereby agrees to be so employed and to fulfill the duties of Chief Executive Officer. Executive shall also serve as a member of Employer's Board of Directors. This Agreement shall, as of the Effective Date, replace the Prior Agreement in its entirety. The term of Executive's employment under this Agreement shall commence on the Effective Date and end on the third anniversary of that date. The term may be extended only by the written agreement of the parties. Upon termination of Executive's employment at or after the end of term, as such term may be extended, Executive and his spouse shall be entitled to the benefit described in Section 4(c)(iv) of this Agreement. 2. DUTIES AND POWER. For so long as Executive is employed by Employer, Executive agrees as follows: to devote his full and exclusive business time and attention to the business of Employer and of any subsidiaries or affiliates of Employer (excluding reasonable vacations and sick leave in accordance with Employer's policies consistent with his position) and to perform all duties in a professional and prudent manner. As Chief Executive Officer, Executive shall report directly to the Board of Directors of Employer, have no other officer or employee of Employer senior to him and have full power, authority, duties and responsibilities customarily associated with the position as Chief Executive Officer, including, without limitation, authority, direction and control over day-to-day business, financial and personnel matters of Employer, subject to the lawful and reasonable policies and guidelines as may be established by the Board of Directors of Employer. Executive agrees to devote his full business time to the performance of services hereunder and not to engage in any other activity or own any interest that would conflict with the interest of Employer or would interfere with his responsibilities to Employer and the performance of his duties hereunder; provided, however, that: (i) passive investments of less than 5% of the outstanding securities of any corporation shall be deemed not to violate this provision; (ii) Executive may engage in activities involving charitable, educational, religious, industry, trade and similar types of organizations, speaking engagements and similar type activities to the extent that such other activities do not detract from the performance by Executive of his duties and obligations hereunder; and (iii) Executive may serve as an outside director of other companies to the extent that such service does not involve a conflict of interest and does not detract in any material respect from the performance by Executive of his duties and obligations hereunder. Executive shall perform his duties at Employer's office in North Canton, Ohio, except that a reasonable amount of business-related travel may be required. 3. COMPENSATION AND BENEFITS. For all services rendered by Executive pursuant to this Agreement, Employer shall compensate Executive as follows: (a) BASE COMPENSATION. Subject to the terms and conditions set forth herein, Employer (or, at Employer's option, any subsidiary or affiliate of Employer for which Executive also provides services hereunder) shall pay to Executive a salary of at least $325,000 per annum on and after July 1, 2001 and $350,000 on and after January 1, 2003. Such annual compensation as it may be increased from time to time shall be referred to herein as the "Base Compensation". Executive's Base Compensation will be paid in accordance with Employer's customary payroll practices (but not less frequently than monthly), and will be prorated based upon the number of days elapsed in any partial year. Subject to the minimum Base Compensation requirements set forth above, Base Compensation shall be reviewed annually by the Compensation Committee of Employer's Board of Directors and may be further increased at the sole discretion of such Committee. (b) BONUS. Executive may be awarded an annual bonus based on the attainment of certain goals to be agreed upon by Executive and Employer's Board of Directors on or before March 1 of the applicable year. Such annual bonus is targeted to be 50% of Executive's Base Compensation (the "Target Bonus"), but may be increased (up to a maximum of 100% of Base Compensation) or decreased by the Board of Directors in its discretion depending on the extent to which the goals are exceeded or not met. Notwithstanding the foregoing, in the event that a Change in Control (as defined below) shall occur, Executive shall be entitled to a minimum guaranteed bonus for each of the fiscal year of Employer in which such Change in Control occurs (the "Current Year") and the immediately preceding fiscal year (the "Preceding Year") of 50% of Executive's Base Compensation for each such year (the "Minimum Bonus"). The Minimum Bonus for the Current Year and the Preceding Year shall be paid on the closing date of the Change in Control transaction; provided, however, that, in the case of the Minimum Bonus for the Preceding Year, if the closing of such Change in Control transaction occurs after the payment date of Executive's bonus for the Preceding Year, then, on the closing date of Change in Control transaction, Employer shall pay to Executive an amount equal to the excess, if any, of the Minimum Bonus for the Preceding Year over the amount of bonus theretofore paid to Executive with respect to -2- the Preceding Year; provided, however, that if such bonus paid with respect to the Preceding Year equals or exceeds the Minimum Bonus that would otherwise be due under this Section 3(b) with respect to such Preceding Year upon the closing of the Change in Control transaction, then no such Minimum Bonus for the Preceding Year shall be paid. In addition to the foregoing, Executive shall be entitled to receive (i) an Annual Retention Bonus of $330,000 on each June 30 of 2002, 2003 and 2004 if he is still in the employ of Employer on each such date, payment of such Annual Retention Bonuses to be accelerated and paid in full upon the closing date of any Change in Control transaction, and (ii) a Special Retention Bonus of $1,000,000 to be paid on the closing date of any Change in Control transaction that occurs during, or within six (6) months after the expiration of, the term of this Agreement, provided such Special Retention Bonus shall not be payable if Executive is employed as the Chief Executive Officer of the surviving company in such Change in Control transaction. (c) BENEFITS. Executive shall be entitled, as an employee of Employer, to employee retirement and welfare benefits, perquisites and other executive benefits substantially comparable to those employee benefits made available to the senior executive management of Employer, including, but not limited to, 401(k) plan and medical benefit plan participation and no less than five (5) weeks of vacation per year. For purposes of the vacation entitlement, Executive shall receive credit for his prior 32 years of service in the industry. (d) CERTAIN REIMBURSEMENTS. Executive shall be entitled to reimbursement by Employer for financial and tax planning advisory services at rates customary to the local area and for uninsured expenses associated with an annual physical examination by a physician selected by him. In addition, in each year during the term of this Agreement, Executive shall be entitled to perform up to three (3) weeks of his service hereunder at a health resort of Executive's choosing. During any such stay at a health resort, Executive shall be expected to perform services as Chief Executive Officer of the Company, but his hours shall be at his sole discretion. Employer shall reimburse Executive for all expenses associated with such stay, and Employer shall further pay Executive an amount determined by its accountants to be equal to Executive's federal, state and local taxes on the foregoing reimbursement (the "Health Resort Tax Gross-Up") and the federal, state and local taxes on the Health Resort Tax Gross-Up, all to the end that Executive be held harmless, on an after-tax basis, from the tax impact thereof. Employer will also reimburse Executive for reasonable attorneys' fees and expenses incurred in connection with review of this Agreement by Executive's attorney. In addition, Employer shall pay Executive an amount determined by its accountants to be equal to Executive's federal, state and local taxes on the foregoing reimbursement (the "Legal Expense Tax Gross-up") and the federal, state and local taxes on the Legal Expense Tax Gross-up, all to the end that Executive be held harmless, on an after-tax basis, from the tax impact thereof. Notwithstanding the foregoing, the total amount paid or reimbursed to Executive under this Section 3(d) shall not exceed $35,000 in any calendar year. (e) EXPENSES. Executive shall be entitled to reimbursement by Employer for his ordinary and necessary business expenses incurred in the performance of his duties -3- under this Agreement if supported by reasonable documentation as required by Employer in accordance with its usual practices. (f) LIABILITY FOR TAXES. Except as otherwise provided in Section 3(d) and Section 4(f), Employer shall have no liability for any tax liability of Executive attributable to any payment made under this Agreement except for customary employer liability for federal and state employee taxes (e.g., social security, Medicare, etc.). Employer may withhold from any such payment such amounts as may be required by applicable provisions of the Internal Revenue Code, other tax laws, and the rules and regulations of the Internal Revenue Service and other tax agencies in effect at the time of any such payment. 4. TERMINATION OF EMPLOYMENT. (a) TERMINATION NOTICE. Notwithstanding any other provision contained in this Agreement, either Executive or Employer may terminate Executive's employment hereunder at any time with or without Cause (as defined below) at its or his election upon prior written notice (a "Termination Notice") to the other. A Termination Notice shall be effective upon delivery to the other party and the termination shall be effective as of the date set forth in such Termination Notice (hereinafter, the "Termination Date'). (b) DEFINITION OF "CAUSE". For purposes of this Agreement, the term "Cause" shall mean Executive's personal dishonesty, fraud or deceit, willful misconduct, a serious breach of a fiduciary duty involving personal profit, conviction of a felony (including via a guilty or nolo contendere plea), willful neglect of duties by Executive or material breach by Executive of the provisions of Sections 2, 6, 7 or 8 of this Agreement; provided, however, that unsatisfactory job performance shall not be considered Cause for termination of the Executive's employment by the Company. Executive shall be afforded a reasonable opportunity to cure any willful neglect of his duties and any other alleged material breach of this Agreement according to the following terms. Employer's Board of Directors shall give Executive written notice stating with reasonable specificity the nature of the circumstances determined by the Board of Directors in good faith to constitute willful neglect or other material breach. Executive shall have thirty (30) days from his receipt of such notice to cure such circumstances or such breach if such breach is reasonably susceptible to cure. If, in the reasonable good faith judgment of the Board of Directors, the alleged breach is not reasonably susceptible to cure, or such circumstances or material breach has not been satisfactorily cured within such thirty (30) day cure period, such neglect of duties or material breach shall thereupon constitute "Cause" hereunder. (c) TERMINATION WITHOUT CAUSE. Employer may terminate Executive's employment under this Agreement at any time with or without any Cause shown. Upon any such termination without Cause, or upon a resignation by Executive with Good Reason as described in Section 4(e), Executive shall be entitled to the following: (i) For the period from the termination date through the then-remaining term of this Agreement (the "Continuation Period"), Executive shall -4- be entitled to continuation of his base salary, at the rate in effect on the termination date. This salary continuation shall be payable in accordance with Employer's regular payroll practices. The amount, if any, of such salary continuation that remains unpaid upon the occurrence of a Change in Control shall be accelerated and paid in full upon the closing date of such Change in Control transaction. (ii) For each month commencing with the month in which the date of termination occurs and ending with the last month of the Continuation Period, Employer shall pay to Executive a payment equal to one-twelfth (1/12) of Executive's Target Bonus for the fiscal year in which the date of termination occurs. The amount, if any, of such monthly payments that remains unpaid upon the occurrence of a Change in Control shall be accelerated and paid in full upon the closing date of such Change in Control transaction. (iii) Executive shall receive the Annual Retention Bonuses as and when such amounts would have been payable had Executive's employment continued for the balance of the term of this Agreement. The amount, if any, of such Annual Retention Bonuses that remains unpaid upon the occurrence of a Change in Control shall be accelerated and paid in full upon the closing date of such Change in Control transaction. (iv) Executive and his spouse shall be entitled to continued health benefits on the same basis as if Executive had continued as an active employee of Employer until Executive attains Medicare benefit eligibility. For the longer of the duration of the Continuation Period, or two years following the date of termination, Employer shall bear the full cost thereof, and thereafter Executive shall bear such cost at Employer's COBRA rate. With the approval of Executive, which approval shall not be unreasonably withheld, Employer may provide the foregoing coverage through the acquisition of insurance or other means provided that the benefits are substantially similar to the benefits provided under Employer's health benefit plans as in effect from time to time. (v) If a Change in Control occurs within six (6) months following the date of termination, Executive shall receive the $1,000,000 Special Retention Bonus on the closing Date of such Change in Control transaction. Notwithstanding the foregoing, the aggregate amount of the payments to Executive under clauses (i), (ii), (iii) and (v) above shall not exceed $1,990,000. If the payments under clauses (i), (ii), (iii) and (v) above must be reduced in accordance with the immediately preceding sentence, such reduction shall be effected by reducing the -5- payments in the inverse of the order in which they are due to be paid and on a pro rata basis to payments due on the same date. All of the above severance payments and benefits shall be subject to normal withholding of taxes and other authorized deductions. Executive acknowledges and agrees that the provisions of this Section 4(c) state his entire and exclusive rights, entitlements and remedies against Employer, its successors, assigns, affiliates, employees and representatives for termination without any Cause shown by Employer; provided, however, that the Executive also shall be entitled to receive all salary, bonus, benefits and expense reimbursement which have accrued as of the Termination Date. The payments provided in this Section 4(c) are conditioned upon and subject to the Executive complying with the restrictive covenants provided in Sections 6 and 7 hereof and upon the Executive executing a general release and waiver (in a form substantially similar to the form attached hereto as Exhibit A). Except as provided in Section 4(f), if applicable, Employer shall have no additional obligations under this Agreement. (d) TERMINATION FOR DEATH OR PERMANENT DISABILITY. In the event that Executive's employment by Employer is terminated because of death or Permanent Disability (as defined below), then, subject to all applicable laws, Executive (or Executive's estate) shall be entitled to receive only that salary, bonus, benefits and expense reimbursements which have accrued as of the Termination Date, and Executive, or, in the event of Executive's death, Executive's surviving spouse, if any, shall be entitled to the benefit described in Section 4(c)(iv). For purposes of this Agreement, "Permanent Disability" shall mean the inability of Executive, by reason of any ailment or illness, or physical or mental condition, to devote substantially all of his time during normal business hours to the daily performance of Executive's duties as required under this Agreement for a continuous period of six (6) months, as reflected in the opinions of three qualified physicians, one of which has been selected by Employer, one of which has been selected by Executive, and one of which has been selected by the other two physicians, jointly. (e) TERMINATION FOR CAUSE OR TERMINATION BY THE EXECUTIVE. In the event that Executive elects to terminate his employment under this Agreement (except as otherwise provided below), or if Executive is terminated for Cause, then Executive shall not be entitled to receive any severance pay or compensation except such base compensation, benefits, bonuses and expense reimbursement as shall have accrued prior to the Termination Date. Notwithstanding any provision of this Agreement to the contrary, in the event Executive elects to terminate his employment either (i) following the occurrence of any event constituting Good Reason (as defined below) or (ii) for any reason after the occurrence of a Change of Control (as defined below in Section 5(g)(iii)) regardless of the reason for such termination, such termination shall be deemed to constitute a termination by Employer without Cause, and Executive shall be entitled to all of the payments and benefits set forth in Section 4(c). For purposes of this Agreement, "Good Reason means any of the following: (i) a substantial and adverse change in Executive's status or position as Chief Executive Officer and a key employee of Employer, or a substantial reduction in the duties and responsibilities previously exercised by Executive, or any failure to reappoint or reelect Executive to, such position, -6- except in connection with the termination of Executive's employment for Cause or Permanent Disability, or as a result of Executive's death; (ii) a reduction (other than for Cause) by Employer in Executive's Base Compensation; (iii) a relocation of Executive's principal place of work to any location that is more than 25 miles from Canton, Ohio; (iv) a sale or other exchange or transfer (whether by merger, reorganization or otherwise) of substantially all of the shares or assets of Employer; or (v) a material breach of the provisions of the Agreement by Employer. Notwithstanding the foregoing, a termination of employment by Executive will be deemed to be for "Good Reason" only if Executive elects to terminate employment within ninety (90) days after he knows or should know that an event constituting Good Reason has occurred; provided, however, that Executive's continued employment following the occurrence of such an event shall not constitute consent to, or a waiver of rights with respect to, any other event constituting Good Reason hereunder. Executive acknowledges and agrees that the provisions of this Section state his entire and exclusive rights, entitlements and remedies against the Employer, its successors, assigns, affiliates and representatives if he elects to terminate his employment and/or is terminated with Cause. The payments provided in this Section 4(e) are conditioned upon and subject to the Executive complying with the restrictive covenants provided in Sections 6 and 7 hereof and upon the Executive executing a general release and waiver (in a form substantially similar to the form attached hereto as Exhibit A). Except as provided in Section 4(f), if applicable, Employer shall have no additional obligations under this Agreement. -7- (f) CERTAIN ADDITIONAL OBLIGATIONS OF EMPLOYER. (i) Anything in this Agreement to the contrary notwithstanding, in the event it shall be determined that any economic benefit or payment or distribution by Employer to or for the benefit of the Employee, whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise (a "Payment"), would be subject to the excise tax imposed by Section 4999 of the Internal Revenue Code or any Applicable Interest and Penalties (as defined below) with respect to such excise tax (such excise tax, together with any Applicable Interest and Penalties, are hereinafter collectively referred to as the "Excise Tax"), then Executive shall be entitled to receive an additional payment (a "Gross-Up-Payment") in an amount such that after payment by Executive of all taxes (including any Applicable Interest and Penalties imposed with respect to such taxes), including any Excise Tax imposed upon the Gross-Up Payment, Executive retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments. For purposes of this Agreement, "Applicable Interest and Penalties" means all interest and penalties payable by Executive with respect to excise tax imposed under Section 4999 of the Internal Revenue Code other than interest or penalties determined by the Accounting Firm (as defined below) to be primarily attributable to unreasonable delay on the part of Executive. (ii) Subject to the provisions of Section 4(f)(iii), all determinations required to be made under this Section 4(f), including whether a Gross-Up Payment is required and the amount of such Gross-Up Payment, shall be made by Employer's regular outside independent public accounting firm (the "Accounting Firm") which shall provide detailed supporting calculations both to Employer and Executive within 15 business days of the Effective Date of Termination, if applicable, or such earlier time as is requested by Employer. The initial Gross-Up Payment, if any, as determined pursuant to this Section 4(f)(ii), shall be paid to Executive within 5 days of the receipt of the Accounting Firm's determination. Any determination by the Accounting Firm shall be binding upon Employer and Executive. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Accounting Firm hereunder, it is possible that Gross-Up Payments which will not have been made by Employer should have been made ("Underpayment"), consistent with the calculations required to be made hereunder. In the event that Employer exhausts its remedies pursuant to Section 4(f)(iii) and Executive thereafter is required to make a payment of any Excise Tax, the Accounting Firm shall determine the amount of the Underpayment -8- that has occurred and any such Underpayment shall be promptly paid by Employer to or for the benefit of Executive. (iii) Executive shall notify Employer in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by Employer of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than ten business days after the later of either (i) the date Executive has actual knowledge of such claim, or (ii) ten days after the Internal Revenue Service issues to Executive either a written report proposing imposition of the Excise Tax or a statutory notice of deficiency with respect thereto, and shall apprise Employer of the nature of such claim and the date on which such claim is requested to be paid. Executive shall not pay such claim prior to the expiration of the thirty-day period following the date on which he gives such notice to Employer (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If Employer notifies Executive in writing prior to the expiration of such period that it desires to contest such claim, Executive shall: (i) give Employer any information reasonably requested by Employer relating to such claim, (ii) take such action in connection with contesting such claim as Employer shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by Employer, (iii) cooperate with Employer in good faith in order effectively to contest such claim, (iv) permit Employer to participate in any proceedings relating to such claim; provided, however, that Employer shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold Executive harmless, on an after-tax basis, for any Excise Tax or income tax, including interest and penalties with respect thereto, imposed as a result of such contest. Without limitation of the foregoing provisions of this Section 4(f)(iii), Employer shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forego any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct Executive to request or accede to a request for an extension of the statute of limitations with respect only to the tax claimed, or pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and Executive agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as Employer shall determine; provided, however, that if Employer directs Executive to pay such claim and sue for a refund, Employer shall advance the amount of such payment to Executive, on an -9- interest-free basis and shall indemnify and hold Executive harmless, on an after-tax basis, from any Excise Tax or income tax, including interest or penalties with respect thereto, imposed with respect to such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations requested or acceded to by Executive at Employer's request and relating to payment of taxes for the taxable year of Executive with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, Employer's control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and Executive shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority. (iv) If, after the receipt by Executive of an amount advanced by Employer pursuant to Section 4(f)(iii), Executive becomes entitled to receive any refund with respect to such claim, Executive shall (subject to Employer's complying with the requirements of Section 4(f)(iii)) promptly pay to Employer the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by Executive of an amount advanced by Employer pursuant to Section 4(f)(iii), a determination is made that Executive shall not be entitled to any refund with respect to such claim and Employer does not notify Executive in writing of its intent to contest such denial of refund prior to the expiration of thirty days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid. (v) In the event that any state or municipality or subdivision thereof shall subject any Payment to any special tax which shall be in addition to the generally applicable income tax imposed by such state, municipality, or subdivision with respect to receipt of such Payment, the foregoing provisions of this Section 4(f) shall apply, mutatis mutandis, with respect to such special tax. (vi) Employer will reimburse Executive for reasonable attorneys' fees and expenses incurred following the occurrence of a Change in Control in connection with the enforcement of any of Executive's rights under this Agreement provided that Executive substantially prevails in such action. In addition, Employer shall pay Executive an amount determined by its accountants to be equal to Executive's federal, state and local taxes on the foregoing reimbursement (the "Enforcement Expense Tax Gross-up") and the federal, state and -10- local taxes on the Enforcement Expense Tax Gross-up, all to the end that Executive be held harmless, on an after-tax basis, from the tax impact thereof. 5. STOCK OPTIONS. (a) TOTAL NUMBER OF SHARES SUBJECT TO THIS OPTION. Subject to the terms and conditions of this Agreement, Employer granted to Executive, effective June 1, 1999, an option ("Option") to purchase 139,383 shares of common stock of Employer. The Option granted pursuant to this first paragraph of Section 5(a) is referred to in this Agreement as the "Initial Option." Effective March 22, 2000, Employer granted to Executive an additional Option to purchase 69,692 shares of common stock of Employer (the "March 2000 Option"). Effective as of December 31, 2001, Employer grants to Executive an additional Option to purchase 100,000 shares of common stock of Employer (the "December 2001 Option") and the parties agree to the cancellation and termination of the Option to purchase 25,000 shares of common stock of Employer at an exercise price of $3.59 per shares that was granted to Executive prior to the date of this Agreement. References in this Agreement to the "Options" shall be deemed to refer to the Initial Option, the March 2000 Option and the December 2001 Option. References in this Agreement to the "Option Shares" shall be deemed to refer to the shares of common stock of Employer issuable upon exercise of the Options. (b) VESTING. The Initial Option shall be vested as follows: One-fourth (1/4) of the Option Shares (I.E., 34,845 shares) shall vest and be exercisable on June 1, 2000 and one-twelfth (1/12) of the remaining Option Shares (I.E., 8,711 shares) shall vest and be exercisable at the end of each three (3) month period thereafter until all Option Shares have vested, provided, however, in order for Option Shares eligible to vest for any period to vest, Executive must have remained an executive or member of the Board of Directors of Employer from the date hereof through the last day of the relevant period. The Board of Directors of Employer, in its discretion, may from time to time accelerate the vesting of any or all of the Option Shares. The March 2000 Option shall be vested as follows: One-fourth (1/4) of the Option Shares (I.E., 17,423 shares) shall vest and be exercisable on March 22, 2001, and of the remaining Option Shares, 4,356 Option Shares shall vest and be exercisable at the end of each of the first eleven three (3) month periods thereafter, and 4,353 Option Shares shall vest and be exercisable at the end of the twelfth three month period thereafter, until all such Option Shares have vested, provided, however, in order for Option Shares eligible to vest for any period to vest, Executive must have remained an executive or member of the Board of Directors of Employer from the date hereof through the last day of the relevant period. The Board of Directors of Employer, in its discretion may from time to time accelerate the vesting of any or all of the Option Shares. -11- The December 2001 Option shall be vested as follows: One-fourth (1/4) of the Option Shares (I.E., 25,000 shares) shall vest and be exercisable on June 30, 2003, and of the remaining Option Shares, 25,000 Option Shares shall vest and be exercisable at the end of each of September 30, 2003, December 31, 2003 and March 31, 2004, until all such Option Shares have vested, provided, however, in order for Option Shares eligible to vest for any period to vest, Executive must have remained an executive or member of the Board of Directors of Employer from the date hereof through the last day of the relevant period. The Board of Directors of Employer, in its discretion may from time to time accelerate the vesting of any or all of the Option Shares. (c) EXERCISE PRICE AND METHOD OF PAYMENT. (i) EXERCISE PRICE. The exercise price (the "Exercise Price") of the Initial Option shall be $0.01 per share. The Exercise Price of the March 2000 Option shall be $0.21 per share and the Exercise Price of the December 2001 Option shall be $2.14 per share. (ii) METHOD OF PAYMENT. Payment of the Exercise Price per share, together with payment of any tax withholding amounts, is due in full upon exercise of any or all vested Option Shares. Executive may elect, to the extent permitted by applicable statutes and regulations, to make payment of the Exercise Price and the tax withholding amounts under one of the following alternatives: (A) Payment of the exercise price per share in cash (including check) at the time of exercise; (B) Payment by delivery of already-owned shares of common stock of Employer, owned free and clear of any liens, claims, encumbrances or security interests, or by having withheld shares of common stock otherwise issuable upon exercise of the Option, which common stock shall be valued at its fair market value on the date of exercise; or (C) Payment by any combination of the methods of payment permitted by Sections 5(c)(ii)(A) and 5(c)(ii)(B). (iii) WHOLE SHARES. The Options may not be exercised for any number of Option Shares which would require the issuance of anything other than whole shares. (d) APPLICABLE LAWS OR REGULATIONS. (i) Executive acknowledges and understands that neither the Options, the Option Shares nor any other of the securities of Employer have been registered under the Securities Act of 1933, as amended (the "Act"), or qualified under any state securities laws or regulations ("Blue Sky Laws") in reliance upon the nonpublic offering -12- exemption from the registration requirements of the Act and similar exemptions under the Blue Sky Laws. Executive hereby acknowledges and agrees that he is acquiring the Options and any Option Shares which he may subsequently acquire, solely for his own account and not with a view to or for sale in connection with any distribution of the Options or Option Shares, and that Executive either (A) has such knowledge and experience in financial and business matters that he is capable of evaluating the merits and risks of the proposed investment and therefore has the capacity to protect his own interests in connection with the acquisition of the Option Shares, or (B) has a preexisting personal or business relationship with Employer or one or more of its officers, directors or controlling persons. In the event Executive exercises any of the Options as provided herein, Executive consents to the placement of any and all legends on any certificates evidencing ownership of the Option Shares and all restrictions on transfer of the Option Shares which may, in the determination of Employer or its counsel, be appropriate or required by law. (ii) Employer's obligations to sell and deliver Option Shares are subject to, and conditional upon, such compliance as Employer deems necessary or advisable with federal and state laws, rules and regulations applying to the authorization, issuance, listing or sale of securities, and the Options may not be exercised unless (A) the Option Shares have been registered under a then currently effective registration statement under the Act, or (B) a determination is made by counsel to Employer that such registration is not required under applicable securities laws. (iii) Executive shall indemnify, defend and hold harmless Employer and its officers, directors and stockholders from and against any and all claims, demands, losses, costs, expenses (including without limitation attorney's fees) that arise from, relate to or result from any breach of, or failure of Executive to perform, any of Executive's representations, warranties or covenants set forth in Section 5(d)(i). (e) TERM. (i) The term of the Options commences on the applicable date of grant thereof, as set forth above, and shall automatically expire on June 1, 2009 (the "Expiration Date") unless the Options expire sooner as set forth below. In no event may the options be exercised on or after the Expiration Date. (ii) The Options shall terminate prior to the Expiration Date as follows: -13- (A) If Executive ceases to be an employee or director of Employer, whichever last occurs, for any reason other than death, retirement or disability or expiration of the term of this Agreement, the Options may be exercised (to the extent that Executive was entitled to exercise the same on the date of such cessation) within a period of three (3) months following such cessation, but not later than the expiration date described in Section 5(e)(i), and upon expiration of such period, the Options shall terminate; PROVIDED, HOWEVER, that the Options will immediately terminate if Executive's employment is terminated by Employer for Cause. (B) If Executive ceases to be an employee or director of Employer, whichever last occurs, by reason of death, retirement or permanent disability, or upon expiration of the term of this Agreement, the Options may be exercised (to the extent Executive was entitled to exercise the same on the date of such cessation of service) within a period of twelve (12) months following such cessation, but not later than the expiration date described in Section 5(e)(i), and upon expiration of such period, the Options shall terminate. (f) EXERCISE. (i) This Options may be exercised by Executive from time to time, to the extent Option Shares have vested, by delivering a notice of exercise in the form set forth in Exhibit A hereto, or such other form then designated by Employer (the "Notice of Exercise") together with the aggregate exercise price to the corporate secretary of Employer, or to such other person as Employer may designate, during regular business hours, together with such additional documents as Employer may then require in its discretion. The date of exercise shall be the date of Employer's receipt of the Notice of Exercise. (ii) By exercising the Options, Executive agrees that: (A) as a precondition to the completion of any exercise of the Options, Employer may require Executive to enter an arrangement providing for the payment by Executive to Employer of any tax withholding obligation of Employer arising by reason of: (1) the exercise of the Options; (2) the lapse of any substantial risk of forfeiture to which the shares are subject at the time of exercise; or (3) the disposition of shares acquired upon such exercise. Executive also agrees that any exercise of the Options has not been completed and that Employer is under no obligation to issue any common -14- stock to Executive until such an arrangement is established or Employer's tax withholding obligations are satisfied, as reasonably determined by Employer; and (B) Employer (or a representative of the underwriters) may, in connection with the first underwritten registration of the offering of any equity securities of Employer under the Act, require that Executive not sell or otherwise transfer or dispose of any shares of common stock or other securities of Employer during such period (not to exceed one hundred eighty (180) days or, if less, the period of time any other executive officer of Employer is so restricted) following the effective date of the registration statement of Employer filed under the Act as may be requested by Employer or the representative of the underwriters. Executive further agrees that Employer may impose stop-transfer instructions with respect to securities subject to the foregoing restrictions until the end of such period. (g) ADJUSTMENTS UPON CHANGES IN CAPITALIZATION. (i) In the event of any change in the number or nature of issued and outstanding shares of common stock of Employer by reason of any stock dividend, stock split, recapitalization, merger, rights offering, share exchange or other change in the corporate or capital structure of Employer, which increases, decreases, or exchanges the shares of common stock of Employer for a different number or kind of shares or other securities, an appropriate and proportionate adjustment (to the extent necessary or appropriate, as determined by the Board of Directors of Employer, in its discretion) shall be made in (A) the number of shares or other securities subject to the Options, and (B) the Exercise Price. (ii) In the event of a merger, consolidation, sale or exchange of all or substantially all of the assets of Employer, or other corporate reorganization of Employer, other than a Change in Control (as hereinafter defined), the Board of Directors of Employer, in its discretion, may, but is not obligated to do, either of the following: (A) pay in cash the difference between the Exercise Price and the consideration receivable in the transaction by a holder of common stock of Employer for the number of Option Shares unexercised, whether or not vested, or (B) provide that Executive shall receive, upon exercise of the Options, the stock or other securities, cash or property to which Executive would have been entitled if Executive had exercised the Options and had been a holder of record of shares of common stock of employer on the record date fixed for determination of holders of shares of common stock of Employer -15- entitled to receive such stock or other securities, cash or property at the same aggregate price as the aggregate Exercise Price of the Option Shares, with adjustments as set forth in Section 5(g)(i). (iii) In the event of a Change in Control, all Option Shares shall immediately become exercisable in full. For purposes of this Agreement, a "Change in Control" shall mean the following and shall be deemed to occur if: (A) As a result of any transaction, any of the following occur (1) the Permitted Holders no longer beneficially own (within the meaning of Rule 13d-3 promulgated under the securities Exchange Act of 1934, as amended), in the aggregate, at least 25% of the outstanding shares of common stock of Employer ("Outstanding Common Stock"), (2) the Permitted Holders no longer beneficially own (within the meaning of Rule 13d-3 promulgated under the Securities Exchange Act of 1934, as amended), in the aggregate, at least 50% of the combined voting power of Employer's then outstanding securities entitled to vote generally in the election of directors ("Employer Voting Securities"), or (3) any Person other than the Permitted Holders becomes the beneficial owner (within the meaning of Rule 13d-3 promulgated under the Securities Exchange Act of 1934, as amended) of an amount of Employer Voting Securities (as defined below) that is greater than the amount of Employer Voting Securities that are then beneficially owned (within the meaning of Rule 13d-3 promulgated under the Securities Exchange Act of 1934, as amended), in the aggregate, by the Permitted Holders; or (B) Prior to the occurrence of an underwritten public offering of the Company's equity securities, any of the following events occurs: (x) Any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended) (each, a "Person"), other than a Permitted Holder, becomes the beneficial owner (within the meaning of Rule 13d-3 promulgated under the Securities Exchange Act of 1934, as amended) of 50% or more of the Employer Voting Securities; or (y) Consummation by Employer of the sale or other disposition by Employer of all or substantially all of Employer's assets or a merger, consolidation or other -16- reorganization of Employer with any other Person, other than: (1) a merger, consolidation or other reorganization that would result in the voting securities of Employer outstanding immediately prior thereto (or, in the case of a reorganization or merger or consolidation that is preceded or accomplished by an acquisition or series of related acquisitions by any person, by tender or exchange offer or otherwise, of voting securities representing 50% or more of the combined voting power of all securities of Employer, immediately prior to such acquisition or the first acquisition in such series of acquisitions) continuing to represent, either by remaining outstanding or by being converted into voting securities of another entity, more than 50% of the combined voting power of the voting securities of Employer or such other entity outstanding immediately after such reorganization or merger or consolidation (or series of related transactions involving such a reorganization or merger or consolidation), or (2) a merger, consolidation or other reorganization effected to implement a recapitalization or reincorporation of Employer (or similar transaction) that does not result in a material change in beneficial ownership of the voting securities of Employer or its successor; or (C) Following the occurrence of an underwritten public offering of Employer's equity securities, any of the following events occur: (w) the acquisition in one or more transactions by any Person, other than a Permitted Holder, becomes the beneficial owner (within the meaning of Rule 13d-3 promulgated under the Securities Exchange Act of 1934, as amended) of greater than thirty percent (30%) of the Employer Voting Securities; or (x) the consummation of a merger, reorganization, consolidation, share exchange, transfer of assets or other transaction having similar effect involving Employer, unless, following such transaction, stock -17- possessing at least fifty percent (50%) of the outstanding Employer Voting Securities of the corporation resulting from such transaction is beneficially owned, directly or indirectly, by Permitted Holders, or Persons who were beneficial owners of the Employer Voting Securities immediately prior to such transaction; or (y) individuals who are members of the Board of Directors of Employer as of the Effective Date of this Agreement (the "Incumbent Directors") cease for any reason to constitute at least a majority of the members of the Board; provided, however, that any individual becoming a director subsequent to the date of this Agreement whose appointment to the Board or nomination for election by Employer was approved by a vote of at least a majority of the Incumbent Directors then in office (unless such appointment or election was at the request of an unrelated third party who has taken steps reasonably calculated to result in a Change in Control as described in paragraphs (w) or (x) above and who has indicated publicly an intent to seek control of Employer) shall be treated from the date of his or her appointment or election as an Incumbent Director; or (z) consummation of a complete liquidation or dissolution of Employer. For purposes of this Agreement, "Permitted Holders" means (i) TPG Partners II, L.P., TPG Parallel II, L.P. and TPG Investors II, L.P. (the "Investors"), (ii) any investment partnership or fund management by the principals of TPG II, (iii) any partners of the Investors, (iv) members of the immediate family of the persons described in (iii) and trusts for the benefit of members of their immediate family, (iv) the respective affiliates (within the meaning ascribed to such term in Rule 405 of the Securities Act of 1933, as amended) of Persons described in (i) through (iv), and (v) any Person acting in the capacity of an underwriter in connection with a public or private offering of Employer's equity securities. (h) DELIVERY OF CERTIFICATES, RIGHTS IN OPTION SHARES. Upon the due exercise of the Options in accordance with the provisions of this Agreement, Employer shall deliver to the Executive at the main office of Employer, or such other place as shall be mutually acceptable, a certificate or certificates representing such shares of common stock to which the Options shall have been so exercised. Neither Executive, his estate nor his transferees by will or the laws of descent and distribution shall be, or have any rights or privileges of, a stockholder of Employer with respect to any Option Shares -18- issuable upon exercise of the Options, unless and until certificates representing such Option Shares shall have been issued and delivered. (i) TRANSFERABILITY. These Options are not transferable, except by will or by the laws of descent and distribution, and shall be exercisable only by Executive during the life of Executive. Notwithstanding the foregoing, by delivering written notice to Employer, in a form satisfactory to Employer, Executive may designate a third party who, in the event of the death of Executive, shall thereafter be entitled to exercise the Options. (j) NO EMPLOYMENT RIGHT. Nothing in the Options shall be deemed to create in any way whatsoever any obligation on the part of Executive to continue in the employ of Employer, or of Employer to continue employment of Executive with Employer. In addition, nothing in the Options shall obligate Employer or any affiliate of Employer, or their respective stockholders, board of directors, officers, or employees to continue any relationship which Executive might have as a director or consultant for Employer or affiliate of Employer. 6. NONDISCLOSURE. (a) CONFIDENTIAL INFORMATION. Executive hereby acknowledges that in connection with his employment by Employer he will be exposed to and may obtain certain information (including, without limitation, procedures, memoranda, notes, records and customer and supplier lists whether such information has been or is made, developed or compiled by Executive or otherwise has been or is made available to him) regarding the business and operations of Employer and its subsidiaries or affiliates. Executive further acknowledges that such information and procedures are unique, valuable, considered trade secrets and deemed proprietary by Employer. For purposes of this Agreement, such information and procedures shall be referred to as "Confidential Information," except that the following shall not be considered Confidential Information: (i) information disclosed on a non-confidential basis to third parties by Employer (but not by Executive in violation of this Agreement), (ii) information released from confidential treatment by written consent of Employer, and (iii) information lawfully available to the general public. (b) USE OF CONFIDENTIAL INFORMATION. Executive agrees that all Confidential Information is and will remain the property of Employer. Executive further agrees, except as otherwise required by law and for disclosures occurring in the good faith performance of his duties for Employer, while employed by Employer hereunder and thereafter, to hold in the strictest confidence all Confidential Information, and not to, directly or indirectly, duplicate, sell, use, lease, commercialize, disclose or otherwise divulge to any person or entity any portion of the Confidential Information or use any Confidential Information for his own benefit or profit or allow any person, entity or third party, other than Employer and authorized executives of the same, to use or otherwise gain access to any Confidential Information. -19- (c) TRADE SECRET. It is the intention of the parties that to the extent any Confidential Information may constitute a "trade secret" as defined by Ohio law, then, in addition to the remedies set forth in this Agreement, Employer may elect to bring an action against Executive in the case of any actual or threatened misappropriation of any such trade secret by Executive. (d) NO REMEDY AT LAW. Regardless of whether any of the Confidential Information shall constitute a trade secret as defined by Ohio law, Executive expressly recognizes and agrees that the restrictions contained in this Section 6 represent a reasonable and necessary protection of the legitimate interests of Employer, that his failure to observe and comply with his covenants and agreements herein will cause irreparable harm to Employer, that it is and will continue to be difficult to ascertain the harm and damages to Employer that such a failure by Executive could cause, and that a remedy at law for such failure by Executive will be inadequate. 7. NON-INTERFERENCE, NON-SOLICITATION AND NON-COMPETITION COVENANTS. (a) ACKNOWLEDGMENT OF ACCESS. Pursuant to this Agreement, Executive has agreed to become Chief Executive Officer of Employer and to comply with the non-disclosure provisions contained in Section 6 hereof. Executive recognizes and acknowledges that he will be given access to certain of Employer's Confidential Information (as defined in Section 6(a)), and have access to and authority to develop relationships with customers of Employer because of his position and status as Employer's Chief Executive Officer, which he would not otherwise attain. In consideration of the foregoing, Executive agrees to comply with the terms of this Section 7. (b) RESTRICTED PERIOD. The restraints imposed by this Section 7 shall apply during any period that Executive continues to receive payment of Base Compensation hereunder, and for a period of one year thereafter (the "Restricted Period"); provided, however, that, notwithstanding anything contained herein to the contrary, the restraints imposed by this Section 7 shall not apply following the termination of Executive's employment with Employer by Employer without Cause. In the event that any Court having jurisdiction should find that the Restricted Period is so long and/or the scope (distance) (as set forth below) is so broad as to constitute an undue hardship on Executive, then, in such event only, the Restricted Period and area limitations shall be valid for the maximum time and area for which they could be legally made and enforced. (c) COVENANT. During the Restricted Period, Executive shall not, as an executive (other than as an executive of Employer or an affiliate thereof), employee, employer, stockholder, officer, director, partner, consultant, advisor, proprietor, lender, provider of capital or other ownership, operational or management capacity, directly or indirectly, (i) solicit or hire any employee of Employer or otherwise interfere with or disrupt the employment relationship between Employer and any employee, (ii) solicit or do business with (A) Employer's customers with whom Employer did business while Executive was employed under this Agreement, or (B) individuals or entities who Executive met as a result of his position with Employer while Executive was employed -20- under this Agreement, that (in the case of either clause (A) or (B)) results in competition with Employer in any county, parish or other comparable jurisdiction within a state, province or nation located in North America in which any of such customers have operations (other than customers whose business relationship with Employer has terminated for at least 90 days) or in which Employer has conducted business while Executive was employed under this Agreement (collectively, the "Restricted Area"), or (iii) be associated with any entity engaged in the business of oil and/or gas exploration, development, production, distribution and/or marketing in the Restricted Area that results in competition with Employer (but excluding association due to ownership of less than 5% of the outstanding securities of any such entity). (d) REASONABLENESS. Executive expressly recognizes and agrees that the restraints imposed by this Section 7 are (i) reasonable as to time, geographic limitation and scope of activity to be restrained; (ii) reasonably necessary to the enjoyment by Employer of the value of its assets and to protect its legitimate interests; and (iii) not oppressive. Executive further expressly recognizes and agrees that the restraints imposed by this Section 7 represent a reasonable and necessary restriction for the protection of the legitimate interests of Employer, that the failure by the Executive to observe and comply with the covenants and agreements in this Section 7 will cause irreparable harm to Employer, that it is and will continue to be difficult to ascertain the harm and damages to Employer that such a failure by the Executive would cause, that the consideration received by the Executive for entering into these covenants and agreements is fair, that the covenants and agreements and their enforcement will not deprive Executive of his ability to earn a reasonable living in the oil and gas industry or otherwise, and that Executive has acquired knowledge and skills in his field that will allow him to obtain employment without violating these covenants and agreements. Executive further expressly acknowledges that he has been encouraged to and has consulted independent counsel, and has reviewed and considered this Agreement with that counsel before executing this Agreement. 8. MEMORANDA, NOTES, RECORDS, ETC. All memoranda, notes, records, software, customer lists or other documents (including, but not limited to, those in electronic form) made or compiled by Executive or otherwise made available to him concerning the business of Employer or its subsidiaries or affiliates shall be Employer's property and shall be delivered to Employer upon the expiration or termination of Executive's employment hereunder or at any other time upon request by Employer, and Executive shall retain no copies of those documents; provided, however, that Executive may retain copies of personal information and information concerning his compensation and benefits entitlements and other employee rights. Executive shall never at any time have or claim any right, title or interest in any material or matter of any sort prepared for or used in connection with the business or promotion of Employer. 9. ENFORCEMENT. The parties hereto recognize that the covenants of Executive hereunder are special, unique and of extraordinary character. Accordingly, it is the intention of the parties that, in addition to any other rights and remedies which Employer may have in the event of any breach of this Agreement, Employer shall be entitled, and hereby is expressly and irrevocably authorized by Executive, INTER ALIA, to -21- demand and obtain specific performance, including without limitation temporary and permanent injunctive relief, and all other appropriate equitable relief against Executive in order to enforce against Executive, or in order to prevent any breach or any threatened breach by Executive of, the covenants and agreements contained herein. In case of any breach of this Agreement, nothing herein contained shall be construed to prevent Employer from seeking such other remedy in the courts as it may elect or invoke. 10. MISCELLANEOUS. (a) NON-DELEGATION OF DUTIES. Executive may not delegate the performance of any of his obligations or duties hereunder, or assign any rights hereunder, without the prior written consent of Employer. Any such purported delegation or assignment in the absence of such written consent shall be null and void with no force or effect. Notwithstanding the foregoing, nothing herein shall prevent Executive from the appropriate delegation of tasks to other executives, employees, assistants and other service providers. (b) BINDING EFFECT. This Agreement shall be binding on and inure to the benefit of the parties hereto and their respective heirs, representatives, successors and permitted assigns and any receiver, trustee in bankruptcy or representative of the creditors of each such person. Employer shall require any successor (whether direct or indirect, by purchase, merger, reorganization, consolidation, acquisition of property or stock, liquidation, or otherwise) to all or a significant portion of its assets, by agreement in form and substance satisfactory to Executive, expressly to assume and agree to perform this Agreement in the same manner and to the same extent that Employer would be required to perform this Agreement if no such succession had taken place. Regardless whether such agreement is executed, this Agreement shall be binding upon any successor of Employer in accordance with the operation of law and such successor shall be deemed the "Employer" for purposes of this Agreement. (c) SURVIVAL OF COVENANTS. Notwithstanding anything contained in this Agreement, in the event Executive's employment is terminated for any reason whatsoever, the covenants and agreements of Executive contained in Sections 4, 5, 6, 7, 8, 9 and 10, and the covenants of Employer contained in Sections 4 and 5 hereof shall survive any such termination and shall not lapse except as provided herein. (d) SEVERABILITY/MODIFICATION. If any term or provision of this Agreement is held or deemed to be invalid or unenforceable, in whole or in part, by a court of competent jurisdiction, such term or provision shall be ineffective to the extent of such invalidity or unenforceability without rendering invalid or unenforceable the remaining terms and provisions of this Agreement. (e) GOVERNING LAW. This Agreement is entered into in Ohio, and the construction, validity and interpretation of this Agreement shall be governed by the laws of the State of Ohio without regard to the laws of conflicts of laws thereof. -22- (f) ARBITRATION. In the event of any dispute, controversy or claim between Employer and Executive arising out of or relating to the interpretation, application or enforcement of any provision of this Agreement (other than with respect to provisions under Section 4(f) of this Agreement), either Employer or Executive may, by written notice to the other, require such dispute or difference to be submitted to arbitration. The arbitrator shall be selected by agreement of the parties or, if they do not agree on an arbitrator within 30 days after one party has notified the other of his or its desire to have the question settled by arbitration, then the arbitrator shall be selected pursuant to the procedures of the American Arbitration Association (the "AAA") in Canton, Ohio. The determination reached in such arbitration shall be final and binding on all parties. Enforcement of the determination by such arbitrator may be sought in any court of competent jurisdiction. Unless otherwise agreed by the parties, any such arbitration shall take place in Canton, Ohio, and shall be conducted in accordance with the Commercial Arbitration Rules of the AAA. (g) EFFECTIVENESS; ENTIRE AGREEMENT; AMENDMENT. This Agreement contains the entire understanding and agreement between the parties relating to the subject matter hereof, and it supersedes all previous and contemporaneous negotiations, commitments, writings and understandings. Neither this Agreement nor any provision hereof may be waived, modified, amended, changed, discharged or terminated, except by an agreement in writing signed by the party against whom enforcement of any waiver, modification, change, amendment, discharge or termination is sought. (h) NOTICES. Any notice required or permitted to be given under the provisions of this Agreement shall be in writing and shall be deemed to have been duly given on the date of delivery if delivered personally to the party to whom notice is to be given (or to the appropriate address below), or on the third day after mailing if mailed to the party to whom notice is to be given by certified or registered mail, return receipt requested, postage prepaid, or by courier, addressed as follows, or to such other person at such other address as any party may request in writing to the other party to this Agreement: To Executive: John L. Schwager ------------ c/o Belden & Blake Corporation 5200 Stoneham Road North Canton, Ohio 47720 To Employer: Belden & Blake Corporation 5200 Stoneham Road North Canton, Ohio 47720 Any party may change its address for purposes of this paragraph by giving the other parties written notice of the new address in the manner set forth above. (i) HEADINGS. The section headings herein are for convenience only and shall not be used in interpreting or construing this Agreement. -23- (j) INDEMNIFICATION. Employer shall defend and hold Executive harmless to the fullest extent permitted by applicable law in connection with any civil or criminal claim, action, suit, investigation or proceeding arising out of or relating to performance by Executive of services for, or action of Executive as a director, officer or employee of Employer, or of any other person or enterprise at the request of Employer. Expenses incurred by Executive in defending any such claim, action, suit, investigation or proceeding shall be paid by Employer in advance of the final disposition thereof upon the receipt by Employer of an undertaking by or on behalf of Executive to repay said amount if it shall ultimately be determined that Executive is not entitled to be indemnified hereunder; provided, however, that this indemnification arrangement shall not apply to a nonderivative action commenced by Employer against Executive. The foregoing shall be in addition to, and shall not be deemed to limit in any respect, any indemnification rights Executive may have by law, contract, charter, by-law or otherwise. IN WITNESS WHEREOF, the parties hereto have executed this Employment Agreement to be effective as of the Effective Date. EXECUTIVE: /s/ John L. Schwager --------------------------------------- John L. Schwager EMPLOYER: BELDEN & BLAKE CORPORATION, an Ohio Corporation By: /s/ William S. Price III --------------------------------------- William S. Price III Chairman of the Compensation Committee of the Board of Directors -24- EXHIBIT A GENERAL RELEASE AND WAIVER In consideration of the payments and benefits (the "Termination Benefits") to which the undersigned (the "Executive") is entitled under Section 4(c) of the Amended and Restated Employment Agreement, dated (the "Employment Agreement"), by and between the Executive and Belden & Blake Corporation (the "Employer"), and for other good and valuable consideration, receipt of which is hereby acknowledged, the Executive agrees as follows: 1. CONFIRMATION OF TERMINATION. The Executive's employment with the Employer shall terminate as of _____________________ (the "Termination Date"). 2. GENERAL RELEASE AND WAIVER (a) EXECUTIVE HEREBY RELEASES, REMISES AND ACQUITS EMPLOYER AND ALL OF ITS AFFILIATES, AND THEIR RESPECTIVE OFFICERS, DIRECTORS, EMPLOYEES, SUCCESSORS AND ASSIGNS (COLLECTIVELY REFERRED TO HEREIN AS THE "RELEASEES"), JOINTLY AND SEVERALLY, FROM ANY AND ALL CLAIMS, KNOWN OR UNKNOWN, WHICH EXECUTIVE OR EXECUTIVE'S HEIRS, SUCCESSORS OR ASSIGNS HAVE OR MAY HAVE AGAINST ANY RELEASEE ARISING ON OR PRIOR TO THE DATE OF THIS GENERAL RELEASE AND WAIVER (THIS "RELEASE") AND ANY AND ALL LIABILITY WHICH ANY SUCH RELEASEE MAY HAVE TO EXECUTIVE, WHETHER DENOMINATED CLAIMS, DEMANDS, CAUSES OF ACTION, OBLIGATIONS, DAMAGES OR LIABILITIES ARISING FROM ANY AND ALL BASES, HOWEVER DENOMINATED, INCLUDING BUT NOT LIMITED TO THE AGE DISCRIMINATION IN EMPLOYMENT ACT, THE AMERICANS WITH DISABILITIES ACT OF 1990, THE FAMILY AND MEDICAL LEAVE ACT OF 1993, TITLE VII OF THE UNITED STATES CIVIL RIGHTS ACT OF 1964, 42 U.S.C. sec. 1981, THE OHIO CIVIL RIGHTS ACT, secs. 124, 4111, 4112 OR 4123 OF THE OHIO REVISED CODE ANNOTATED, OHIO COMMON LAW OR ANY OTHER FEDERAL, STATE, OR LOCAL LAW AND ANY WORKERS' COMPENSATION OR DISABILITY CLAIMS UNDER ANY SUCH LAWS. THIS RELEASE IS FOR ANY AND ALL CLAIMS INCLUDING BUT NOT LIMITED TO CLAIMS ARISING FROM AND DURING EXECUTIVE'S EMPLOYMENT RELATIONSHIP WITH EMPLOYER AND ITS AFFILIATES OR AS A RESULT OF THE TERMINATION OF SUCH RELATIONSHIP. EXECUTIVE FURTHER AGREES THAT EXECUTIVE WILL NOT FILE OR PERMIT TO BE FILED ON EXECUTIVE'S BEHALF ANY SUCH CLAIM. NOTWITHSTANDING THE PRECEDING SENTENCE OR ANY OTHER PROVISION OF THIS AGREEMENT, THIS RELEASE IS NOT INTENDED TO INTERFERE WITH EXECUTIVE'S RIGHT TO FILE A CHARGE WITH THE EQUAL EMPLOYMENT OPPORTUNITY COMMISSION IN CONNECTION WITH ANY CLAIM HE BELIEVES HE MAY HAVE AGAINST ANY OF THE RELEASEES. HOWEVER, BY EXECUTING THIS RELEASE, EXECUTIVE HEREBY WAIVES THE RIGHT TO RECOVER IN ANY PROCEEDING EXECUTIVE MAY BRING BEFORE THE EQUAL EMPLOYMENT OPPORTUNITY COMMISSION OR ANY STATE HUMAN RIGHTS A-1 COMMISSION OR IN ANY PROCEEDING BROUGHT BY THE EQUAL EMPLOYMENT OPPORTUNITY COMMISSION OR ANY STATE HUMAN RIGHTS COMMISSION ON EXECUTIVE'S BEHALF. THIS RELEASE IS FOR ANY RELIEF, NO MATTER HOW DENOMINATED, INCLUDING, BUT NOT LIMITED TO, INJUNCTIVE RELIEF, WAGES, BACK PAY, FRONT PAY, COMPENSATORY DAMAGES, OR PUNITIVE DAMAGES. THIS RELEASE SHALL NOT APPLY TO ANY OBLIGATION OF EMPLOYER PURSUANT TO SECTION 4(c) OR, IF APPLICABLE, 4(f) OF THE EMPLOYMENT AGREEMENT OR RIGHTS OF EXECUTIVE, IF ANY, TO INDEMNIFICATION AND/OR INSURANCE WITH RESPECT TO HIS SERVICE TO OR FOR THE BENEFIT OF THE EMPLOYER AND ITS AFFILIATES AS AN EMPLOYEE, DIRECTOR OR IN ANY OTHER CAPACITY. (b) EXECUTIVE ACKNOWLEDGES THAT THE TERMINATION BENEFITS HE IS RECEIVING PURSUANT TO THE EMPLOYMENT AGREEMENT IN CONNECTION WITH THE FOREGOING RELEASE ARE IN ADDITION TO ANYTHING OF VALUE TO WHICH EXECUTIVE ALREADY IS ENTITLED FROM EMPLOYER. 3. CERTAIN FORFEITURES IN EVENT OF BREACH The Executive acknowledges and agrees that, notwithstanding any other provision of this Agreement, in the event the Executive materially breaches any of his obligations under this Agreement, the Executive will forfeit his right to receive the Termination Benefits under the Employment Agreement to the extent not theretofore paid to him as of the date of such breach and, if already made as of the time of breach, the Executive agrees that he will reimburse the Employer, immediately, for the amount of such payment. 4. NO ADMISSION This Release does not constitute an admission of liability or wrongdoing of any kind by the Employer or its affiliates. 5. HEIRS AND ASSIGNS The terms of this Release shall be binding on the Executive and his successors and assigns. 6. KNOWING AND VOLUNTARY WAIVER The Executive acknowledges that, by the Executive's free and voluntary act of signing below, the Executive agrees to all of the terms of this Release and intends to be legally bound thereby. The Executive understands and acknowledges that he may consider whether to agree to the terms contained herein for a period of twenty-one days after the Termination Date. However, the Termination Benefits will be delayed until this Release is executed and delivered to the Employer; provided that there shall be no such delay with respect to any Termination Benefit that is due to be paid upon the closing date of a A-2 Change in Control (as defined in the Employment Agreement). The Executive acknowledges that he has been advised to consult with an attorney prior to executing this Release. This Release will become effective, enforceable and irrevocable on the eighth day after the date on which it is executed by the Executive (the "Release Effective Date"). During the seven-day period prior to the Effective Date, the Executive may revoke his agreement to accept the terms hereof by serving notice in writing to the Employer of his intention to revoke. If the Executive exercises his right to revoke hereunder, he shall forfeit his right to receive any of the Termination Benefits provided for herein, and to the extent such Termination Benefits have already been provided, the Executive agrees that he will immediately reimburse the Employer for the amounts of such payment. ------------------------------------ John L. Schwager Acknowledgment - -------------- STATE OF _________________) ss: COUNTY OF_________________) On the ____ day of __________, 20__, before me personally came John L. Schwager who, being by me duly sworn, did depose and say that he resides at _________________; and did acknowledge and represent that he has had an opportunity to consult with attorneys and other advisers of his choosing regarding the Release attached hereto, that he has reviewed all of the terms of the Release and that he fully understands all of its provisions, including, without limitation, the general release and waiver set forth therein. - ------------------------------ Notary Public Date: ------------- A-3 EXHIBIT B NOTICE OF EXERCISE Belden & Blake Corporation - --------------------------- - --------------------------- Date of Exercise: ----------------- Ladies and Gentlemen: This constitutes notice under my stock option that I elect to purchase the number of shares for the price set forth below. Stock option dated -------------------------------- Number of shares as to which option is exercised -------------------------------- Certificates to be issued in name of: -------------------------------- Total exercise price: $ -------------------------------- Cash payment delivered herewith: $ -------------------------------- By this exercise, I agree (i) to provide such additional documents as Executive may reasonably require and (ii) to provide for the payment by me to Executive of your withholding obligation, if any, relating to the exercise of this option. I hereby make the following certifications and representations with respect to the number of shares of Common Stock of Employer listed above (the "SHARES"), which are being acquired by me for my own account upon exercise of the Option as set forth above: I acknowledge that the Shares have not been registered under the Securities Act of 1933, as amended (the "ACT"), and are deemed to constitute "restricted securities" under Rule 701 and "control securities" under Rule 144 promulgated under the Act. I warrant and represent to Employer that I have no present intention of distributing or selling said Shares, except as permitted under the Act and any applicable state securities laws. B-1 I further acknowledge that I will not be able to resell the Shares for at least ninety (90) days after the stock of Employer becomes publicly traded (i.e., subject to the reporting requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934) under Rule 701 and that more restrictive conditions apply to affiliates of Employer under Rule 144. I further acknowledge that all certificates representing any of the Shares subject to the provisions of the Option shall have endorsed thereon appropriate legends reflecting the foregoing limitations, as well as any legends reflecting restrictions pursuant to Employer's Articles of Incorporation, Bylaws and/or applicable securities laws. I further agree that, if required by Employer (or a representative of the underwriters) in connection with an underwritten registration of the offering of any securities of Employer under the Act, I will not sell or otherwise transfer or dispose of any shares of Common Stock or other securities of Employer during such period (not to exceed one hundred eighty (180) days or, if less, the period of time any other executive officer of Employer is so restricted) following the effective date of the registration statement of Employer filed under the Act (the "EFFECTIVE DATE") as may be requested by Employer or the representative of the underwriters. I further agree that Employer may impose stop-transfer instructions with respect to securities subject to the foregoing restrictions until the end of such period. Very truly yours, ------------------------------ John L. Schwager B-2 EX-10.12 5 l92370aex10-12.txt EXHIBIT 10.12 Exhibit 10.12 December 21, 2001 Mr. Leo A. Schrider 2962 Wildridge, N.W. Massillon, Ohio 44646 Dear Leo: This Letter of Agreement summarizes the discussions which we have had concerning your transition into retirement over the next two years. The terms are as follows: 1. Subject to earlier termination as set forth in Paragraph 14, this arrangement will be in effect from January 1, 2002 through December 31, 2003 (the "Transition Period"). 2. Effective January 1, 2002, you will be classified as a part-time employee of the Company. 3. During the Transition Period, you will work as a part-time employee approximately ten hours per week on average, performing such duties as may be assigned. 4. During the Transition Period, you would receive the full base salary which you are receiving as of December 31, 2001, i.e., $145,948.37 per year. 5. You would qualify for any applicable executive year-end bonus for calendar year 2001. 6. Prior stock options granted to you become 100% vested upon your execution of this Agreement. 7. Belden will pay the full cost of medical and dental insurance coverage through June 30, 2002. You may thereafter pick up the cost at the COBRA rate until you are eligible for Medicare. In the event of your death, your current wife may continue to purchase at the COBRA rate until age 65 unless she were to remarry or go to work for any employer which offers medical benefits. 8. After December 31, 2001, you will not be eligible to participate in any other benefit plan of the Company. 9. During the Transition Period, you would be reimbursed for reasonable out-of-pocket expenses incurred in your part-time position with the Company. 10. You would maintain an office at Belden, along with access to computer and other support services. This arrangement will continue at the sole discretion of the CEO. Page 2. December 21, 2001 Leo A. Schrider 11. During the Transition Period, you would not perform work of any kind for any other entity, whether as an employee or as a contractor or consultant, without my prior express written authorization. 12. Dave Wozniak will assume your current responsibilities as of January 1, 2002, and thereafter you will report to Dave. 13. This Agreement will be considered to be your request for part time employment effective December 31, 2001, and resignation as a part time employee effective December 31, 2003, or an earlier date of termination pursuant to Paragraph 14. 14. This Agreement may be terminated by either Belden or you at any time prior to December 31, 2003, upon ten days written notice. If the agreement is terminated, any remaining salary payable through December 31, 2003, as provided in Subsection 4 of this letter will be paid in one lump sum payment within thirty days of written notice of the termination of the agreement by either Belden or you. The terms of Paragraphs 6, 7 and 16 will survive any termination of this Agreement. 15. The acceptance of the terms of this Agreement constitutes a waiver of any claim you may have for severance pay of any kind under any other agreement or Belden policy. 16. You agree that during your employment and permanently following the end of your employment you will not disclose to any person, firm, association, partnership, entity or corporation, other than in discharge of your duties or pursuant to a court order or in discovery proceedings in which you are required to present evidence or testimony in a matter associated with Belden's business dealings, any information concerning Belden's business, including: (i) the business operations or internal structure of Belden; (ii) Belden's customers; (iii) Belden's financial condition; and (iv) other confidential information including but not limited to trade secrets, technical data, sales figures and forecasts, marketing analyses and studies, customer and price lists, including any and all of the foregoing confidential information of any affiliates or subsidiaries of Belden. All papers and records of every kind, including all memoranda, lists, tapes, notes, sketches, designs, plans, data, telephone lists, address lists, rolodexes, customer lists, price lists and other documents, whether made by your or Belden relating in any way to the business and affairs of Belden, its successors, affiliates and subsidiaries or to any business or field of investigation of Belden which shall at any time come into your possession or control, shall be the sole and exclusive property of Belden and you shall surrender these to Belden at any time upon request from Belden. 2 Page 3. December 21, 2001 Leo A. Schrider If the terms of this Agreement are acceptable to you, please sign and return a copy to me no later than December 31, 2001. Sincerely, /s/ John L. Schwager - --------------------------------------- John L. Schwager President & Chief Executive Officer Accepted this 21st day of December, 2001 /s/ Leo A. Schrider - ----------------------------------------- Leo A. Schrider 3 EX-21 6 l92370aex21.txt EXHIBIT 21 EXHIBIT 21 SUBSIDIARIES OF THE REGISTRANT SUBSIDIARY STATE OF INCORPORATION - ---------- ---------------------- The Canton Oil & Gas Company Ohio Ward Lake Drilling, Inc. Michigan As of December 31, 2001 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 7 l92370aex23.txt EXHIBIT 23 Exhibit 23 CONSENT OF INDEPENDENT AUDITORS We consent to the incorporation by reference in the Registration Statement (Form S-8 No. 333-38624) pertaining to the Belden & Blake Corporation Nonqualified Stock Option Plan of our report dated March 13, 2002, 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, 2001. ERNST & YOUNG LLP Cleveland, Ohio March 25, 2002 -----END PRIVACY-ENHANCED MESSAGE-----