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
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