10-K405 1 l87048ae10-k405.txt BELDEN & BLAKE CORPORATION 10-K405 1 FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 [x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File No. 0-20100 BELDEN & BLAKE CORPORATION (Exact name of registrant as specified in its charter) OHIO 34-1686642 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 5200 STONEHAM ROAD NORTH CANTON, OHIO 44720 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (330) 499-1660 Securities registered pursuant to Section 12(b) of the Act: NONE Securities registered pursuant to Section 12(g) of the Act: COMMON STOCK, WITHOUT PAR VALUE (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No --- --- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. X --- As of February 28, 2001, Belden & Blake Corporation had outstanding 10,303,159 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. 2 PART I ------ Item 1. BUSINESS -------- GENERAL Belden & Blake Corporation (the "Company") 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 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 Services 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. The sale resulted in net proceeds of approximately $69.2 million, which were used to reduce bank debt. At December 31, 2000, the Company operated in Ohio, Pennsylvania, New York and Michigan. At December 31, 2000, the Company's net production was approximately 48.5 Mmcf (million cubic feet) of natural gas and 1,465 Bbls (barrels) of oil per day. At that date, the Company owned interests in 6,337 gross (5,272 net) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with proved reserves totaling 374 Bcf (billion cubic feet) of natural gas and 8.7 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 $1.2 billion at December 31, 2000. At December 31, 2000, the Company operated approximately 5,817 wells, including wells operated for third parties. At that date, the Company held leases on 990,904 gross (878,042 net) acres, including 538,970 gross (467,675 net) undeveloped acres. The Company owned and operated 1,741 miles of gas gathering systems with access to the commercial and industrial gas markets of the northeastern United States at December 31, 2000. The Company has a consistent and successful track record of reserve replacement and growth through both drilling and acquisitions. Since its formation in 1992 through December 31, 2000, the Company has added approximately 413 Bcfe (billion cubic feet of natural gas equivalent) of proved developed reserves through drilling and acquisitions at an average cost of $.79 per Mcfe (thousand cubic feet of natural gas equivalent). This represented approximately 207% of the oil and gas produced by the Company during that period. During 2000, the Company drilled 149 gross (104.1 net) wells at a direct cost of approximately $17.0 million for the net wells. The 2000 drilling activity added 17.9 Bcfe of proved developed reserves at an average cost of $.94 per Mcfe. Proved developed reserves added through drilling in 2000 represented approximately 76% of 2000 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, 1 3 all references herein to the "Company" are to Belden & Blake Corporation, its subsidiaries and predecessor entities. SIGNIFICANT EVENTS When gas prices declined sharply in 1998, the Company's previous lenders reduced its 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 .8 Bcfe of oil and gas reserves. 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. 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 "Term Loan"). The Facility has a two year term. 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 ("the Notes"). No amounts were drawn under the Term Loan and the Term Loan commitment terminated on December 26, 2000. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. Up to $20 million in letters of credit may be issued pursuant to the conditions of the Revolver. 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 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 and Michigan) 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 5,500 feet. Drilling success rates of the Company and others drilling in these formations historically have exceeded 90% with production generally lasting longer than 20 years. 2 4 The combination of long-lived production and high drilling success rates at these shallower depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the Appalachian Basin. As 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. In addition, the Company is a pioneer in the production of methane from coalbed formations in Pennsylvania. 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 and production opportunities in the Michigan Basin with an established operating company that provided the critical mass to operate efficiently. Ward Lake currently operates 755 wells producing approximately 41 Mmcf (20 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 1,700 feet) blanket Antrim Shale formation. Success rates for companies drilling to this formation have exceeded 90%, with production often lasting as long as 20 years. The Michigan Basin also contains deeper formations with greater reserve potential. The Company has also established production from certain of these deeper formations through its drilling operations. 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. 3 5 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; utilization of the Company's advanced technology to enhance production and reserves discovered; and, further expansion of the Company's natural gas gathering network. 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 drilling in shallow blanket formations and development and exploratory drilling in deeper, more prolific formations. Coupled with its extensive knowledge of its operating areas, this broad portfolio approach allows the Company to optimize economic returns and minimize much of the geological risk associated with oil and gas exploration and development. The result is analogous to a manufacturing process, in that the Company is able to predict with a high degree of accuracy the expected reserve additions and overall finding costs of its drilling activities. 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 and has established a substantial leasehold position overlying potentially productive coalbed methane formations in western Pennsylvania. The Company's drilling budget in 2001 is approximately $29.2 million, which is expected to fund the drilling of approximately 158 gross (150.9 net) wells to shallow blanket formations and 47 gross (24.7 net) wells to the deeper more prolific formations in the Appalachian and Michigan Basins. - IMPROVE THE COMPANY'S FINANCIAL POSITION. At December 31, 2000, the Company had a deficit in shareholders' equity of $48.3 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 consider attempting 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 success rates at the shallow depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the Appalachian Basin. The Company has been applying more advanced technology, including 3-D seismic, horizontal drilling, advanced fracturing techniques and enhanced oil recovery methods. The Company is implementing these techniques to improve drilling success rates, reserves discovered per well, production rates, reserve recovery rates and total economics in its operating areas. - IMPROVE PROFIT MARGINS. To become one of the most efficient operators in the Appalachian and Michigan Basins, the Company intends to improve its profit margins on the production from existing and acquired properties through advanced production technologies, operating efficiencies, mechanical improvements and the use of enhanced recovery techniques. Through its production field offices, the Company continuously 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 reduce 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 4 6 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. - EXPAND NATURAL GAS GATHERING. The Company's extensive gas gathering systems are an integral part of the Company's business strategy. The Company currently operates approximately 1,489 miles of natural gas gathering lines in Ohio, Pennsylvania and New York and 252 miles of lines in Michigan, all of which are connected or have the ability to connect to various intrastate and interstate natural gas transmission and distribution systems. The interconnections with these pipelines affords the Company access to numerous major gas markets, including existing and proposed electric power generating facilities. It is the Company's intention to expand its gas gathering systems to further improve the rate of return on the Company's drilling and development activities. The Company has excellent business relationships with a number of utilities and industrial end users located within the Company's operating areas, providing it with a direct outlet for a portion of its natural gas production. - 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 substantially all 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 enhanced and secondary recovery techniques. The Company currently maintains production field offices in Ohio, Pennsylvania, New York and Michigan. Through these offices, the Company continuously reviews its properties to determine what action can be taken to reduce operating costs and/or improve production. The Company also uses secondary recovery techniques, which typically involve methods of oil extraction in which external energy sources are applied to extract additional 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. 5 7 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, ------------------------------------------------------------- 1996 1997 1998 1999 2000 ------- ------- ------- ------- ------- Production: Gas (Bcf) 25.4 27.2 30.1 27.0 20.0 Oil (Mbbl)(1) 719 753 768 713 592 Average sales price: Gas (per Mcf)(2) $ 2.56 $ 2.65 $ 2.57 $ 2.50 $ 3.17 Oil (per barrel) 20.24 18.10 12.61 16.57 27.29 Mcfe 2.67 2.70 2.51 2.54 3.38 Average production costs per Mcfe (including production taxes) 0.72 0.78 0.77 0.80 0.99 Operating margin per Mcfe 1.95 1.92 1.74 1.74 2.39 Total oil and gas revenues (in thousands) 79,491 85,756 87,055 79,299 79,743 Total production expenses (in thousands) 21,266 24,668 26,725 25,240 23,326
(1) Thousand barrels (2) Thousand cubic feet 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, ------------------------------------------------------------- 1996 1997 1998 1999 2000 ------- ------- ------- ------- ------- Production: Gas (Bcf) 21.8 22.9 24.5 21.5 18.9 Oil (Mbbl) 612 658 686 642 576 Average sales price: Gas (per Mcf) $ 2.48 $ 2.57 $ 2.48 $ 2.50 $ 3.20 Oil (per barrel) 20.23 18.04 12.57 16.51 27.36 Mcfe 2.61 2.63 2.43 2.54 3.41 Average production costs per Mcfe (including production taxes) 0.72 0.77 0.74 0.81 1.00 Operating margin per Mcfe 1.89 1.86 1.69 1.73 2.41 Total oil and gas revenues (in thousands) 66,297 70,635 69,458 64,489 76,252 Total production expenses (in thousands) 18,243 20,598 21,239 20,602 22,272
6 8 Gas Gathering. The Company currently operates approximately 1,741 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 major gas markets. The Company's gas gathering revenues totaled $3.1 million in 2000. Direct costs associated with gas gathering in 2000 totaled $1.5 million. EXPLORATION AND DEVELOPMENT The Company's exploration and development activities include development drilling in the highly developed or blanket formations and development and exploratory drilling in the less developed formations of the Appalachian 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 2000, the Company drilled 111 gross (86.2 net) wells to highly developed or shallow blanket formations in its four state operating area at a direct cost of approximately $11.5 million for the net wells. The Company also drilled 38 gross (17.9 net) wells to less developed and deeper formations in 2000 at a direct cost of approximately $5.5 million for the net wells. The result of this drilling activity is shown in the table on page 12. In 2001, the Company expects to spend approximately $29.2 million on development and exploratory drilling of approximately 205 gross (175.6 net) wells. The Company believes that its diversified portfolio approach to its drilling activities results in more consistent and predictable economic results than might be experienced with a less diversified or higher risk drilling program profile. Highly Developed Formations. In general, the highly developed or blanket formations found in the Appalachian and Michigan Basins are widespread in extent and hydrocarbon accumulations are not dependent upon local stratigraphic or structural trapping. Drilling success rates exceed 90%. The principal risk of such wells is uneconomic recoverable reserves. The highly developed formations in the Appalachian Basin are relatively tight reservoirs that produce 20% to 30% of their recoverable reserves in the first year and 40% to 50% of their total recoverable reserves in the first three years, with steady declines thereafter. Average well lives range from 15 years to 25 years or more. The Antrim Shale formation, the principal shallow blanket formation in the Michigan Basin, is characterized by high formation water production in the early years of a well's productive life with water production decreasing over time. Antrim Shale wells typically produce at rates of 100 Mcf to 125 Mcf per day for several years, with modest declines thereafter. Gas production often increases in the early years as the producing formation becomes less water saturated. Average well lives are 20 years or more. The Company plans to drill 28 gross (26.1 net) wells to the Antrim Shale formation in 2001. Producing natural gas in the form of methane from coalbed formations is a common practice in the Rocky Mountain, Mid-Continent and southern Appalachian sections of the United States. It is just beginning to become a factor in the northern Appalachian Basin region. The Company is a pioneer in coalbed methane development and production in Pennsylvania, presently operating 70 coalbed methane 7 9 ("CBM") 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. Eight of the 14 CBM wells drilled by the Company in 2000 are currently producing at or above expected levels. The remaining 6 wells drilled in 2000 were drilled in areas of known coal deposits that had not been tested for CBM production. These wells have all been drilled to their targeted total depth and are currently being tested for production volumes and economic viability. The Company currently holds leases on approximately 65,000 net undeveloped acres with potential for CBM production and plans to drill 34 wells to the CBM formations in 2001. Certain typical characteristics of the highly developed or blanket formations drilled by the Company in recent years are described below:
Range of Range of Average Average Drilling Gross Reserves Range of and Completion per Completed Well Depths Costs per Well Well ----------- -------------- -------------- (in feet) (in thousands) (in Mmcfe) (1) Ohio 1,200-5,500 $ 75-160 80-150 Pennsylvania: Coalbed Methane 900-1,800 100-125 150-250 Clarendon 1,100-2,000 45-55 30-50 Medina 5,000-6,200 170-210 150-300 New York 3,000-5,000 100-150 75-300 Michigan 1,000-1,500 190-240 400-600
(1) Million cubic feet equivalent Less Developed Formations. The Appalachian Basin has productive and potentially productive sedimentary formations to depths of 30,000 feet or more, but the combination of long-lived production and high drilling success rates in the shallow formations has curbed the development of the deeper formations in the basin. The Company believes it possesses the technological expertise and the acreage position needed to explore the deeper formations in a cost effective manner. The less developed formations in the Appalachian Basin include the Knox sequence of sandstones and dolomites, which includes the Rose Run, Beekmantown and Trempealeau productive zones, at depths ranging from 2,500 feet to 8,000 feet. The 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. Approximately 3,000 wells have been drilled to the Knox formations during the past 10 years. Through 2000, the Company had drilled 323 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. 8 10 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. For the data in the tables that follow, "gross" refers to the total wells or acres in which the Company owns a working interest and "net" refers to gross wells or acres multiplied by the percentage working interest it owns. The following table shows the Company's drilling results in the Knox sequence:
Drilling Results in the Knox Formations --------------------------------------------------------------------------------- Average Gross Wells Drilled Wells Completed (1) Reserves per ------------------- -------------------- Completed Well Period Gross Net Gross Net (Mmcfe) ----------- ----- --- ----- --- ------- 1989-1990 18 14.5 5 4.0 456 1991 11 10.3 5 4.7 170 1992 15 12.5 8 6.4 285 1993 30 20.2 16 8.8 360 1994 25 14.2 17 9.8 389 1995 34 16.3 18 8.8 343 1996 38 22.0 25 15.5 422 1997 54 26.6 30 16.4 450 1998 47 22.7 26 11.4 370 1999 18 4.8 9 2.1 320 2000 33 12.9 16 6.2 400
------------ (1) Completed as producing wells in the Knox formations. The Company's historical experience is that the average Knox well produces 20% to 25% of its recoverable reserves in the first year of production and approximately 50% of its recoverable reserves in the first three years with a steady decline thereafter. Wells in the Knox formations have an expected productive life ranging from 10 to 15 years. 9 11 The following table demonstrates the impact of Knox formation wells on the Company's annual production since 1996:
PRODUCING WELLS AND PRODUCTION FROM KNOX FORMATIONS ------------------------------------------------------------------ 1996 1997 1998 1999 2000 ---- ---- ---- ---- ---- Number of wells in production: Gross 82 112 140 131 147 Net 58.9 75.6 88.0 74.8 80.4 Percent of total net wells 0.9% 1.0% 1.2% 1.1% 1.5% Annual production (net): Gas (Mmcf) 2,788 3,600 4,111 2,603 2,144 Oil (Mbbl) 78.2 111.2 181.9 161.5 144.1 Combined (Mmcfe) 3,257 4,267 5,202 3,572 3,009 Percent of total combined production 11% 13% 15% 11% 13%
Productive Knox wells represented approximately 1.5% of the Company's total productive wells at December 31, 2000. Production from Knox wells in 2000, however, equaled 13% of the Company's total production on an Mcfe basis. The Company plans to drill or participate in joint ventures to drill 41 gross (19.8 net) wells to the Knox formation in 2001. In addition, the Company has also tested the more prolific Niagaran Carbonate, Dundee Carbonate, Trenton/Black River Carbonates ("TBR"), Onondaga Limestone and Oriskany Sandstone formations. Development of the TBR began in the mid-1990's in south-central New York and more recently in central West Virginia. Since that time, approximately 80 wells have been drilled to this formation, establishing commercial gas production in several areas. Based on historical information available in public records, wells completed in the TBR formation have reserves in the range of 1.0 to 2.0 Bcf of natural gas per well. The Company drilled one TBR well in 1998 and three TBR wells in 2000. While expected geologic conditions and gas shows were encountered in all four of these wells, economic production was not established. The Company currently holds leases on approximately 70,000 net undeveloped acres with potential for TBR production and approximately 400 miles of proprietary and nonproprietary seismic data for the region. The Company currently plans to drill two wells to test the TBR formation in 2001. 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 Knox and TBR formation drilling, the Company plans to drill approximately 4 gross (3.4 net) wells to other deep formations in 2001. 10 12 Certain typical characteristics of the less developed or deeper formations drilled by the Company in recent years are described below:
Average Drilling Costs ------------------------ Average Gross Range of Dry Completed Reserves per Formation Location Well Depths Hole Well Completed Well ------------------- -------- ----------- ---- ----- -------------- (in feet) (in thousands) (in Mmcfe) Knox formations OH, NY 2,500-8,000 $ 130 $ 260 300-600 Trenton/Black River Carbonates NY 5,000-9,000 400 750 1,000-2,000 Niagaran Carbonate MI 4,500-5,500 275 600 900-1,500 Onondaga Limestone PA 4,000-5,500 150 250 200-1,500 Oriskany Sandstone PA, NY 4,500-7,000 150 350 300-1,000
11 13 Drilling Results. The following table sets forth drilling results with respect to wells drilled during the past five years:
HIGHLY DEVELOPED OR BLANKET FORMATIONS (1) LESS DEVELOPED OR DEEPER FORMATIONS (2) ---------------------------------------------- ------------------------------------------------- 1996 1997 1998 1999 2000 1996 1997 1998 1999 2000 ---- ---- ---- ---- ---- ---- ---- ---- ---- ---- Productive: Gross 153 187 189 -- 108 34 39(3) 29(4) 9(5) 17(6) Net 126.3 156.5 167.0 -- 83.6 22.2 24.5 14.2 2.1 7.2 Dry: Gross 2 7 3 -- 3 18 28 28 9 21 Net 2.0 6.3 2.5 -- 2.6 10.2 12.3 15.5 2.7 10.7 Reserves developed- net (Bcfe) 32.7 32.8 32.3 -- 15.4 7.7 9.0 3.0 0.5 2.5 Approximate cost (in millions) $ 22.2 $ 31.2 $ 28.4 $ -- $11.5 $ 9.0 $ 9.3 $ 7.6 $0.8 $ 5.5
(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. 12 14 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. The following table sets forth information pertaining to acquisitions completed during the period 1992 through 2000. 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 will primarily focus on its drilling operations, and to a lesser extent, on the acquisition of producing properties.
Proved Developed Reserves ---------------------------------------- Number of Purchase Oil Gas Combined Period Transactions Price (1) (Mbbl) (Mmcf) (Mmcfe) -------- ------------ --------- ------ ------ -------- (in thousands) 1992 5 $ 23,733 466 41,477 44,273 1993 8 3,883 119 4,121 4,835 1994 11 20,274 223 26,877 28,215 1995 6 77,388 1,850 97,314 108,414 1996 3 4,103 205 6,000 7,230 1997 10 21,295 101 32,800 33,406 1998 3 7,640 34 8,574 8,778 1999 -- -- -- -- -- 2000 -- -- -- -- -- ------- -------- ----- ------- ------- Total 46 $158,316 2,998 217,163 235,151 ======= ======== ===== ======= =======
------------ (1) Represents the portion of the purchase price allocated to proved developed reserves. DISPOSITION OF ASSETS On March 17, 2000, the Company sold the stock of Peake. 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. EMPLOYEES As of February 28, 2001, the Company had 393 full-time employees, including 227 oil and gas exploration and production employees, 13 petroleum engineers, 7 geologists, 2 geophysicists, 114 oilfield service employees and 30 general and administrative employees. 13 15 COMPETITION AND CUSTOMERS The oil and gas industry is highly competitive. Competition is particularly intense with respect to the acquisition of producing properties and the sale of oil and gas production. There is competition among oil and gas producers as well as with other industries in supplying energy and fuel to end users. The competitors of the Company in oil and gas exploration, development 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 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 the year ended December 31, 2000 was FirstEnergy Corp., sales to which totaled $21.6 million. No customer accounted for more than 10% of consolidated revenues during the years ended December 31, 1999 and 1998. 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 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. 14 16 ITEM 2. PROPERTIES ---------- OIL AND GAS RESERVES The following table sets forth the Company's proved oil and gas reserves as of December 31, 1998, 1999 and 2000 determined in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC"). 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, --------------------------------- 1998 1999 2000 ---- ---- ---- Estimated proved reserves Gas (Bcf) 315.3 306.7 373.5 Oil (Mbbl) 4,243 6,699 8,653 Bcfe 340.7 346.9 425.4
See Note 16 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, 2000 determined in accordance with the rules and regulations of the SEC.
Estimated future net cash flows (before income taxes) (in thousands) attributable to estimated production during 2001 $ 127,601 2002 153,290 2003 162,456 2004 and thereafter 2,586,926 ---------- Total $3,030,273 ========== Present value before income taxes (discounted at 10% per annum) $1,234,949 ========== Present value after income taxes (discounted at 10% per annum) $ 820,764 ==========
Estimated future net cash flows represent estimated future gross revenues from the production and sale of proved reserves, net of estimated production costs (including production taxes, ad valorem taxes, operating costs, development costs and additional capital investment). Estimated future net cash flows were calculated on the basis of prices and costs estimated to be in effect at December 31, 2000 without escalation, except where changes in prices were fixed and readily determinable under existing contracts. 15 17 The following table sets forth the weighted average year-end prices for oil and gas utilized in determining the Company's reserves.
December 31, --------------------------- 1998 1999 2000 ---- ---- ---- Gas (per Mcf) $2.49 $ 2.61 $ 8.33 Oil (per barrel) 9.73 23.47 23.50
At December 31, 2000, 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. The average prices of natural gas used in the calculation were higher than the Company actually realized in December 2000. Further, based on market conditions in February 2001, these prices are not indicative of those that the Company expects to realize consistently in the future. If reserves had been valued using assumed constant wellhead prices of $23.50 per barrel of oil and $4.50 per Mmbtu (million British thermal units) of natural gas, total proved reserves would be 401.9 Bcfe instead of 425.4 Bcfe with a discounted future net cash flows before income taxes of $469.0 million instead of $1.2 billion. 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 and $477,000 was recorded in 2000. 16 18 PRODUCING WELL DATA As of December 31, 2000 the Company owned interests in 6,337 gross (5,272 net) producing oil and gas wells and operated approximately 5,817 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, 2000, the Company's net production was approximately 48.5 Mmcf of natural gas and 1,465 Bbls of oil per day. The following table summarizes by state the Company's productive wells at December 31, 2000:
December 31, 2000 --------------------------------------------------------------------------------- Gas Wells Oil Wells Total ------------------ ------------------- ------------------- State Gross Net Gross Net Gross Net ------------ ----- ----- ----- ----- ----- ----- Ohio 1,548 1,345 1,784 1,680 3,332 3,025 Pennsylvania 678 535 421 407 1,099 942 New York 869 840 7 7 876 847 Michigan 1,024 455 6 3 1,030 458 ----- ----- ----- ----- ----- ----- 4,119 3,175 2,218 2,097 6,337 5,272 ===== ===== ===== ===== ===== =====
ACREAGE DATA The following table summarizes by state the Company's gross and net developed and undeveloped leasehold acreage at December 31, 2000:
December 31, 2000 ------------------------------------------------------------------------------- Developed Acreage Undeveloped Acreage Total Acreage --------------------- -------------------- ----------------------- State Gross Net Gross Net Gross Net ------------ ------- ------- ------- ------- ------- ------- Ohio 320,428 289,956 218,367 174,610 538,795 464,566 Pennsylvania 45,340 36,573 167,911 152,191 213,251 188,764 New York 70,000 68,537 115,137 106,822 185,137 175,359 Michigan 16,166 15,301 37,555 34,052 53,721 49,353 ------- ------- ------- ------- ------- ------- 451,934 410,367 538,970 467,675 990,904 878,042 ======= ======= ======= ======= ======= =======
17 19 Item 3. LEGAL PROCEEDINGS ----------------- The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on the Company's financial position or the results of operations. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS --------------------------------------------------- Not applicable. PART II Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED ----------------------------------------------------- STOCKHOLDER MATTERS ------------------- There is no established public trading market for the Company's equity securities. The number of record holders of the Company's equity securities at February 28, 2001 was as follows: Number of Title of Class Record Holders ---------------------------------------- -------------------- Common Stock 16 DIVIDENDS No dividends have been paid on the Company's Common Stock. 18 20 Item 6. SELECTED FINANCIAL DATA -----------------------
PREDECESSOR COMPANY | SUCCESSOR COMPANY ---------------------------- | ---------------------------------------------------------- | AS OF OR FOR THE YEAR AS OF OR FOR THE SIX MONTHS | SIX MONTHS ENDED DECEMBER 31, YEAR ENDED ENDED | ENDED ---------------------------------------- DECEMBER 31, JUNE 30, | DECEMBER 31, (IN THOUSANDS) 1996 1997 | 1997 1998 1999 2000(1) ---------------- ---------- | ------------ --------- --------- -------- | OPERATIONS: | Revenues $153,235 $ 79,397 | $ 84,126 $ 154,839 $ 135,761 $117,851 Depreciation, depletion | and amortization 29,752 15,366 | 31,694 68,488 41,412 27,460 Impairment of oil and gas | properties and other assets -- -- | -- 160,690 -- 477 Income (loss) from continuing | operations before extraordinary | item 15,194 (9,873) | (11,372) (130,550) (18,303) 4,325 Preferred dividends paid 180 45 | -- -- -- -- | | BALANCE SHEET DATA: | AS OF | 12/31/97 | -------- Working capital 22,110 | 19,846 (6,268) (43,032) 4,180 Oil and gas properties and | gathering systems, net 222,127 | 491,183 319,013 285,081 228,937 Total assets 303,763 | 599,320 418,605 350,695 285,117 Long-term liabilities, | less current portion 97,642 | 355,649 354,382 303,731 286,858 Preferred stock 2,400 | -- -- -- -- Total shareholders' equity (deficit) 158,918 | 96,858 (33,014) (51,590) (48,313)
(1) In March 2000, the Company sold Peake (See Note 3 to the Consolidated Financial Statements). In August 2000, the Company obtained a new credit facility (See Note 7 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. 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. Due to sustained significantly lower oil and natural gas prices in 1998, the quantity and value of the Company's oil and gas reserves were negatively impacted. Given this impairment indicator, the Company computed the expected future undiscounted cash flows, employing methods consistent with those utilized to determine the estimated future net cash flows from proved reserves discussed in Note 16 to the Consolidated Financial Statements. For those assets in which the sum of the expected future undiscounted cash flows was less than the carrying amount, an impairment loss was recognized for the difference between the fair value and 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. No 19 21 impairment was recorded in 1999 and $477,000 was recorded in 2000. The impairment charge in 1998 resulted in a significant decrease in the book value of the Company's assets which resulted in significantly lower charges for depreciation, depletion and amortization in 2000 and 1999 compared to 1998. 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 gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. The Company currently operates in Ohio, Pennsylvania, New York and Michigan. The Company utilizes the "successful efforts" method of accounting for its oil and gas properties. Under this method, property acquisition and development costs and productive exploration costs are capitalized while non-productive exploration costs, which include dry holes, expired leases and delay rentals, are expensed as incurred. Capitalized costs related to proved properties are depleted using the unit-of-production method. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized. The Company provides oilfield 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. 20 22 RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------------ 2000 1999 1998 ----------------------- -------------------- --------------------- (in thousands) REVENUES Oil and gas sales $ 79,743 67.7% $ 79,299 58.4% $ 87,055 56.2% Gas gathering, marketing, and oilfield sales and service 34,850 29.6 51,445 37.9 63,348 40.9 Other 3,258 2.7 5,017 3.7 4,436 2.9 ----------------------- -------------------- --------------------- 117,851 100.0 135,761 100.0 154,839 100.0 EXPENSES Production expense 20,917 17.7 21,980 16.2 23,739 15.3 Production taxes 2,409 2.0 3,260 2.4 2,986 1.9 Gas gathering, marketing, and oilfield sales and service 31,703 26.9 46,977 34.6 56,813 36.7 Exploration expense 8,528 7.3 6,442 4.7 9,982 6.5 General and administrative expense 4,617 3.9 5,412 4.0 4,536 2.9 Depreciation, depletion and amortization 27,460 23.3 41,412 30.5 68,488 44.2 Impairment of oil and gas properties and other assets 477 0.4 -- -- 160,690 103.8 Franchise, property and other taxes 397 0.3 652 0.5 1,084 0.7 Other nonrecurring expense 241 0.3 3,285 2.4 373 0.3 ----------------------- -------------------- --------------------- 96,749 82.1 129,420 95.3 328,691 212.3 ----------------------- -------------------- --------------------- OPERATING INCOME (LOSS) 21,102 17.9 6,341 4.7 (173,852) (112.3) (Gain) loss on sale of subsidiaries and other income (15,064) (12.8) 1,521 1.1 -- -- Interest expense 29,473 25.0 34,302 25.3 32,903 21.2 ----------------------- -------------------- --------------------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM 6,693 5.7 (29,482) (21.7) (206,755) (133.5) Provision (benefit) for income taxes 2,368 2.0 (11,179) (8.2) (76,205) (49.2) ----------------------- -------------------- --------------------- INCOME (LOSS) BEFORE EXTRAORDINARY ITEM 4,325 3.7 (18,303) (13.5) (130,550) (84.3) Extraordinary item - early extinguishment of debt, net of tax benefit (1,364) (1.2) -- -- -- -- ----------------------- -------------------- --------------------- NET INCOME (LOSS) $ 2,961 2.5% $ (18,303) (13.5)% $(130,550) (84.3)% ======================= ==================== ===================== EBITDAX $ 57,808 49.1% $ 57,480 42.3% $ 65,681 42.4%
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 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 21 23 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. Earnings before interest, income taxes, depreciation, depletion and amortization, impairment, exploration expense and other nonrecurring items ("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 volume 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 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 of approximately $2.0 million. Gas volumes decreased 7.0 Bcf (26%) from 27.0 Bcf in 1999 to 20.0 Bcf in 2000 resulting in a decrease in gas sales 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 by approximately $6.4 million. The average price paid for the Company's natural gas increased $.67 per Mcf to $3.17 per Mcf in 2000 compared to 1999 which increased gas sales in 2000 by approximately $13.4 million. As a result of the Company's hedging activities, gas sales were reduced by $9.3 million ($.47 per Mcf) in 2000 and were enhanced by $1.0 million ($.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 related expenses. The average production cost increased from $.70 per Mcfe in 1999 to $.89 per Mcf in 2000 primarily due to decreased production volumes 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 primarily due to the sale of Peake. Average production taxes were $.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. 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. 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. 22 24 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 $.92 per Mcfe in 1999 to $.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. 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. 1999 COMPARED TO 1998 Operating income increased $180.2 million from an operating loss of $173.9 million in 1998 to operating income of $6.3 million in 1999. This increase was the result of the $160.7 million asset impairment in 1998, a $27.1 million decrease in depreciation, depletion and amortization expense and a $3.6 million decrease in exploration expense. These changes were partially offset by a $2.9 million increase in other nonrecurring expense and a $8.3 million decrease in the Company's operating margin primarily due to decreases in natural gas prices and the volume of oil and natural gas sold offset by an increase in the average price paid for the Company's oil. The volume decrease was due to the natural production decline of the wells and curtailment of drilling due to capital constraints caused by the reduction in the Company's borrowing base. The operating margin from oil and gas sales on a per unit basis was $1.74 per Mcfe in 1998 and 1999. Net loss decreased $112.3 million from a loss of $130.6 million in 1998 to a loss of $18.3 million in 1999. This decrease was the result of the changes in operating income discussed above and a $1.3 million gain on the sale of BESCO in November 1999 partially offset by a decrease in the income tax benefit of $65.0 million primarily due to the decrease in loss before income taxes, a $2.8 million loss on the sale of TOPS in August 1999 and a $1.4 million increase in interest expense. EBITDAX decreased $8.2 million (12%) from $65.7 million in 1998 to $57.5 million in 1999. This was primarily due to the $8.3 million decrease in the Company's operating margin discussed above. Total revenues decreased $19.1 million (12%) in 1999 compared to 1998 due to the sale of TOPS and decreases in natural gas prices and the volume of oil and natural gas sold offset by an increase the average price paid for the Company's oil. Oil volumes decreased approximately 55,000 Bbls (7%) from 768,000 Bbls in 1998 to 713,000 Bbls in 1999 resulting in a decrease in oil sales of approximately $697,000. Gas volumes decreased 3.1 Bcf (10%) from 30.1 Bcf in 1998 to 27.0 Bcf in 1999 resulting in a decrease in gas sales of 23 25 approximately $8.1 million. These volume decreases were primarily due to the natural production decline of the wells and curtailment of drilling due to capital constraints caused by the reduction in the Company's borrowing base. The average price paid for the Company's oil increased from $12.61 per barrel in 1998 to $16.57 per barrel in 1999 which increased oil sales by approximately $2.8 million. The average price paid for the Company's natural gas decreased $.07 per Mcf to $2.50 per Mcf in 1999 compared to 1998 which decreased gas sales in 1999 by approximately $1.9 million. As a result of the Company's hedging activities, gas sales were enhanced by $1.0 million ($.04 per Mcf) and $1.3 million ($.04 per Mcf) in 1999 and 1998, respectively. Production expense decreased $1.7 million (7%) from $23.7 million in 1998 to $22.0 million in 1999. The average production cost increased from $.68 per Mcfe in 1998 to $.70 per Mcf in 1999 primarily due to decreased volumes. Production taxes increased approximately $274,000 in 1999 compared to 1998. Average production taxes increased from $.09 per Mcfe in 1998 to $.10 per Mcfe in 1999. General and administrative expense increased approximately $876,000 in 1999 compared to 1998. This increase was the result of increased compensation and bonus, costs associated with executive transitions and Y2K related costs. Exploration expense decreased by $3.6 million (35%) from $10.0 million in 1998 to $6.4 million in 1999 as a result of the curtailment of the Company's drilling program previously discussed. Other nonrecurring expense increased from $373,000 in 1998 to $3.3 million in 1999 due to $2.4 million in employee reduction costs and an increase of $507,000 in costs associated with an abandoned acquisition effort and an abandoned public offering of a royalty trust in 1999. Depreciation, depletion and amortization decreased by $27.1 million (40%) from $68.5 million in 1998 to $41.4 million in 1999. Depletion expense decreased $28.8 million (50%) from $57.7 million in 1998 to $28.9 million in 1999. Depletion per Mcfe decreased from $1.66 per Mcfe in 1998 to $.92 per Mcfe in 1999. These decreases were primarily the result of the $160.7 million write-down of certain permanently impaired assets in the fourth quarter of 1998. Interest expense increased $1.4 million (4%) from $32.9 million in 1998 to $34.3 million in 1999. This increase was due to an increase in average outstanding borrowings and higher blended interest rates. The Company incurred $972,000 and $499,000 in additional interest expense during 1999 and 1998, respectively, related to interest rate swaps. (Gain) loss on sale of subsidiaries and other income in 1999 includes a $2.8 million loss on the sale of TOPS offset by a $1.3 million gain on the sale of BESCO. 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, 2000 was 1.16 to 1. During 2000, working capital increased $47.2 million from a deficit of $43.0 million to working capital of $4.2 million. The increase 24 26 was primarily due to a decrease in current portion of long-term liabilities of $50.8 million. The Company's operating activities provided cash flows of $28.5 million during 2000. On December 14, 1999, the Company and its bank group amended its senior revolving credit agreement. The revolving credit commitment in the amended agreement provided for a $75 million revolving portion and a $50 million term portion. 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 and its bank group further amended the credit agreement to provide a borrowing base of $62.7 million and to forego the May 2000 borrowing base redetermination. On August 23, 2000, the Company obtained a $125 million Facility comprised of a $100 million Revolver and a $25 million Term Loan. The Facility has a two year term. 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 Notes. 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 due to the modification of borrowing capacity. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At December 31, 2000, the interest rate was 11.5%. Up to $20 million in letters of credit may be issued pursuant to the conditions of the Revolver. At December 31, 2000, the Company had $12.8 million of outstanding letters of credit. Initial proceeds from the Revolver of approximately $66 million 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) representing the unamortized deferred loan costs pertaining to the former credit facility. The charge was recorded as an extraordinary item. As of December 31, 2000, the outstanding balance under the Revolver was $61.4 million with $25.8 million of borrowing capacity available for general corporate purposes. The Facility 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, 2000, under this formula was approximately $265 million for all proved reserves of the Company and $211 million for properties secured by a mortgage. The Facility is subject to certain financial covenants. These include a senior debt interest coverage ratio ranging from 5.8 to 1 at December 31, 2000, to 3.2 to 1 at June 30, 2002; and a senior debt leverage ratio ranging from 2.4 to 1 at December 31, 2000 to 3.2 to 1 at June 30, 2002. EBITDA, as defined in the Facility, 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) 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 25 27 December 31, 2000, the Company's current ratio including the above adjustments was 2.34 to 1. The Company has satisfied all financial covenants as of December 31, 2000. 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 below, the notes are not redeemable prior to June 15, 2002. Thereafter, the notes are subject to redemption at the option of the Company at specific redemption prices. Prior to June 15, 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. The Company currently expects to spend approximately $39 million during 2001 on its drilling activities and other capital expenditures. The Company intends to finance its planned capital expenditures through its available cash flow, available revolving credit line and the sale of non strategic assets. At February 28, 2001, the Company had approximately $37 million available under its existing revolving credit line. The level of the Company's cash flow in the future 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. 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. With the May 10, 1999 amendment to the credit agreement, the applicable margin relating to these swaps was increased from 1.5% to 2.5%. Effective with the December 14, 1999 amendment to the credit agreement, the applicable margin relating to these swaps was increased from 2.5% to a range up to 3.5%. 26 28 To manage its exposure to natural gas price volatility, the Company may partially hedge its physical gas 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 or options. The Company had a pretax loss on its hedging activities of $9.3 million in 2000 and pretax gains of $1.0 million and $1.3 million in 1999 and 1998, respectively. As of December 31, 2000, the Company had hedged 4.35 Bcf of 2001 natural gas production at a weighted average NYMEX price of $4.50 per Mcf which represented a net unrealized loss of $10.5 million. This amount includes an unrealized loss of $1.2 million associated with terminated financial swaps on 750 Mmcf of second quarter of 2001 natural gas. The following table reflects the natural gas volumes and the weighted average prices under financial hedges and fixed price contracts (including settled hedges) at December 31, 2000:
FINANCIAL HEDGES FIXED PRICE CONTRACTS ----------------------------------- ---------------------- ESTIMATED ESTIMATED NYMEX WELLHEAD WELLHEAD QUARTER ENDING MMCF PRICE PRICE MMCF PRICE -------------------- ----- ----- --------- ----- --------- March 31, 2001 1,250 $4.75 $5.00 2,100 $3.78 June 30, 2001 1,050 4.40 4.55 1,300 3.53 September 30, 2001 1,050 4.40 4.55 1,050 3.57 December 31, 2001 1,000 4.43 4.63 450 3.22
The quarter ending June 30, 2001 in the above table does not include an unrealized loss of $1.2 million associated with terminated financial swaps on 750 Mmcf of natural gas. Since December 31, 2000, the Company has financially hedged 3.0 Bcf of 2002 gas production at a NYMEX price of $4.75 per Mcf. As of February 28, 2001, the Company had hedges totaling 6.6 Bcf of 2001 and 2002 natural gas production which represented a net unrealized loss of $4.4 million. As of January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. (SFAS) 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. As a result of the adoption of SFAS 133, the Company will recognize 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). 27 29 The adoption of SFAS 133 will result in a January 1, 2001 transition adjustment to increase other current liabilities by $10.5 million, increase 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 will be reflected as a transition adjustment in other comprehensive income (loss) as of January 1, 2001. 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. INFLATION AND CHANGES IN PRICES During 1998, the price paid for the Company's crude oil increased to a high of $14.50 per barrel in January, then decreased to a low of $8.50 per barrel in December and increased to $9.25 per barrel at year-end 1998, with an average price of $12.61 per barrel. 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. The average price of the Company's natural gas decreased from $2.57 per Mcf in 1998 to $2.50 per Mcf in 1999, then increased to $3.17 per Mcf in 2000. 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. As a result of increased competition among drilling contractors and suppliers in the Company's operating area, costs to drill, complete and service wells have remained relatively constant in recent years. The Company's costs and expenses may be subject to inflationary pressures if oil and gas prices remain favorable. Historically, a large portion of the Company's natural gas has 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. 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. 28 30 Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ---------------------------------------------------------- The Company is exposed to interest rate and commodity price risks. The interest rate risk relates to existing debt under the Company's revolving credit facility as well as any new debt financing needed to fund capital requirements. The Company 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, 2000. At December 31, 1999 and 1998 the principal amount of the swaps totaled $120 million and $140 million, respectively. If market interest rates for short-term borrowings increased 1%, the increase in the Company's interest expense would be approximately $615,000. This sensitivity analysis is based on the Company's financial structure at December 31, 2000. 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 increased $.25 per Mcf, the Company's gas sales would increase by $2.5 million, after considering the effects of the hedging contracts in place at December 31, 2000. This sensitivity analysis is based on the Company's 2000 gas sales volumes. The information included in this Item is considered to constitute "forward looking statements" for purposes of the statutory safe harbor provided in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Forward-Looking Information" in Item 7 of this Report. Item 8. 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. 29 31 The Company maintains accounting and other controls which management believes provide reasonable assurance that financial records are reliable, assets are safeguarded, and that transactions are properly recorded. However, limitations exist in any system of internal control based upon the recognition that the cost of the system should not exceed benefits derived. The Company's independent auditors, Ernst & Young LLP, are engaged to audit the financial statements and to express an opinion thereon. Their audit is conducted in accordance with 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. Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ------------------------------------------------ ACCOUNTING AND FINANCIAL DISCLOSURE ----------------------------------- Not applicable. 30 32 PART III -------- Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT -------------------------------------------------- Executive officers and directors of the Company as of March 5, 2001 were as follows:
Name Age Position ---- --- -------- John L. Schwager 52 President, Chief Executive Officer and Director Joseph M. Vitale 59 Senior Vice President Legal, General Counsel, Secretary and Director Richard R. Hoffman 50 Senior Vice President Exploration and Production Leo A. Schrider 62 Senior Vice President Technical Development Robert W. Peshek 46 Vice President Finance and Chief Financial Officer David M. Becker 39 Vice President and General Manager, Michigan Exploration and Production District Carl J. Carlson 47 Vice President and General Manager, Pennsylvania/New York Exploration and Production District Duane D. Clark 45 Vice President Gas Marketing John G. Corp 41 Vice President and General Manager, Arrow Oilfield Service Company James C. Ewing 58 Vice President Human Resources Charles P. Faber 59 Vice President Corporate Development William F. Murray 39 Vice President and General Manager, Ohio Exploration and Production District Henry S. Belden IV 61 Director Lawrence W. Kellner 42 Director Max L. Mardick 66 Director Robert S. Maust 63 Director William S. Price, III 45 Director Gareth Roberts 48 Director Jeffrey C. Smith 39 Director
31 33 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 nine members each of whom is elected annually to serve one year terms. The business experience of each executive officer and director is summarized below. 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, 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. JOSEPH M. VITALE has been Senior Vice President Legal of the Company since 1989 and has served as its General Counsel since 1974. He has been a director of the Company since 1991. He holds a BS degree from John Carroll University and a JD degree from Case Western Reserve Law School. He is a member of the Ohio Oil and Gas Association, the Stark County, Ohio State and American Bar Associations, and the Interstate Oil and Gas Compact Commission. Mr. Vitale is a past Chairman of the Natural Resources Law Committee of the Ohio State Bar Association. 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 28 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 it's 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 Tennessee Oil and 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. 32 34 LEO A. SCHRIDER has been Senior Vice President of Technical Development since 1993. He previously served as Senior Vice President of Exploration, Drilling and Engineering for the Company since 1986. Mr. Schrider is a Petroleum Engineer with more than 35 years of experience in oil and gas production, principally in the Appalachian Basin. Prior to joining the Company in 1981, he served as Assistant and Deputy Director of Morgantown Energy Technology Center from 1976 to 1980. From 1973 to 1976, Mr. Schrider served as Project Manager of the Laramie Energy Research Center. He has also held various research positions with the U.S. Department of Energy in Wyoming and West Virginia. Mr. Schrider received his BS degree from the University of Pittsburgh in 1961 and did graduate work at West Virginia University. He has published more than 35 technical papers on oil and gas production. He was an Adjunct Professor at West Virginia University and also served as a member of the International Board of Directors of the Society of Petroleum Engineers. In 1994, Mr. Schrider was elected to the Board of Directors of the Petroleum Technology Transfer Council and currently serves as its chairman. 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 19 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. CARL J. CARLSON was appointed Vice President of the Company in May 2000, and has been General Manager of the Pennsylvania/New York Exploration and Production District of the Company since 1995. Mr. Carlson joined the Company as a result of the Quaker State acquisition in May of 1995. He was employed by Quaker State Corporation from 1976 to 1995, serving most recently as President of the Natural Gas E&P Division. He has 25 years of experience in the oil and gas industry. Mr. Carlson graduated from Pennsylvania State University where he received a Bachelor of Science degree in Geological Science. DUANE D. CLARK has been Vice President of Gas Marketing for the Company since 1997. Previously, he served as General Manager of Gas Marketing from 1996 to 1997. He joined the Company in 1995 as a Gas Marketing Analyst. Prior to joining 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 33 35 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 Services 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 22 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. JAMES C. EWING has been Vice President of Human Resources for the Company since 1997. He previously served as Human Resources Manager. Mr. Ewing joined the Company in April of 1986 and has 15 years of experience in the oil and gas industry and more than 20 years of experience in the Human Resource field. Prior to joining the Company, he was the Director of Personnel for the Union Metal Manufacturing Company from 1978 to 1986. Mr. Ewing holds a Bachelor of Arts degree in Psychology from West Liberty State College. He is a member of the Society for Human Resource Management. He is a founder and current member of the Stark County Health Care Coalition; President of the Stark County Historical Society; and, Chairman of the Business Advisory Board and adjunct faculty member of Kent State University. CHARLES P. FABER has been Vice President of Corporate Development for the Company since 1993. He previously served as Senior Vice President of Capital Markets from 1988 to 1993. Prior to joining the Company, Mr. Faber was employed as Senior Vice President of Marketing for Heritage Asset Management from 1986 to 1988. From 1983 to 1986 he served as President and Chief Executive Officer of Samson Properties, Incorporated. Mr. Faber holds a BA degree in Marketing and an MBA in Finance from the University of Wisconsin where he graduated with honors. He is a member of the Independent Petroleum Association of America and the Ohio Oil and Gas Association. 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 18 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. HENRY S. BELDEN IV served as Chairman and Chief Executive Officer of the Company from 1982 to 1997. He resigned as Chairman and Chief Executive Officer upon the merger with TPG in 1997, and was appointed to serve on the Board of Directors upon consummation of the merger. Mr. Belden has been involved in oil and gas production since 1955 and associated with the Company since 1967. Prior to joining the Company, he was employed by Ashland Oil & Refining Company and Halliburton Services, Incorporated. Mr. Belden attended Florida State University and the University of Akron and is a current member and previous board member of the Ohio Oil and Gas Association and the Independent Petroleum 34 36 Association of America. He is also a member of the Interstate Oil Compact Commission. Other professional memberships include the World Business Council and the World Presidents Organization. Mr. Belden is a director of Phoenix Packaging Corporation and Family Office Services, LLC. LAWRENCE W. KELLNER has been a director since 1997. He has been Executive Vice President and Chief Financial Officer of Continental Airlines, Inc. since November 1996. Previously, he served as Senior Vice President and Chief Financial Officer at Continental from June 1995 to November 1996. Mr. Kellner graduated magna cum laude with a Bachelor of Science, Business Administration degree from the University of South Carolina. 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 38-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. MAX L. MARDICK was President and Chief Operating Officer of the Company from 1990 to 1997, a director from 1992 to 1997 and a director of predecessor companies from 1988 to 1992. He resigned as President and Chief Operating Officer upon consummation of the merger with TPG in 1997 and was appointed to serve on the Board of Directors upon consummation of the merger. He previously served as Executive Vice President and Chief Operating Officer from 1988 to 1990. Mr. Mardick is a Petroleum Engineer with more than 35 years of experience in domestic and international production, engineering, drilling operations and property evaluation. Prior to joining the Company, he was employed for more than 30 years by Shell Oil Company in various engineering, supervisory and senior management positions, including: Manager, Property Acquisitions and Business Development (1986-1988); Production Manager for Shell's Onshore and Eastern Divisions (1981-1986); Production Manager of Shell's Rocky Mountain Division (1980-1981); Operations Manager (1977-1980); and Engineering Manager (1975-1977). Mr. Mardick holds a BS degree in Petroleum Engineering from the University of Kansas. He has served as Vice Chairman of the Alabama-Mississippi section of the Mid-Continent Oil and Gas Association. WILLIAM S. PRICE, III, who became a director upon consummation of the merger with TPG in 1997, was a founding partner of Texas Pacific Group in 1993. Prior to forming Texas Pacific Group, Mr. Price was Vice President of Strategic Planning and Business Development for G.E. Capital, and from 1985 to 1991 he was employed by the management consulting firm of Bain & Company, attaining partnership status and acting as co-head of the Financial Services Practice. Mr. Price is a 1978 graduate of Stanford University and received a JD degree from the Boalt Hall School of Law at the University of California, Berkeley. Mr. Price serves on the Boards of Directors of Continental Airlines, Inc., Del Monte, Inc., 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 25 years of experience in the exploration 35 37 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. 36 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, 2000, 1999 and 1998 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 ------------------------------------------------ ------------- Other No. of Shares Name and Annual Underlying All Other Principal Position Year Salary Bonus Compensation Options/SARs Compensation(1) ------------------ ---- ------ ----- ------------ ------------ --------------- John L. Schwager 2000 $308,654 $157,500 $ -- 66,692 $ 8,500 President and Chief 1999 173,077 300,000 -- 139,383 113,358 (2) Executive Officer Joseph M. Vitale 2000 185,192 47,250 -- 27,500 8,500 Senior Vice President Legal, 1999 180,000 57,416 -- 55,000 (3) 8,084 General Counsel and Secretary 1998 186,493 52,525 -- -- 14,248 Tommy L. Knowles (7) 2000 185,300 49,039 337 (6) 27,500 8,500 Senior Vice President of 1999 172,009 17,201 -- 55,000 (3) 7,878 Exploration and Production 1998 175,158 6,244 -- -- 14,444 Leo A. Schrider 2000 142,777 36,487 1,370 (6) 27,500 7,804 Senior Vice President of 1999 133,000 13,300 -- 55,000 (4) 7,635 Technical Development 1998 137,962 12,719 -- -- 11,669 Robert W. Peshek 2000 144,721 40,851 -- 27,500 8,500 Vice President of Finance 1999 110,617 13,000 -- 55,000 (5) 5,531 and Chief Financial Officer 1998 102,708 7,320 -- -- 5,818
-------------------- (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 options for 54,946 shares originally granted in 1997 and repriced in 1999 plus options for 54 shares granted in 1999. (4) Includes options for 20,000 shares originally granted in 1997 and repriced in 1999 plus options for 35,000 shares granted in 1999. (5) Includes options for 25,000 shares originally granted in 1997 and repriced in 1999 plus 30,000 shares granted in 1999. (6) Includes amounts related to taxes from a prior year paid by the Company on the behalf of the named executive. (7) Employment with the Company terminated effective March 4, 2001. 37 39 OPTION/SAR GRANTS IN LAST FISCAL YEAR
Number of Percentage/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 69,692 25.37% $ 0.21 03/21/10 $ 4,668 Joseph M. Vitale 27,500 10.01% 0.21 03/21/10 1,925 Tommy L. Knowles 27,500 10.01% 0.21 03/21/10 1,925 Leo A. Schrider 27,500 10.01% 0.21 03/21/10 1,925 Robert W. Peshek 27,500 10.01% 0.21 03/21/10 1,925
(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. AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION/SAR VALUE
Value of Unexercised Number of Unexercised In-the Money Options/SARs at FY-End Options/SARs at FY-End ---------------------- ---------------------- Shares Acquired Value Name on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable ---- ----------- -------- ----------- ------------- ----------- ------------- John L. Schwager 52,267 $ 23,520 -- 156,808 $ -- 390,626 Joseph M. Vitale 13,750 22,138 -- 68,750 -- 171,875 Tommy L. Knowles -- -- 13,750 68,750 35,475 171,875 Leo A. Schrider -- -- 13,750 68,750 35,475 171,875 Robert W. Peshek 13,750 22,138 -- 68,750 -- 171,875
COMPENSATION OF DIRECTORS The outside directors of the Company are compensated for their services at $7,500 per quarter. Directors employed by the Company or affiliated with TPG are not compensated for their services. Two directors had additional compensation of $3,603 and $12,495, respectively, in 2000 related to taxes from a prior year paid by the Company on their behalf. EMPLOYMENT AND SEVERANCE AGREEMENTS John L. Schwager entered into an Employment Agreement effective as of June 1, 1999 providing for his employment as Chief Executive Officer of the Company at an annual base salary of not less than $300,000, and entitling him to an annual bonus of up to 100% of his annual base salary subject to the attainment of certain goals to be agreed upon annually by Mr. Schwager and the Board of Directors. The 38 40 Company agreed to reimburse Mr. Schwager for expenses incurred in connection with his relocation to Canton, Ohio, including any loss on the sale of his former residence. If his employment is terminated by the Company without "cause" (as defined in the agreement) or if Mr. Schwager resigns in response to a substantial and adverse change in his status or position or a substantial reduction in duties, responsibilities or base salary or a relocation of his place of work or a sale of the Company, Mr. Schwager will be entitled to severance pay equal to three times his total compensation for the previous calendar year, or if such termination occurs in 2000, three times his total annualized 1999 compensation. Mr. Schwager would also be entitled to receive an additional payment (the "gross up") sufficient to cover any tax imposed by Section 4999 of the Internal Revenue Code on the severance payments and the gross up. In addition, Mr. Schwager received options to purchase 139,383 shares of common stock of the Company at a price of $0.01 per share, subject to upward adjustment in the event of the sale by the Company of new equity securities to TPG Partners II or its affiliates for at least $30 million, in which case he will receive additional options for such number of shares as will, when added to 139,383, equal 1.25% of the Company's outstanding stock. In such event, the exercise price of all options shall be equal to the fair market value of the underlying shares. 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 six (6) months to twenty-four (24) months, depending on their years of service and position with the Company. Under the Plan, Messrs. Schrider, Peshek and Vitale would be eligible to receive severance pay ranging from twelve (12) months to twenty-four (24) months, and Mr. Knowles will receive twenty-four (24) months of severance pay in connection with the termination of his employment. The Company has a 1999 Change in Control Protection Plan for Key Employees providing severance benefits for such employees if within six (6) months prior to a change in control or within two (2) 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. Such benefits range from twelve (12) months to thirty-six (36) months, depending on their position with the Company. Under the Plan, Messrs. Schrider, Peshek and Vitale would be eligible to receive severance pay ranging from twenty-four (24) to thirty-six (36) months. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION During 2000, the Compensation and Organizational Committee of the Board of Directors consisted of William S. Price, III, Henry S. Belden IV and Gareth Roberts, all of whom are outside directors. No executive officer of the Company was a director or member of the compensation committee of any entity of which a member of the Company's Board of Directors or its Compensation and Organizational Committee was or is an executive officer. 39 41 Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND --------------------------------------------------- MANAGEMENT ---------- The following table sets forth certain information as of February 28, 2001 regarding the beneficial ownership of the Company's common stock by each person who beneficially owns more than five percent of the Company's outstanding common stock, each director, the chief executive officer and the four other most highly compensated executive officers and by all directors and executive officers of the Company, as a group:
FIVE PERCENT SHAREHOLDERS NUMBER OF SHARES PERCENTAGE OF SHARES ------------------------- ---------------- -------------------- TPG Advisors II, Inc. 201 Main Street, Suite 2420 Fort Worth, Texas 76102 9,353,038 (1) 89.4% State Treasurer of the State of Michigan, Custodian of the Public School Employees' Retirement System, State Employees Retirement System, Michigan State Police Retirement System and Michigan Judges Retirement System 554,376 5.3% OFFICERS AND DIRECTORS ---------------------- William S. Price, III 9,353,038 (1) 89.4% Henry S. Belden IV 63,360 (2) * John L. Schwager 78,401 (2) * Lawrence W. Kellner -0- -0- Max L. Mardick 39,387 (2) * Gareth Roberts -0- -0- Robert S. Maust -0- -0- Jeffrey C. Smith -0- -0- Joseph M. Vitale 27,500 (2) * Tommy L. Knowles (3) 17,188 (2) * Leo A. Schrider 27,500 (2) * Robert W. Peshek 27,500 (2) * All directors and executive officers (19) as a group 9,706,374 92.8%
* 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 II, TPG Investors II, L.P. and TPG Parallel II, L.P. which are the direct beneficial owners of 7,976,645, 832,047 and 544,346 shares of common stock, respectively. (2) Consists of shares subject to stock options exercisable within 60 days by Mr. Schwager as to 26,134 shares, Mr. Vitale as to 13,750 shares, Mr. Peshek as to 13,750 shares and as to all shares for Messrs. Belden, Mardick, Knowles and Schrider. (3) Employment with the Company terminated effective March 4, 2001. 40 42 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. 41 43 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) 42 44 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. 10.2 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. 21* Subsidiaries of the Registrant 23* Consent of independent auditors * Filed herewith 43 45 (b) Reports on Form 8-K No reports on Form 8-K were filed by the Company during the last quarter of the year covered by this report. (c) Exhibits required by Item 601 of Regulation S-K Exhibits required to be filed by the Company pursuant to Item 601 of Regulation S-K are contained in the Exhibits listed under Item 14(a)3. (d) Financial Statement Schedules required by Regulation S-X The items listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K. 44 46 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, 2001 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, 2001 --------------------------------- and Chief Executive Officer -------------- John L. Schwager (Principal Executive Officer) Date /s/ Robert W. Peshek Vice President Finance and March 21, 2001 --------------------------------- Chief Financial Officer -------------- Robert W. Peshek (Principal Financial and Date Accounting Officer) /s/ Joseph M. Vitale Senior Vice President Legal, March 21, 2001 --------------------------------- General Counsel, Secretary -------------- Joseph M. Vitale and Director Date /s/ Henry S. Belden IV Director March 21, 2001 --------------------------------- -------------- Henry S. Belden IV Date /s/ Lawrence W. Kellner Director March 21, 2001 --------------------------------- -------------- Lawrence W. Kellner Date /s/ Max L. Mardick Director March 21, 2001 --------------------------------- -------------- Max L. Mardick Date
45 47 /s/ Robert S. Maust Director March 21, 2001 --------------------------------- -------------- Robert S. Maust Date /s/ William S. Price, III Director March 21, 2001 --------------------------------- -------------- William S. Price, III Date /s/ Gareth Roberts Director March 21, 2001 --------------------------------- -------------- Gareth Roberts Date /s/ Jeffrey C. Smith Director March 21, 2001 --------------------------------- -------------- Jeffrey C. Smith Date
46 48 BELDEN & BLAKE CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES ITEM 14(a)(1) AND (2)
PAGE ---- CONSOLIDATED FINANCIAL STATEMENTS --------------------------------- Report of Independent Auditors..................................................... F-2 Consolidated Balance Sheets as of December 31, 2000 and 1999....................... F-3 Consolidated Statements of Operations: Years ended December 31, 2000, 1999 and 1998.................................... F-4 Consolidated Statements of Shareholders' Equity (Deficit): Years ended December 31, 2000, 1999 and 1998.................................... F-5 Consolidated Statements of Cash Flows: Years ended December 31, 2000, 1999 and 1998.................................... 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 49 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, 2000 and 1999, 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, 2000. 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, 2000 and 1999 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States. ERNST & YOUNG LLP Cleveland, Ohio March 9, 2001 F-2 50 BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31, ----------------------------- 2000 1999 --------- --------- ASSETS ------ CURRENT ASSETS Cash and cash equivalents $ 1,798 $ 4,536 Accounts receivable, net 22,620 25,301 Inventories 2,222 2,106 Deferred income taxes 1,475 2,006 Other current assets 1,448 1,154 --------- --------- TOTAL CURRENT ASSETS 29,563 35,103 PROPERTY AND EQUIPMENT, AT COST Oil and gas properties (successful efforts method) 413,824 534,515 Gas gathering systems 13,445 22,193 Land, buildings, machinery and equipment 23,469 24,242 --------- --------- 450,738 580,950 Less accumulated depreciation, depletion and amortization 208,435 280,047 --------- --------- PROPERTY AND EQUIPMENT, NET 242,303 300,903 OTHER ASSETS 13,251 14,689 --------- --------- $ 285,117 $ 350,695 ========= ========= LIABILITIES AND SHAREHOLDERS' DEFICIT ------------------------------------- CURRENT LIABILITIES Accounts payable $ 5,926 $ 4,132 Accrued expenses 19,316 23,024 Current portion of long-term liabilities 141 50,979 --------- --------- TOTAL CURRENT LIABILITIES 25,383 78,135 LONG-TERM LIABILITIES Bank and other long-term debt 61,535 78,161 Senior subordinated notes 225,000 225,000 Other 323 570 --------- --------- 286,858 303,731 DEFERRED INCOME TAXES 21,189 20,419 SHAREHOLDERS' DEFICIT Common stock without par value; $.10 stated value per share; authorized 58,000,000 shares; issued 10,357,255 (which includes 53,972 treasury shares) and 10,260,457 shares 1,030 1,026 Paid in capital 107,921 107,609 Deficit (157,264) (160,225) --------- --------- TOTAL SHAREHOLDERS' DEFICIT (48,313) (51,590) --------- --------- $ 285,117 $ 350,695 ========= =========
See accompanying notes. F-3 51 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ------------------------------------------------- 2000 1999 1998 --------- --------- --------- REVENUES Oil and gas sales $ 79,743 $ 79,299 $ 87,055 Gas gathering, marketing, and oilfield sales and service 34,850 51,445 63,348 Other 3,258 5,017 4,436 --------- --------- --------- 117,851 135,761 154,839 EXPENSES Production expense 20,917 21,980 23,739 Production taxes 2,409 3,260 2,986 Gas gathering, marketing, and oilfield sales and service 31,703 46,977 56,813 Exploration expense 8,528 6,442 9,982 General and administrative expense 4,617 5,412 4,536 Depreciation, depletion and amortization 27,460 41,412 68,488 Impairment of oil and gas properties and other assets 477 -- 160,690 Franchise, property and other taxes 397 652 1,084 Other nonrecurring expense 241 3,285 373 --------- --------- --------- 96,749 129,420 328,691 --------- --------- --------- OPERATING INCOME (LOSS) 21,102 6,341 (173,852) (Gain) loss on sale of subsidiaries and other income (15,064) 1,521 -- Interest expense 29,473 34,302 32,903 --------- --------- --------- 14,409 35,823 32,903 --------- --------- --------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM 6,693 (29,482) (206,755) Provision (benefit) for income taxes 2,368 (11,179) (76,205) --------- --------- --------- INCOME (LOSS) BEFORE EXTRAORDINARY ITEM 4,325 (18,303) (130,550) Extraordinary item - early extinguishment of debt, net of tax benefit (1,364) -- -- --------- --------- --------- NET INCOME (LOSS) $ 2,961 $ (18,303) $(130,550) ========= ========= =========
See accompanying notes. F-4 52 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT) (IN THOUSANDS)
TOTAL COMMON COMMON PAID IN EQUITY SHARES STOCK CAPITAL DEFICIT (DEFICIT) ------ --------- --------- --------- --------- JANUARY 1, 1998 10,000 $ 1,000 $ 107,230 $ (11,372) $ 96,858 Stock-based compensation 111 11 667 678 Net loss (130,550) (130,550) ------------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1998 10,111 1,011 107,897 (141,922) (33,014) Stock-based compensation 118 12 (288) (276) Stock options exercised 31 3 3 Net loss (18,303) (18,303) ------------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 1999 10,260 1,026 107,609 (160,225) (51,590) Stock options exercised 97 10 (9) 1 Stock-based compensation 336 336 Treasury stock (54) (6) (15) (21) Net income 2,961 2,961 ------------------------------------------------------------------------------------------------------------------------- DECEMBER 31, 2000 10,303 $ 1,030 $ 107,921 $(157,264) $(48,313) =========================================================================================================================
See accompanying notes. F-5 53 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ------------------------------------------------- 2000 1999 1998 --------- -------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss) $ 2,961 $(18,303) $(130,550) 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 27,460 41,412 68,488 Impairment of oil and gas properties and other assets 477 -- 160,690 (Gain) loss on sale of subsidiaries (13,794) 1,521 -- Loss on disposal of property and equipment 500 136 100 Exploration expense 8,528 6,442 9,982 Deferred income taxes 2,077 (11,179) (75,702) Deferred compensation and stock grants 169 (565) 993 Change in operating assets and liabilities, net of effects of purchases of businesses and disposition of subsidiaries: Accounts receivable and other operating assets (442) 8,580 3,218 Inventories (674) 2,413 (261) Accounts payable and accrued expenses (102) (7,867) (1,689) --------- -------- --------- NET CASH PROVIDED BY OPERATING ACTIVITIES 28,524 22,590 35,269 CASH FLOWS FROM INVESTING ACTIVITIES: Acquisition of businesses, net of cash acquired -- -- (11,827) Disposition of businesses, net of cash 69,031 7,887 -- Proceeds from property and equipment disposals 218 3,011 4,082 Exploration expense (8,528) (6,442) (9,982) Additions to property and equipment (18,624) (2,996) (38,165) (Increase) decrease in other assets (83) 2,140 (1,294) --------- -------- --------- NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES 42,014 3,600 (57,186) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving line of credit and term loan 123,096 21,000 44,000 Repayment of long-term debt and other obligations (190,814) (50,582) (17,929) Debt issue costs (5,537) (2,766) (15) Proceeds from sale of common stock and stock options -- 3 -- Purchase of treasury stock (21) -- -- --------- -------- --------- NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (73,276) (32,345) 26,056 --------- -------- --------- NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (2,738) (6,155) 4,139 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 4,536 10,691 6,552 --------- -------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,798 $ 4,536 $ 10,691 ========= ======== =========
See accompanying notes. F-6 54 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 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 2000. 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, dry holes, expired leases and delay rentals, are expensed as incurred. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized. F-7 55 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 2000 and 1998 were $477,000 and $5.8 million, respectively, which wrote-down unproved oil and gas properties to their estimated fair value. Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is charged to income as incurred, and significant renewals and betterments are capitalized. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. In performing the review for long-lived asset recoverability during 1998, the Company recorded $148.0 million and $6.9 million of impairments which wrote-down producing properties and other assets, respectively, to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the assets, discounted at a market rate of interest. No impairment was recorded in 2000 and 1999. INTANGIBLE ASSETS ----------------- Intangible assets totaling $11.7 million at December 31, 2000, include deferred debt issuance costs, goodwill and other intangible assets and are being amortized over 25 years or the shorter of their respective terms. REVENUE RECOGNITION ------------------- Oil and gas production revenue is recognized as production and delivery take place. Oil and gas marketing revenues are recognized when title passes. Oilfield sales and service revenues are recognized when the goods or services have been provided. INCOME TAXES ------------ The Company uses the liability method of accounting for income taxes. Deferred income taxes are provided for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred income taxes also are recognized for operating losses that are available to offset future taxable income and tax credits that are available to offset future federal income taxes. STOCK-BASED COMPENSATION ------------------------ The Company measures expense associated with stock-based compensation under the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25). As of July 1, 2000, stock options repriced in October 1999 are subject to variable plan accounting (see Note 2). The changes in share value are reported as adjustments to compensation expense. The increase in share value in 2000 resulted in an increase in compensation expense of $336,000. The reduction in share value in 1999 and 1998 resulted in a reduction in compensation expense of $858,000 and $403,000, respectively. F-8 56 DERIVATIVES AND HEDGING ----------------------- As of 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 Financial Accounting Standards Board (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, will be applied prospectively as the cumulative effect of an accounting change effective January 1, 2001. As a result of the adoption of SFAS 133, the Company will recognize 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). The adoption of SFAS 133 will result 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 stockholders' deficit by $6.7 million to record the fair value of open cash flow hedges and the related income tax effect. The increase in stockholders' deficit will be reflected as a transition adjustment in other comprehensive income (loss) as of January 1, 2001. 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 March 2000, the Financial Accounting Standards Board issued FASB Interpretation No. (FIN) 44, "Accounting for Certain Transactions involving Stock Compensation, an interpretation of APB Opinion No. 25." The Interpretation, which has been adopted prospectively as of July 1, 2000, requires that stock options that have been modified to reduce the exercise price be accounted for as variable. The Company repriced 318,892 stock options (298,392 outstanding prior to July 1, 2000) in October 1999, and reduced the exercise price to $.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. Prior to the adoption of the Interpretation, the Company accounted for these repriced stock options as fixed. Because the value of the Company's stock increased since July 1, 2000, 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 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. F-9 57 In December 1999, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB) No. 101, "Revenue Recognition in Financial Statements." SAB 101, as amended, summarizes the SEC's views in applying generally accepted accounting principles to revenue recognition in financial statements. The adoption of SAB 101 on October 1, 2000 did not have a material effect on the Company's financial position or results of operations. (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 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 for the year 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 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. In November 1999, the Company sold Belden Energy Services Company ("BESCO"), its Ohio retail natural gas marketing subsidiary, to FirstEnergy Corp. ("FirstEnergy"). 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. (4) ACQUISITIONS The following acquisitions were accounted for as purchase business combinations. Accordingly, the results of operations of the acquired businesses are included in the Company's consolidated statements of operations from the date of the respective acquisitions. During 1998, the Company acquired working interests in oil and gas wells in Ohio, West Virginia, Michigan and New York for approximately $7.6 million. Estimated proved developed reserves associated with the wells totaled 8.8 Bcfe net to the Company's interest at the time of acquisition. The Company also acquired undeveloped properties and other assets for $4.2 million. The pro forma effects of the 1998 acquisitions were not material. (5) OTHER NONRECURRING EXPENSE The Company wrote off approximately $241,000 and $880,000 in 2000 and 1999, respectively. These costs were primarily associated with investment banking fees, an abandoned acquisition effort and the abandonment of a proposed public offering of a royalty trust. F-10 58 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. On March 19, 1998, the Company entered into an agreement in principle with FirstEnergy to form an equally-owned joint venture to be named FE Holdings L.L.C. ("FE Holdings") to engage in the exploration, development, production, transportation and marketing of natural gas. Formation of the joint venture was subject to the negotiation and execution of a definitive joint venture agreement. The Company was unable to reach agreement with FirstEnergy regarding certain terms of the joint venture agreement and in June 1998, the Company determined it would not participate in the proposed joint venture. Costs of $373,000 related to the proposed formation of the joint venture and due diligence associated with a proposed acquisition by FE Holdings were written-off to other nonrecurring expense in 1998. (6) DETAILS OF BALANCE SHEETS
DECEMBER 31, ----------------------------- 2000 1999 --------- --------- ACCOUNTS RECEIVABLE (IN THOUSANDS) Accounts receivable $ 12,333 $ 13,280 Allowance for doubtful accounts (1,245) (1,215) Oil and gas production receivable 11,358 12,626 Current portion of notes receivable 174 610 --------- --------- $ 22,620 $ 25,301 ========= ========= INVENTORIES Oil $ 1,272 $ 1,552 Natural gas 27 27 Material, pipe and supplies 923 527 --------- --------- $ 2,222 $ 2,106 ========= ========= PROPERTY AND EQUIPMENT, GROSS OIL AND GAS PROPERTIES Producing properties $ 390,229 $ 506,266 Non-producing properties 7,676 7,078 Other 15,919 21,171 --------- --------- $ 413,824 $ 534,515 ========= ========= LAND, BUILDINGS, MACHINERY AND EQUIPMENT Land, buildings and improvements $ 5,632 $ 6,592 Machinery and equipment 17,837 17,650 --------- --------- $ 23,469 $ 24,242 ========= ========= ACCRUED EXPENSES Accrued expenses $ 5,901 $ 9,500 Accrued drilling and completion costs 1,624 615 Accrued income taxes 481 190 Ad valorem and other taxes 2,449 3,733 Compensation and related benefits 2,685 2,324 Undistributed production revenue 6,176 6,662 --------- --------- $ 19,316 $ 23,024 ========= =========
F-11 59 (7) LONG-TERM DEBT Long-term debt consists of the following (in thousands):
DECEMBER 31, -------------------------- 2000 1999 -------- -------- Revolving line of credit $ 61,393 $114,000 Term loans -- 14,000 Senior subordinated notes 225,000 225,000 Other 161 180 -------- -------- 286,554 353,180 Less current portion 19 50,019 -------- -------- Long-term debt $286,535 $303,161 ======== ========
On June 27, 1997, the Company completed a private placement (pursuant to Rule 144A) of $225 million of 9 7/8% Senior Subordinated Notes, Series A, which mature on June 15, 2007. The notes were issued under an indenture which requires interest to be paid semiannually on June 15 and December 15 of each year, commencing December 15, 1997. The notes are subordinate to the senior revolving credit agreement and the term loans. In September 1997, the Company completed a registration statement on Form S-4 providing for an exchange offer under which each Series A Senior Subordinated Note would be exchanged for a Series B Senior Subordinated Note. The terms of the Series B Notes are the same in all respects as the Series A Notes except that the Series B Notes have been registered under the Securities Act of 1933 and therefore will not be subject to certain restrictions on transfer. The notes are redeemable in whole or in part at the option of the Company, at any time on or after June 15, 2002, at the redemption prices set forth below plus, in each case, accrued and unpaid interest, if any, thereon.
YEAR PERCENTAGE ---- ---------- 2002................................................. 104.938% 2003................................................. 103.292% 2004................................................. 101.646% 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 June 27, 1997, the Company entered into a senior revolving credit agreement with several lenders. These lenders committed, subject to compliance with the borrowing base, to provide the Company with revolving credit loans of up to $200 million, of which $25 million was available for the issuance of letters of credit. The credit agreement was a senior revolving credit facility secured by substantially all of the Company's assets. The borrowing base was determined by an evaluation of the Company's proved developed reserves, proved undeveloped reserves and related processing and gathering assets and other assets of the Company, adjusted by the engineering committee of the banks in accordance with their standard oil and gas lending practices. F-12 60 The Company's borrowing base at December 31, 1998 was $170 million. On January 15, 1999, the Company's borrowing base was redetermined at $126 million. The Company had $154 million outstanding under this agreement at December 31, 1998 which resulted in a borrowing base deficiency of $28 million. The Company agreed with its lenders to reduce this deficiency by $14 million on March 22, 1999 and by $14 million on May 10, 1999. On March 22, 1999, the Company made the $14 million payment to reduce the outstanding amount under the credit agreement to $140 million. On May 10, 1999, the Company and its lenders further amended the credit agreement to increase the Company's borrowing base to $136 million, subject to redetermination in November 1999, and the Company paid $4 million to reduce the outstanding loan balance to $136 million. The funds for these payments were provided by internally generated cash flow and $14 million in term loans provided by Chase Manhattan Bank. The Company was further required to make additional payments which would lower the borrowing base and outstanding balance to $126 million. The Company paid $5 million on July 29, 1999 and $6 million on September 10, 1999 to reduce the outstanding balance to $125 million at September 30, 1999. The amended agreement increased the interest rate to LIBOR (London Interbank Offered Rate) plus 2.5% and provided certain covenant ratio relief. The Company paid approximately $2 million in fees to the lenders and expenses associated with the amendment. On December 14, 1999, the Company and its bank group further amended the credit agreement. The revolving credit commitment in the amended agreement provided for a $75 million revolving portion which matures on June 27, 2002 and a $50 million term portion which would have matured on March 31, 2000. The Company paid approximately $900,000 in fees to the lenders and expenses associated with the amendment and wrote off $1.9 million of unamortized deferred loan costs due to the modification of the borrowing base. 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 "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 ("the Notes"). 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 due to the modification of borrowing capacity. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At December 31, 2000, the interest rate was 11.5%. Up to $20 million in letters of credit may be issued pursuant to the conditions of the Revolver. At December 31, 2000, the Company had $12.8 million of outstanding letters of credit. Initial proceeds from the Revolver of approximately $66 million 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) representing the unamortized deferred loan costs pertaining to the former credit facility. The charge was recorded as an extraordinary item. As of December 31, 2000, the outstanding balance under the Revolver was $61.4 million with $25.8 million of borrowing capacity available for general corporate purposes. F-13 61 The Facility 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 New York Mercantile Exchange ("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, 2000, under this formula was approximately $265 million for all proved reserves of the Company and $211 million for properties secured by a mortgage. The Facility is subject to certain financial covenants. These include a senior debt interest coverage ratio ranging from 5.8 to 1 at December 31, 2000, to 3.2 to 1 at June 30, 2002; and a senior debt leverage ratio ranging from 2.4 to 1 at December 31, 2000 to 3.2 to 1 at June 30, 2002. EBITDA, as defined in the Facility, 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) 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, 2000, the Company's current ratio including the above adjustments was 2.34 to 1. The Company had satisfied all financial covenants as of December 31, 2000. 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 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. Effective with the May 10, 1999 amendment to the credit agreement, the applicable margin relating to these swaps was increased from 1.5% to 2.5%. Effective with the December 14, 1999 amendment to the credit agreement, the applicable margin relating to these swaps was increased from 2.5% to a range up to 3.5%. At December 31, 2000, the aggregate long-term debt maturing in the next five years is as follows: $19,000 (2001); $61,412,000 (2002); $20,000 (2003); $5,000 (2004); $6,000 (2005); and $225,092,000 (2006 and thereafter). F-14 62 (8) LEASES The Company leases certain computer equipment, vehicles and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $1.6 million, $1.9 million and $2.2 million for the years ended December 31, 2000, 1999 and 1998, respectively. Future commitments under leasing arrangements were not significant at December 31, 2000. (9) SHAREHOLDERS' EQUITY In November 1998, the Company awarded 118,274 shares of common stock to employees as profit sharing and bonuses. These shares were issued in the subsequent year. (10) 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, 2000 there were 133,915 of these options 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, 2000, options to purchase 735,277 shares were outstanding under the plan. These options become exercisable as to 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 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 because, as discussed below, the alternative fair value accounting provided for under SFAS 123, "Accounting for Stock-Based Compensation" requires use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, no compensation expense is recognized 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 no options granted in 1998. There were 274,692 and 303,491 options granted in 2000 and 1999, respectively, and 318,892 options were repriced in 1999 which had an immaterial effect on compensation expense in 1999. As a result of adopting FIN 44 compensation expense increased $298,000 in the second half of 2000. 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 1999 and 2000, respectively: risk-free interest rates of 6.2% and 6.4%; 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. F-15 63 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 loss for the years ended December 31, 2000, 1999 and 1998 were not material. Stock option activity consisted of the following:
WEIGHTED NUMBER AVERAGE OF EXERCISE SHARES PRICE -------- ------ BALANCE AT DECEMBER 31, 1997 817,707 $ 8.66 -------- BALANCE AT DECEMBER 31, 1998 817,707 8.66 -------- Granted 303,491 1.26 Forfeitures (333,632) 10.82 Exercised (31,268) .13 Reissued and repriced (318,892) 10.82 Reissued and repriced 318,892 .01 -------- BALANCE AT DECEMBER 31, 1999 756,298 .53 Granted 274,692 .22 Forfeitures (65,000) 5.83 Exercised (96,798) .01 -------- BALANCE AT DECEMBER 31, 2000 869,192 .09 ======== OPTIONS EXERCISABLE AT DECEMBER 31, 2000 220,007 $ .07 ========
The weighted average fair value of options granted during 2000 and 1999 was $.07 and $.50, respectively. No options were granted in 1998. The exercise price for the options outstanding as of December 31, 2000 ranged from $.01 to $.30 per share. At December 31, 2000 the weighted average remaining contractual life of the outstanding options is 8.5 years. (11) TAXES The provision (benefit) for income taxes on income (loss) before extraordinary item includes the following (in thousands):
YEAR ENDED DECEMBER 31, ----------------------------------------------- 2000 1999 1998 -------- -------- -------- CURRENT Federal $ 290 $ -- $ (503) State 1 -- -- -------- -------- -------- 291 -- (503) DEFERRED Federal 2,073 (10,449) (69,976) State 4 (730) (5,726) -------- -------- -------- 2,077 (11,179) (75,702) -------- -------- -------- TOTAL $ 2,368 $(11,179) $(76,205) ======== ======== ========
F-16 64 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, ------------------------------------ 2000 1999 1998 ---- ---- ---- 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 2.0 Other, net (1.4) 0.9 (0.1) ---- ---- ---- Effective income tax rate for the period 35.4% 37.9% 36.9% ==== ==== ====
Significant components of deferred income tax liabilities and assets are as follows (in thousands):
DECEMBER 31, DECEMBER 31, 2000 1999 ------------ ------------ Deferred income tax liabilities: Property and equipment, net $ 45,065 $ 48,619 Other, net 753 625 -------- -------- Total deferred income tax liabilities 45,818 49,244 Deferred income tax assets: Accrued expenses 1,192 1,446 Inventories -- 17 Net operating loss carryforwards 25,372 30,014 Tax credit carryforwards 990 699 Other, net 390 708 Valuation allowance (1,840) (2,053) -------- -------- Total deferred income tax assets 26,104 30,831 -------- -------- Net deferred income tax liability $ 19,714 $ 18,413 ======== ======== Long-term liability $ 21,189 $ 20,419 Current asset (1,475) (2,006) -------- -------- Net deferred income tax liability $ 19,714 $ 18,413 ======== ========
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, 2000 relates principally to certain net operating loss carryforwards which management estimates will expire before they can be utilized. At December 31, 2000, the Company had approximately $71 million of net operating loss carryforwards available for federal income tax reporting purposes. Approximately $1 million of the net operating loss carryforwards are limited as to their annual utilization as a result of prior ownership changes. These net operating loss carryforwards, if unused, will expire from 2001 to 2006. The remaining net operating loss carryforwards will expire in 2012 and 2019. The Company has alternative minimum tax credit carryforwards of approximately $990,000 which have no expiration date. The Company has approximately $700,000 of statutory depletion carryforwards, which have no expiration date. (12) PROFIT SHARING AND RETIREMENT PLANS The Company has a non-qualified profit sharing arrangement under which the Company contributes discretionary amounts determined by the compensation committee of its Board of Directors. Amounts are allocated to substantially all employees based on relative compensation. The Company F-17 65 expensed $1.6 million, $845,000 and $938,000 for the years ended December 31, 2000, 1999 and 1998, respectively, for contributions to the profit sharing plan and discretionary bonuses. The 2000 and 1999 amounts were paid in cash. For the 1998 period one half was paid in cash and one half was paid in shares of the Company's common stock contributed into each eligible employee's 401(k) plan account. The Company has a qualified defined contribution plan (a 401(k) plan) covering substantially all of the employees of the Company. Under the plan, an amount equal to 2% of participants' compensation is contributed by the Company to the plan each year. Eligible employees may also make voluntary contributions which the Company matches $.50 for every $1.00 contributed up to 6% of an employee's annual compensation. Retirement plan expense amounted to $650,000, $830,000 and $867,000 for the years ended December 31, 2000, 1999 and 1998, respectively. The Company also has non-qualified deferred compensation plans which permit certain key employees to elect to defer a portion of their compensation. (13) COMMITMENTS AND CONTINGENCIES The Company is involved in various legal actions arising in the normal course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the financial position of the Company. (14) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
YEAR ENDED DECEMBER 31, ------------------------------------------ (IN THOUSANDS) 2000 1999 1998 ------- ------- -------- CASH PAID DURING THE PERIOD FOR: Interest $30,634 $34,426 $ 32,048 Income taxes, net of refunds 1 -- (1,970) NON-CASH INVESTING AND FINANCING ACTIVITIES: Acquisition of assets in exchange for long-term liabilities 239 125 415 Non-compete agreement and related obligation -- 705 --
(15) FAIR VALUE OF FINANCIAL INSTRUMENTS The fair value of the financial instruments disclosed herein is not representative of the amount that could be realized or settled, nor does the fair value amount consider the tax consequences, if any, of realization or settlement. The amounts in the financial statements for cash equivalents, accounts receivable and notes receivable approximate fair value due to the short maturities of these instruments. The recorded amounts of outstanding bank and other long-term debt approximate fair value because interest rates are based on LIBOR or the prime rate or due to the short maturities. The $225 million in senior subordinated notes had an approximate fair value of $191 million at December 31, 2000 based on rates available for similar instruments. From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas price volatility. The Company employs a policy of hedging gas production sold under NYMEX based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. Under the deferral method, gains and losses on these instruments are deferred on the balance F-18 66 sheet and are included as an adjustment to gas revenue for the production being hedged in the contract month. The Company incurred a pre-tax loss on its hedging activities of $9.3 million in 2000 and pre-tax gains of $1.2 million in 1999 and $1.5 million in 1998. At December 31, 2000 the fair value of futures contracts covering 2001 natural gas production represented an unrealized loss of $10.5 million. (16) 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) 2000 1999 1998 ------- ------ ------- Acquisition costs Proved properties $ 220 $ -- $ 9,194 Unproved properties 2,093 855 1,857 Developmental costs 13,849 186 30,090 Exploratory costs 8,528 6,442 9,982
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 have been reviewed by independent petroleum engineers. F-19 67 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, 1997 5,552 291,645 Extensions and discoveries 255 29,331 Purchase of reserves in place 34 20,296 Sale of reserves in place (21) (6,939) Revisions of previous estimates (809) 11,066 Production (768) (30,140) ------ -------- 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 ====== ======== PROVED DEVELOPED RESERVES December 31, 1998 3,974 280,669 ====== ======== December 31, 1999 5,898 267,942 ====== ======== December 31, 2000 5,954 251,747 ====== ========
(1) Thousand barrels (2) Million cubic feet F-20 68 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, --------------------------------------------------- 2000 1999 1998 ----------- --------- --------- (IN THOUSANDS) Estimated future cash inflows (outflows) Revenues from the sale of oil and gas $ 3,835,298 $ 957,046 $ 818,401 Production and development costs (805,025) (411,881) (340,321) ----------- --------- --------- Future net cash flows before income taxes 3,030,273 545,165 478,080 Future income taxes (1,037,843) (124,561) (102,358) ----------- --------- --------- Future net cash flows 1,992,430 420,604 375,722 10% timing discount (1,171,666) (203,716) (167,059) ----------- --------- --------- Standardized measure of discounted future net cash flows $ 820,764 $ 216,888 $ 208,663 =========== ========= =========
At December 31, 2000, 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. The average prices of natural gas used in the calculation were higher than the Company actually realized in December 2000. Further, based on market conditions in February 2001, these prices are not indicative of those that the Company expects to realize consistently in the future. If reserves had been valued using assumed constant wellhead prices of $23.50 per barrel of oil and $4.50 per Mmbtu (million British thermal units) of natural gas, total proved reserves would be 401.9 Bcfe instead of 425.4 Bcfe with a discounted future net cash flows before income taxes of $469.0 million instead of $1.2 billion. F-21 69 The principal sources of changes in the standardized measure of future net cash flows are as follows:
YEAR ENDED DECEMBER 31, ------------------------------------------------- 2000 1999 1998 --------- --------- --------- (IN THOUSANDS) Beginning of year $ 216,888 $ 208,663 $ 219,720 Sale of oil and gas, net of production costs (56,416) (54,059) (60,330) Extensions and discoveries, less related estimated future development and production costs 69,990 1,233 30,821 Purchase of reserves in place less estimated future production costs 13,383 -- 10,528 Sale of reserves in place less estimated future production costs (50,817) (578) (3,373) Revisions of previous quantity estimates 445,976 31,128 (673) Net changes in prices and production costs 608,442 32,836 (30,512) Change in income taxes (363,561) (2,729) 24,977 Accretion of 10% timing discount 26,751 25,656 29,259 Changes in production rates (timing) and other (89,872) (25,262) (11,754) --------- --------- --------- End of year $ 820,764 $ 216,888 $ 208,663 ========= ========= =========
(17) 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 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 the year ended December 31, 2000 which amounted to $21.6 million. No customer accounted for more than 10% of consolidated revenues during the years ended December 31, 1999 and 1998. F-22 70 (18) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The results of operations for the four quarters of 2000 and 1999 are shown below (in thousands).
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)
FIRST SECOND THIRD FOURTH -------- -------- -------- -------- 1999 ---- Sales and other operating revenues $ 34,257 $ 33,099 $ 30,685 $ 32,703 Gross profit (loss) 1,512 1,516 (593) 4,474 Net loss (4,157) (4,854) (7,691) (1,601)
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 2). (19) 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 cubit feet) of gas has been produced and sold. In addition to receiving 100% of the cash flow from the properties, the Company will receive quarterly incentive payments based on production from the interests. The Company has the option to repurchase the interests at a future date. F-23