10-K 1 l05560ae10vk.txt BELDEN & BLAKE 10-K 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, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File No. 0-20100 BELDEN & BLAKE CORPORATION (Exact name of registrant as specified in its charter) OHIO 34-1686642 (State or other jurisdiction of (I.R.S. Employer Identification Number) incorporation or organization) 5200 STONEHAM ROAD NORTH CANTON, OHIO 44720 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (330) 499-1660 Securities registered pursuant to Section 12(b) of the Act: NONE Securities registered pursuant to Section 12(g) of the Act: NONE 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] Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [ ] No [X] As of February 29, 2004, Belden & Blake Corporation had outstanding 10,427,831 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 as of the last business day of the registrant's most recently completed second fiscal quarter. DOCUMENTS INCORPORATED BY REFERENCE: None. The information in this document includes forward-looking statements that are made pursuant to Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements "should," "believe," "expect," "anticipate," "intend," "will," "continue," "estimate," "plan," "outlook," "may," "future," "projection," variations of these statements and similar expressions are forward-looking statements. These forward-looking statements are based on current expectations and projections about future events. Forward-looking statements, and the business prospects of Belden & Blake Corporation (the "Company") are subject to a number of risks and uncertainties which may cause the Company's actual results in future periods to differ materially from the forward-looking statements contained herein. These risks and uncertainties include, but are not limited to, the Company's access to capital, the market demand for and prices of oil and natural gas, the Company's oil and gas production and costs of operation, results of the Company's future drilling activities, the uncertainties of reserve estimates, general economic conditions, new legislation or regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described in the Company's 10-K and 10-Q reports and other filings with the Securities and Exchange Commission ("SEC"). The Company undertakes no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changes in assumptions, or otherwise. PART I ITEM 1. BUSINESS GENERAL Belden & Blake Corporation is a privately held company owned by TPG Partners II L.P. ("TPG") and certain other investors. The Company is an independent energy company engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. The Company provides oilfield services to itself and third-party customers through its Arrow Oilfield Service Company ("Arrow"). Until 1995, the Company conducted business exclusively in the Appalachian Basin where it has operated since 1942 through several predecessor entities. It is currently among the larger exploration and production companies operating in the Appalachian Basin in terms of reserves, acreage held and wells operated. In 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 Peake Energy, Inc. ("Peake"), a wholly owned subsidiary, which owned oil and gas properties in West Virginia and Kentucky. At December 31, 2003, the Company conducted business in Ohio, Pennsylvania, New York, Michigan, Kentucky, Indiana and West Virginia. In the fourth quarter of 2003, the Company's net production was approximately 50.6 Mmcfe (million cubic feet of natural gas equivalent) per day consisting of 43.6 Mmcf (million cubic feet) of natural gas and 1,160 Bbls (barrels) of oil per day. At December 31, 2003, the Company owned interests in 4,126 gross (3,155 net) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with proved reserves totaling 360 Bcfe (billion cubic feet of natural gas equivalent) consisting of 323 Bcf (billion cubic feet) of natural gas and 6.2 Mmbbl (million barrels) of oil. The estimated future net cash flows from these reserves had a present value (discounted at 10 percent) before income taxes of approximately $597 million at December 31, 2003. The weighted average prices related to proved reserves at December 31, 2003 were $6.19 per Mcf (thousand cubic feet) for natural gas and $29.78 per Bbl for oil. At December 31, 2003, the Company operated approximately 3,400 wells (82% of the 1 Company's gross wells), including wells operated for third parties. At that date, the Company held leases on 1,118,512 gross (924,033 net) acres, including 477,434 gross (355,826 net) undeveloped acres. At December 31, 2003, the Company owned and operated 1,254 miles of gas gathering systems with access to the commercial and industrial gas markets of the northeastern United States. During 2003, the Company drilled 98 gross (86.4 net) wells at a direct cost, including exploratory dry hole expense, of approximately $33.9 million for the net wells. The 2003 drilling activity added 20.5 Bcfe of proved developed reserves at an average cost of $1.65 per Mcfe (thousand cubic feet of natural gas equivalent). The cost was impacted by exploratory dry hole costs from wells drilled in the Trenton Black River ("TBR") formations. Excluding the costs of six exploratory dry holes drilled in the TBR during 2003, the average cost of developing proved reserves was $1.31 per Mcfe. The Company also made production enhancements to existing wells during the year which increased proved developed reserves by 595 Mmcfe at an average cost of $1.31 per Mcfe. Acquisitions of proved developed properties in 2003 added 4.6 Bcfe of proved developed reserves at an average cost of $0.83 per Mcfe. Proved developed reserves added through drilling, enhancements and acquisitions in 2003 represented approximately 148% of production. The Company maintains its corporate offices at 5200 Stoneham Road, North Canton, Ohio 44720. Its telephone number at that location is (330) 499-1660. Unless the context otherwise requires, all references herein to the "Company" are to Belden & Blake Corporation, its subsidiaries and predecessor entities. SIGNIFICANT EVENTS The Company's production volumes declined from 2002 to 2003 due to the sale of wells during 2002, the natural decline of the wells and cold weather in the first quarter of 2003. These declines were partially offset by new drilling and other production enhancement actions taken during 2002 and 2003. Production volumes bottomed out in the first quarter of 2003 at 45.0 Mmcfe per day following the asset sales in 2002 and increased each quarter throughout 2003, reaching 50.6 Mmcfe per day in the fourth quarter of 2003. The fourth quarter 2003 production rate was an increase of 11% over the fourth quarter of 2002 and a 12% increase over the first quarter of 2003. During 2003, the Company completed its first successful exploratory TBR wells. Through December 31, 2003, the Company has drilled six successful TBR wells including the recently announced two significant discoveries in New York. The first of these two wells began production in December 2003 and is currently producing at a rate of approximately 3.5 to 4.0 Mmcf of natural gas per day (1.4 to 1.6 Mmcf per day net to the Company's interest). The second well began production in March 2004 and is currently producing at a pipeline-restricted rate of approximately 3.4 Mmcf of natural gas per day (1.5 Mmcf per day net to the Company's interest). These two wells are in addition to two other successful wells that began producing earlier in the year. Two additional wells have been completed in the TBR and are awaiting completion of pipelines to begin production. The Company's completion rate for wells drilled to the TBR in 2002 and 2003 is 35%. All three of the TBR wells drilled in one area of south-central New York have been completed as producers. The Company plans to drill five TBR wells in this area in 2004. In the fourth quarter of 2003, the Company completed a review of its current undeveloped acreage position relative to drilling results in various areas. In addition to its successful TBR drilling in 2003, the Company drilled six exploratory dry holes in the TBR. The cost of these exploratory TBR dry holes was approximately $7.0 million. The Company determined that a portion of its acreage in certain exploratory TBR areas had a fair value of less than its book value. As a result, an impairment of approximately $4.7 million was recorded to reduce the book value of the TBR acreage to its estimated fair value. Additionally, an impairment of approximately $460,000 was recorded to reduce the book value of other acreage to its estimated fair value. 2 The Company's $100 million revolving credit facility (the "Revolver") was amended on March 31, 2003 to increase the letter of credit sub-limit to $55 million. On May 30, 2003, the Company amended the Revolver to increase the total commitment amount from $100 million to $125 million solely to provide for a special letter of credit facility in the amount of $25 million which combined with the existing letter of credit sub-limit of $55 million would allow a total of $80 million in letters of credit. The amendment also extended the Revolver's final maturity date to June 30, 2006, from December 31, 2005. On March 9, 2004, the Company announced that it had engaged Randall & Dewey Partners, L.P., an oil and gas strategic advisory and consulting firm based in Houston, Texas, to assist the Company in evaluating its strategic alternatives. DESCRIPTION OF BUSINESS OVERVIEW The Company conducts operations in the United States in one reportable segment which is oil and gas exploration and production. The Company is actively engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. The Company operates primarily in the Appalachian and Michigan Basins (a region which includes Ohio, Pennsylvania, New York, West Virginia and Michigan) where it is one of the larger oil and gas companies in terms of reserves, acreage held and wells operated. The Appalachian Basin is the oldest and geographically one of the largest oil and gas producing regions in the United States. Although the Appalachian Basin has sedimentary formations indicating the potential for oil and gas reservoirs to depths of 30,000 feet or more, oil and natural gas is currently produced primarily from shallow, highly developed blanket formations at depths of 1,000 to 6,200 feet and to a lesser extent deeper formations. Drilling completion rates of the Company and others drilling in these shallow, highly developed blanket formations historically have exceeded 90% with production generally lasting longer than 20 years. The combination of long-lived production and high drilling completion rates at these shallower depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the Appalachian Basin. As a result of this environment, there has been limited testing or development of the formations below the existing shallow production in the Appalachian Basin. The Company believes that there are significant exploration and development opportunities in these less developed formations for those operators with the capital, technical expertise and ability to assemble the large acreage positions needed to justify the use of advanced exploration and production technologies. During 2003, the Company strategically acquired approximately 20,096 gross (11,532 net) leasehold acres with potential in the deeper, less developed TBR formations. The Company drilled 12 gross (8.2 net) wells to the TBR, including three wells that were classified as wells in progress at December 31, 2002, at a cost of $15.9 million. Six of these wells (3.4 net wells) were completed in the TBR and six (4.8 net) wells were exploratory dry holes. The six successful wells added 4.7 Bcfe of proved developed reserves net to the Company's interests. The Company currently holds approximately 313,000 gross (215,000 net) leasehold acres and approximately 525 miles of 2-D seismic and 50 square miles of 3-D seismic data in prospective TBR areas in the Appalachian Basin and intends to continue to lease additional acreage and acquire additional 3 seismic data primarily in the currently productive TBR areas. The Company plans to drill 13 gross (7.7 net) wells in these TBR areas in 2004. The Company operates 139 producing coalbed methane ("CBM") wells in Pennsylvania and holds leases on approximately 73,000 acres of prospective CBM properties. Current gross production from these wells is 3.7 Mmcf (3.1 Mmcf net) per day. The Company drilled six CBM wells in 2003 and plans to drill an additional 18 CBM wells in 2004. The Company owns a 100% working interest in all of its CBM wells. During 2003, the Company also drilled 25 gross (24.0 net) development Medina wells and 15 gross (15.0 net) development Clarendon wells in Pennsylvania. The Company plans to continue this development drilling program by drilling 25 gross (24.4 net) Medina wells and 15 gross (15.0 net) Clarendon wells in 2004. The Company, through its subsidiary, Ward Lake, currently operates 840 wells in the Michigan Basin producing approximately 34.9 Mmcf (18.8 Mmcf net) of natural gas per day in Michigan. The Michigan Basin has geologic and operational similarities to the Appalachian Basin, geographic proximity to the Company's operations in the Appalachian Basin and proximity to premium gas markets. Geologically, the Michigan Basin resembles the Appalachian Basin with shallow blanket formations and deeper formations with greater reserve potential. Operationally, economies of scale and cost containment are essential to operating profitability. The operating environment in the Michigan Basin is also highly fragmented with substantial acquisition opportunities. Most of the Company's production in the Michigan Basin is derived from the shallow (700 to 2,000 feet) blanket Antrim Shale formation. Completion rates for companies drilling to this formation have exceeded 90%, with production often lasting 20 years or more. 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. During 2003, the Company drilled 33 gross (29.2 net) wells to the Antrim Shale formation. The Company plans to drill 36 gross (33.1 net) to the Antrim Shale formation in 2004. 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 fifteen to sixty cents per Mcf higher than comparable NYMEX prices. BUSINESS STRATEGY The Company seeks to increase shareholder value by increasing reserves, production and cash flow through the exploration and development of the Company's extensive acreage base; further improvement in profit margins through operational efficiencies; and utilization of the Company's advanced technology to enhance production and reserves discovered. The key elements of the Company's strategy are as follows: - MAINTAIN A BALANCED DRILLING PROGRAM. The Company's exploration and development activities focus on a well-balanced portfolio of development and exploratory drilling in both the highly 4 developed or blanket formations and the deeper, less developed and potentially more prolific formations. The Company primarily targets natural gas production in its drilling activities. The Company believes this portfolio approach, coupled with its extensive knowledge of its operating areas, allows the Company to optimize economic returns and minimize much of the geological risk associated with oil and gas exploration and development. The Company believes that there are significant exploration and development opportunities in the less developed or deeper formations in the Appalachian and Michigan Basins and in the shallow coalbed methane formations in western Pennsylvania. The Company has identified numerous development and exploratory drilling locations in the deeper formations of these Basins, such as the Trenton Black River, and has established a substantial leasehold position overlying potentially productive coalbed methane formations in western Pennsylvania. During 2002 and 2003, the Company spent a higher percentage of its drilling capital on higher risk exploration projects than it had in the past. In 2003, the Company spent approximately 46% of its drilling capital expenditures on highly developed or blanket formations and approximately 54% of its drilling capital expenditures on deeper, or less developed, potentially more prolific prospects. The deeper wells drilled by the Company in 2002 and 2003 are higher cost, higher risk with potential for higher reserves than the deep wells drilled by the Company in prior years. Funds previously targeted for other deeper formations have been redeployed to the TBR to take advantage of the significant upside potential of this play. - IMPROVE THE COMPANY'S FINANCIAL POSITION. At December 31, 2003, the Company had a deficit in shareholders' equity of $57.3 million. The Company may sell non-strategic assets and use the proceeds, along with a portion of its available cash flow, to reduce its debt burden and enhance liquidity. The Company may also attempt to restructure portions of its existing debt to further reduce the amount of debt outstanding. - UTILIZE ADVANCED TECHNOLOGY. The combination of long-lived production and high drilling completion rates at the shallow depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the Appalachian and Michigan Basins. The Company has applied more advanced technology, including 3-D seismic, horizontal drilling, advanced fracturing techniques and production enhancement technologies to improve drilling completion rates, reserves discovered per well, production rates, reserve recovery rates and total economics in its operating areas. - IMPROVE PROFIT MARGINS. The Company strives to improve its profit margins on production from existing and acquired properties through advanced production technologies, operating efficiencies and mechanical improvements. Through its production field offices, the Company reviews its properties, especially newly acquired properties, to determine what actions can be taken to reduce operating costs and/or improve production. The Company strives to control field level costs through improved operating practices such as computerized production scheduling and the use of hand-held computers to gather field data. On acquired properties, further efficiencies may be realized through improvements in production scheduling and reductions in oilfield labor. Actions that may be taken to improve production include modifying surface facilities, redesigning downhole equipment and recompleting existing wells. These actions can result in increased operating costs. - 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 82% 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 5 scale and through operating cost reductions, advanced production technology, mechanical improvements and/or the use of deliverability enhancement techniques. The Company currently maintains production field offices in Ohio, Pennsylvania and Michigan. Through these offices, the Company reviews its properties to determine what action can be taken to control operating costs and/or improve production. The Company has also provided its own oilfield services for more than 30 years in order to assure quality control and operational and administrative support to its exploration and production operations. Arrow, the Company's service division, provides the Company and third-party customers with necessary oilfield services such as well workovers, well completions, brine hauling and disposal and oil trucking. The Company currently operates approximately 1,254 miles of natural gas gathering lines in Ohio, Pennsylvania, New York and Michigan which are connected directly to various intrastate and interstate natural gas transmission systems. The interconnections with these pipelines afford the Company potential marketing access to numerous gas markets. 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. This table includes continuing and discontinued operations.
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------ 1999 2000 2001 2002 2003 ---------- ---------- ---------- ---------- ---------- PRODUCTION Gas (Mmcf) 26,988 20,037 18,541 17,106 14,912 Oil (Mbbl) 713 592 646 523 413 Total production (Mmcfe) 31,267 23,591 22,415 20,244 17,389 AVERAGE PRICE Gas (per Mcf) $ 2.50 $ 3.17 $ 4.34 $ 4.84 $ 4.93 Oil (per Bbl) 16.57 27.29 23.04 22.72 28.06 Mcfe 2.54 3.38 4.26 4.67 4.89 AVERAGE COSTS (PER MCFE) Production expense 0.70 0.89 1.01 1.04 1.15 Production taxes 0.10 0.10 0.11 0.09 0.14 Depletion 0.92 0.77 0.91 0.88 0.84 OPERATING MARGIN (PER MCFE) 1.74 2.39 3.14 3.54 3.60
Mmcf - Million cubic feet Mmcfe - Million cubic feet equivalent Bbl - Barrel Mbbl - Thousand barrels Mcf - Thousand cubic feet
Operating margin (per Mcfe) - average price less production expense and production taxes 6 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 and discontinued operations. However, it does not exclude all properties sold. See Note 4 to the Consolidated Financial Statements:
YEAR ENDED DECEMBER 31, ------------------------------------------------------------------ 1999 2000 2001 2002 2003 ---------- ---------- ---------- ---------- ---------- PRODUCTION Gas (Mmcf) 19,812 17,371 17,164 15,882 14,909 Oil (Mbbl) 639 573 644 522 413 Total production (Mmcfe) 23,647 20,811 21,030 19,012 17,386 AVERAGE PRICE Gas (per Mcf) $ 2.50 $ 3.14 $ 4.35 $ 4.95 $ 4.93 Oil (per Bbl) 16.51 27.35 23.04 22.72 28.06 Mcfe 2.54 3.38 4.26 4.76 4.89 AVERAGE COSTS (PER MCFE) Production expense 0.73 0.89 1.00 1.05 1.15 Production taxes 0.08 0.10 0.11 0.09 0.14 Depletion 0.99 0.78 0.91 0.88 0.84 OPERATING MARGIN (PER MCFE) 1.73 2.39 3.15 3.62 3.60
Mmcf - Million cubic feet Mmcfe - Million cubic feet equivalent Bbl - Barrel Mbbl - Thousand barrels Mcf - Thousand cubic feet
Operating margin (per Mcfe) - average price less production expense and production taxes EXPLORATION AND DEVELOPMENT The Company's activities include development and exploratory drilling in both the highly developed or blanket formations and the deeper or 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 2003, the Company drilled 79 gross (74.2 net) wells to highly developed or shallow blanket formations in its operating area at a net direct cost of approximately $15.7 million. The Company also drilled 19 gross (12.2 net) wells to less developed and deeper formations in 2003 at a net direct cost of approximately $18.2 million, including exploratory dry hole expense. The result of this drilling activity is shown in the table on page 11. In 2004, the Company expects to spend approximately $27.4 million, including exploratory dry hole expense, on development and exploratory drilling of approximately 120 gross (106.3 net) wells. In 2004, the Company plans to spend approximately 61% of its drilling capital expenditures on highly developed or blanket formations and approximately 39% of its drilling capital expenditures on deeper, or less developed, potentially more prolific prospects. The Company believes that its diversified portfolio approach to its drilling activities results in more consistent and predictable economic results than might be experienced with a less diversified or higher risk drilling program profile. Highly Developed or Blanket Formations. In general, the highly developed or blanket formations found in the Appalachian and Michigan Basins are widespread in extent and hydrocarbon accumulations. 7 Drilling completion rates of the Company and others drilling these formations historically have exceeded 90%. The principal risk of such wells is uneconomic recoverable reserves. The Company is a pioneer in coalbed methane development and production in Pennsylvania, presently operating 139 coalbed methane gas wells in Indiana, Westmoreland and Fayette counties. CBM wells in this area range in depth from 1,200 to 1,500 feet and typically encounter three to six unmined coal seams. In September 2001, the Company acquired its partner's 40% working interest in the Blacklick CBM field giving the Company 100% ownership of this CBM project. With approximately 76,000 CBM acres currently under lease in Pennsylvania, the Company believes the CBM will contribute significantly to its drilling portfolio. The Company plans to drill 18 gross (18.0 net) CBM wells in 2004. 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 natural gas at rates of 75 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 36 gross (33.1 net) wells to the Antrim Shale formation in 2004. In addition to its CBM and Antrim drilling, the Company also plans to drill 25 gross (24.4 net) wells to the Medina formation and 15 gross (15.0 net) wells to the Clarendon formation in Pennsylvania during 2004. Certain typical characteristics of the highly developed or blanket formations targeted by the Company are described below:
RANGE OF AVERAGE DRILLING AND RANGE OF AVERAGE COMPLETION COSTS PER GROSS RESERVES PER RANGE OF WELL DEPTHS WELL COMPLETED WELL -------------------- -------------------- ------------------ (IN FEET) (IN THOUSANDS) (IN MMCFE) Ohio: Clinton 3,000 - 5,500 $ 170 - 210 80 - 150 Pennsylvania: Coalbed Methane 1,200 - 1,500 150 - 180 150 - 250 Clarendon 1,100 - 2,000 65 - 80 30 - 50 Medina 5,000 - 6,200 210 - 260 150 - 300 Michigan: Antrim 700 - 2,000 170 - 230 350 - 550
Deeper or Less Developed Formations. The Appalachian Basin has productive and potentially productive sedimentary formations to depths of 30,000 feet or more, but the combination of long-lived production and high drilling completion rates in the shallow formations has curbed the development of the deeper formations in the basin. The Company believes it possesses the technological expertise and the acreage position needed to explore the deeper formations in a cost effective manner. The Trenton Black River formations continue to receive significant attention in the Appalachian Basin. Based on historical information available in public records, wells completed in the TBR possess significant productive potential with wells having produced from 0.1 Bcf to 4.0 Bcf of natural gas during 8 the first 12 months of production. Based on this and other data, the Company estimates that ultimate reserves could range from 0.5 Bcf to in excess of 12 Bcf of natural gas per well. With significant discoveries by the Company and other operators in south-central New York, the Company believes the potential exists for numerous opportunities in the Company's existing areas of operations. The Company plans to drill five gross (3.0 net) wells in this area in 2004. In 2001, the Company implemented a major leasing and geophysical program in the TBR that resulted in acquiring over 100,000 acres and more than 100 miles of seismic data. On June 29, 2001, the Company and Triana Energy, LLC ("Triana"), a West Virginia oil and gas exploration company, entered into an exploration agreement and a joint operating agreement ("JOA"). Pursuant to the JOA, Triana will manage the exploration of the Oriskany and Trenton Black River formations on certain properties in which the Company owns the leasehold working interest in Pennsylvania and New York. It is anticipated that the Company's contribution of its leasehold acreage coupled with the experience and professional skills contributed by Triana should enhance the Company's drilling program with respect to these properties and formations. Triana will manage all exploration and drilling activities performed on the properties covered by this agreement. The Company will be the operator following the completion of the wells. This agreement is in effect until June 29, 2006. The Company has also entered into several exploration agreements with other industry participants to jointly explore and develop the TBR in areas of New York and Ohio. The Company holds additional TBR acreage in which it owns a 100% working interest. During 2003, the Company strategically acquired approximately 20,096 gross (11,532 net) leasehold acres with potential in the deeper, less developed TBR formations. The Company drilled 12 gross (8.2 net) wells to the TBR, including three wells that were classified as wells in progress at December 31, 2002, at a cost of $15.9 million. Six of these wells (3.4 net wells) were completed in the TBR and six (4.8 net) wells were exploratory dry holes. The six successful wells added 4.7 Bcfe of proved developed reserves net to the Company's interests. The Company currently holds approximately 313,000 gross (215,000 net) leasehold acres and approximately 575 miles of 2-D seismic and 50 square miles of 3-D seismic data in prospective TBR areas in the Appalachian Basin and intends to continue to lease additional acreage and acquire additional seismic data primarily in the currently productive TBR areas. Exploration and drilling activities in the TBR formations, found at depths ranging from 2,000 to 12,000 feet, are focused on testing many of the currently identified prospects and confirming potential future drill sites. In 2004, the Company anticipates spending approximately $9.2 million to drill 13 gross (7.7 net) wells on TBR acreage. In addition, the Company plans to spend $1.2 million to acquire additional acreage and seismic data in the TBR, including an additional 50 square miles of 3-D seismic. The Company has also tested the Niagaran Carbonate, Onondaga Limestone, Oriskany Sandstone and Knox formations. In addition to its planned TBR drilling, the Company plans to drill two gross (1.0 net) wells to other deep formations in 2004. The Company also plans to drill 11 gross (7.1 net) exploratory wells in Kentucky and Indiana to various shallow, less developed formations in 2004. 9 Certain typical characteristics of the less developed or deeper formations targeted by the Company are described below:
AVERAGE DRILLING COSTS RANGE OF ---------------------- AVERAGE GROSS RANGE OF WELL COMPLETED RESERVES PER FORMATION LOCATION DEPTHS DRY HOLE WELL COMPLETED WELL ------------------- -------------- -------------- -------- ---------- -------------- (IN FEET) (IN THOUSANDS) (IN MMCFE) Trenton Black River Carbonates (1) PA, NY, WV, OH 2,000 - 12,000 $ 1,000 $ 1,600 500 - 3,200 Knox formations OH, NY 2,500 - 8,000 180 350 300 - 600 Niagaran Carbonate MI 4,500 - 5,500 300 600 900 - 1,500 Onondaga Limestone PA, NY 4,000 - 5,500 180 250 200 - 1,500 Oriskany Sandstone PA, NY 4,500 - 7,000 200 350 300 - 1,000
(1) TBR costs vary significantly based on the depths drilled. The average dry hole cost ranges from approximately $125,000 for a 2,000 foot well to over $1.5 million for wells drilled to 12,000 feet. The average completed well cost ranges from approximately $250,000 for a 2,000 foot well to over $3.0 million for wells drilled to 12,000 feet. 10 Drilling Results. The following table sets forth drilling results with respect to wells drilled by the Company during the past five years:
HIGHLY DEVELOPED OR BLANKET FORMATIONS (1) DEEPER OR LESS DEVELOPED FORMATIONS (2) ---------------------------------------------- -------------------------------------------------- 1999 2000 2001 2002 2003 1999 2000 2001 2002 2003 (6) ------ ------ ------ ------ ------ ------- ------ ------ ------ ------ Productive: Gross - 108 142 83 79 9(3) 17(4) 14(5) 12 9 Net - 83.6 130.6 63.7 74.2 2.1 7.2 7.4 6.2 4.9 Dry: Gross - 3 3 1 - 9 21 16 16 10 Net - 2.6 3.0 0.9 - 2.7 10.7 8.0 8.4 7.3 Reserves developed-net (Bcfe) - 15.4 20.6 15.2 15.3 0.5 2.5 2.3 1.6 5.2 Approximate cost (in millions) $ - $ 11.5 $ 21.1 $ 13.3 $ 15.7 $ 0.8 $ 5.5 $ 3.5 $ 7.5 $ 18.2 Wells in progress: Gross - - - - - - - - 4 - Net - - - - - - - - 2.0 - Cost (in millions) $ - $ - $ - $ - $ - $ - $ - $ - $ 2.4 $ -
(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 Black River Carbonates and Knox formations in Ohio, the Niagaran and Dundee Carbonates in Michigan, the Trenton Black River Carbonates, Oriskany Sandstone and Onondaga Limestone formations in Pennsylvania, and the Oriskany Sandstone, Onondaga Limestone, Trenton Black River Carbonates and Knox formations in New York. (3) One additional well which was dry in the Knox formations was subsequently completed in shallower formations. (4) Three additional wells which were dry in the Knox formations were subsequently completed in the shallower Clinton formation. (5) Two additional wells which were dry in the Knox formations were subsequently completed in the shallower Clinton formation. One additional well which was dry in the Trenton Black River formation was subsequently completed in the shallower Clinton formation. (6) Includes four wells that were classified as wells in progress in 2002. ACQUISITION OF PRODUCING PROPERTIES In 2003, the Company purchased reserves in certain wells the Company operates in Michigan for $3.8 million in cash. These properties were subject to a prior monetization transaction of the Section 29 tax credits which the Company entered into in 1996. The Company had the option to purchase these properties beginning in 2003. The Company previously held a production payment on these properties including a 75% reversionary interest in certain future production. The Company purchased those reserve volumes beyond its currently held production payment along with the 25% reversionary interest not owned. The estimated volumes acquired were 4.4 Bcf of proved developed producing gas reserves. In 2002, the Company completed one acquisition transaction adding 4.2 Bcfe of proved developed reserves for a purchase price allocated to proved developed reserves of approximately $1.2 million. The Company previously held a production payment on these properties through December 31, 2002. 11 In 2001, the Company completed two acquisition transactions adding 1.9 Bcfe of proved developed reserves for a combined purchase price allocated to proved developed reserves of approximately $1.7 million. The primary transaction in 2001 was the purchase of the remaining 40% working interest in a CBM project giving the Company 100% ownership of the project. DISPOSITION OF ASSETS As a result of the Company's decision to shift focus away from exploration and development activities in the Knox formation in Ohio, the Company sold substantially all of its undeveloped Knox acreage in Ohio, approximately 290,000 gross (272,000 net) acres, for approximately $2.8 million in September 2003. The sale resulted in a loss of approximately $150,000. The Company retained certain shallow development rights related to the Knox acreage. On December 10, 2002, the Company sold 962 oil and natural gas wells in New York and Pennsylvania. The sale included substantially all of the Company's Medina formation wells in New York and a smaller number of Pennsylvania Medina wells. The properties had approximately 23 Bcfe of total proved reserves. At the time of the sale, the Company's net production from these wells was approximately 3.9 Mmcfe per day (4 Mcfe per day per well). The Company disposed of these properties due to the low production volume per well and high cost characteristics. The wells sold had proved developed reserves using SEC pricing parameters of approximately 19.4 Bcfe and proved undeveloped reserves of approximately 3.6 Bcfe. The sale resulted in proceeds of approximately $16.2 million. On December 10, 2002, the Company received $15.5 million in cash with the remaining amount of approximately $700,000 received in February 2003. The proceeds were used to pay down the Company's revolving credit facility. As a result of the sale, the Company disposed of all of its properties producing from the New York Medina formation. As a result of the disposition of the entire New York Medina geographical/geological pool, the Company recorded a loss on the sale of $3.2 million ($1.8 million net of tax). According to Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. (SFAS) 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the disposition of this group of wells is classified as discontinued operations. The loss on the sale of the New York Medina wells and the related results of these properties have been reclassified as discontinued operations for all periods presented. During 2002, the Company completed the sale of six natural gas compressors in Michigan to a compression services company. The proceeds of approximately $2.0 million were used to pay down the Company's revolving credit facility. The Company also entered into an agreement to leaseback the compressors from the compression services company, which will provide full compression services including maintenance and repair on these and other compressors. Certain compressors were relocated to maximize compression efficiency. A gain on the sale of $168,000 was deferred and amortized as rental expense over the life of the lease. On August 1, 2002, the Company sold oil and gas properties consisting of 1,138 wells in Ohio that had approximately 10 Bcfe of reserves. At the time of the sale, the Company's net production from these wells was approximately 3.1 Mmcfe per day (3 Mcfe per day per well). The Company disposed of these properties due to the low production volume per well and high operating costs per well. The proceeds of approximately $8.0 million were used to pay down the Company's revolving credit facility. On March 17, 2000, the Company sold the stock of Peake, a wholly-owned subsidiary. The sale included substantially all of the Company's oil and gas properties in West Virginia and Kentucky. The sale resulted in net proceeds of approximately $69.2 million, which were used to reduce bank debt. At 12 the time of the sale, Peake represented approximately 20% of the Company's production and proved oil and gas reserves. The Company regularly reviews its oil and gas properties for potential disposition. EMPLOYEES As of February 29, 2004, the Company had 305 full-time employees, including 156 oil and gas exploration and production employees, 127 oilfield service employees and 22 general and administrative employees. The Company's management and technical staff in the categories above included 10 petroleum engineers, two geologists and two geophysicists. COMPETITION AND CUSTOMERS The oil and gas industry is highly competitive. Competition is particularly intense with respect to the acquisition of producing properties and undeveloped acreage and the sale of oil and gas production. There is competition among oil and gas producers as well as with other industries in supplying energy and fuel to end-users. The competitors of the Company in oil and gas exploration, development and production include major integrated oil and gas companies as well as numerous independent oil and gas companies, individual proprietors, natural gas pipeline companies 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 each of the years ended December 31, 2002 and 2001 was FirstEnergy Corp., sales to which amounted to $12.9 million and $21.0 million, respectively. During 2003, the Company had three customers that each accounted for 10% or more of consolidated revenues. The three customers were WPS Energy Services, Exelon Energy and National Fuel Gas with sales of $19.8 million, $11.5 million and $10.8 million, respectively. REGULATION Regulation of Production. In all states in which the Company is engaged in oil and gas exploration and production, its activities are subject to regulation. Such regulations may extend to requiring drilling permits, spacing of wells, the prevention of waste and pollution, the conservation of oil and natural gas and other matters. Such regulations may impose restrictions on the production of oil and natural gas by reducing the rate of flow from individual wells below their actual capacity to produce which could adversely affect the amount or timing of the Company's revenues from such wells. Moreover, future changes in local, state or federal laws and regulations could adversely affect the operations and economics of the Company. Environmental Regulation. The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before 13 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. ITEM 2. PROPERTIES OIL AND GAS RESERVES The following table sets forth the Company's proved oil and gas reserves as of December 31, 2001, 2002 and 2003 determined in accordance with the rules and regulations of the SEC. These estimates of proved reserves were prepared by Wright & Company, Inc., independent petroleum engineers. Proved reserves are the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
DECEMBER 31, -------------------------- 2001 2002 2003 ------ ------ ------ Estimated proved reserves Gas (Bcf) 334.2 335.5 322.7 Oil (Mbbl) 5,587 6,574 6,176 Bcfe 367.7 375.0 359.8
See Note 16 to the Consolidated Financial Statements for more detailed information regarding the Company's oil and gas reserves. The present value of the estimated future net cash flows before income taxes from the proved reserves of the Company as of December 31, 2003, determined in accordance with the rules and regulations of the SEC, was $597 million ($416 million after income taxes). Estimated future net cash flows represent estimated future gross revenues from the production and sale of proved reserves, net of estimated costs (including production taxes, ad valorem taxes, operating costs, development costs and additional capital investment). Estimated future net cash flows were calculated on the basis of prices and costs estimated to be in effect at December 31, 2003 without escalation, except where changes in prices were fixed and readily determinable under existing contracts. 14 The following table sets forth the weighted average prices, including fixed price contracts, for oil and gas utilized in determining the Company's proved reserves. The Company does not include its natural gas hedging financial instruments, consisting of natural gas swaps and collars, in the determination of its oil and gas reserves.
DECEMBER 31, -------------------------- 2001 2002 2003 ------ ------ ------ Gas (per Mcf) $ 2.92 $ 4.99 $ 6.19 Oil (per barrel) 17.85 27.81 29.78
At December 31, 2003, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. Consequently, these may not reflect the prices actually received or expected to be received for oil and natural gas due to seasonal price fluctuations and other varying market conditions. The prices shown above are weighted average prices for the total reserves. The Company also calculated an alternative reserve case utilizing an assumed NYMEX gas price of $4.75 per Mmbtu (million British thermal units) which equated to a weighted average gas price of $5.09 per Mcf, including adjustments for regional basis, Btu (British thermal unit) content and fixed price contracts. The weighted average oil price in the alternative case was $28.25 per Bbl. The alternative reserve case used all of the same assumptions as the proved reserve case at year-end, other than pricing. Total proved reserves calculated at the alternative prices were 355 Bcfe. Estimated future net cash flows from these reserves had a present value (discounted at 10 percent) before income taxes of approximately $455 million. IMPAIRMENT OF OIL AND GAS PROPERTIES AND OTHER ASSETS As described in Note 1 to the Consolidated Financial Statements, the Company evaluates long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In 2001, as a result of declining natural gas and oil prices, the Company recorded an impairment of $1.4 million related to producing properties. No impairment was recorded in 2002. In 2003, the Company recorded impairments of $5.2 million related to unproved properties and $572,000 related to producing properties. The impairment of unproved properties resulted primarily from a review of the Company's undeveloped acreage in areas of unsuccessful TBR drilling. The impairment does not terminate the Company's rights to develop the leasehold acreage. PRODUCING WELL DATA As of December 31, 2003, the Company owned interests in 4,126 gross (3,155 net) producing oil and gas wells and operated approximately 3,400 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. In the fourth quarter of 2003, the Company's net production was approximately 50.6 Mmcfe per day consisting of 43.6 Mmcf of natural gas and 1,160 Bbls of oil per day. 15 The following table summarizes by state the Company's productive wells at December 31, 2003:
DECEMBER 31, 2003 ------------------------------------------------------------- GAS WELLS OIL WELLS TOTAL -------------------- ----------------- ---------------- STATE GROSS NET GROSS NET GROSS NET ------------- ------- --------- ------- ------ ------ ------ Ohio 939 764 875 807 1,814 1,571 Pennsylvania 701 570 461 460 1,162 1,030 New York 27 17 - - 27 17 Michigan 1,116 533 7 4 1,123 537 ------- --------- ------- ------ ------ ------ 2,783 1,884 1,343 1,271 4,126 3,155 ======= ========= ======= ====== ====== ======
ACREAGE DATA The following table summarizes by state the Company's gross and net developed and undeveloped leasehold acreage at December 31, 2003:
DECEMBER 31, 2003 -------------------------------------------------------------------------- DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL ACREAGE ---------------------- ---------------------- ---------------------- STATE GROSS NET GROSS NET GROSS NET ------------- --------- --------- --------- --------- --------- --------- Ohio 289,709 254,562 83,776 71,669 373,485 326,231 Pennsylvania 155,793 143,576 145,576 118,504 301,369 262,080 New York 137,502 132,048 144,957 74,120 282,459 206,168 Michigan 58,074 38,021 39,428 36,927 97,502 74,948 West Virginia - - 37,099 35,277 37,099 35,277 Kentucky - - 18,039 10,823 18,039 10,823 Indiana - - 8,559 8,506 8,559 8,506 --------- --------- --------- --------- --------- --------- 641,078 568,207 477,434 355,826 1,118,512 924,033 ========= ========= ========= ========= ========= =========
Developed acreage includes 467,770 gross (430,255 net) acres of undrilled acreage held by production under the terms of lease agreements. ITEM 3. LEGAL PROCEEDINGS In February 2000, four individuals filed a suit in Chautauqua County, New York on their own behalf and on the behalf of others similarly situated, seeking damages for the alleged difference between the amount of lease royalties actually paid and the amount of royalties that allegedly should have been paid. Other natural gas producers in New York were served with similar complaints. The Company believes the complaint is without merit and is defending the complaint vigorously. Although the outcome is still uncertain, the Company believes the action will not have a material adverse effect on its financial position, results of operations or cash flows. The Company no longer owns the wells that were subject to the suit. In April 2002, the Company was notified of a claim by an overriding royalty interest owner in Michigan alleging the underpayment of royalty resulting from disputes as to the interpretation of the terms of several farmout agreements. The Company believes there will be no material amount payable 16 above and beyond the amount accrued as of December 31, 2003 and therefore, the result will have no material adverse effect on its financial position, results of operation or cash flows. The Company was audited by the state of West Virginia for the years 1996 through 1998. The state assessed taxes which the Company has contested and filed a petition for reassessment. In February 2003, the Company was notified by the State Tax Commissioner of West Virginia that the Company's petition for reassessment had been denied and taxes due, plus accrued interest, are now payable. The Company disagrees with the decision and has appealed. The Company believes there will be no material amount payable above and beyond the amount accrued as of December 31, 2003 and therefore, the result will have no material adverse effect on its financial position, results of operations or cash flows. The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on the Company's financial position, results of operations or cash flows. The Company was subject to binding arbitration on an issue regarding the valuation of shares of common stock put back to the Company in 1999 pursuant to a former executive officer's employment agreement. In March 2003, the arbitrator ruled that the Company must repurchase 31,168 shares of common stock for approximately $337,000 plus interest from the date of the employment agreement. The Company paid $521,000 in 2003 based on the ruling. Environmental costs, if any, are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed as incurred. Expenditures that extend the life of the related property or reduce or prevent future environmental contamination are capitalized. Liabilities related to environmental matters are only recorded when an environmental assessment and/or remediation obligation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability are fixed or reliably determinable. At December 31, 2003, no significant environmental remediation obligation exists which is expected to have a material effect on the Company's financial position, results of operations or cash flows. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not applicable. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES 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 29, 2004 was as follows: Number of Title of Class Record Holders -------------- -------------- Common Stock 15 DIVIDENDS No dividends have been paid on the Company's Common Stock. 17 ITEM 6. SELECTED FINANCIAL DATA The Selected Financial Data should be read in conjunction with the Consolidated Financial Statements at Item 15(a).
AS OF OR FOR THE YEARS ENDED DECEMBER 31, ------------------------------------------------------------- (IN THOUSANDS) 1999 2000(3) 2001 2002(2) 2003(1) ---------------------------------------------------- --------- --------- --------- --------- --------- CONTINUING OPERATIONS: Revenues $ 130,628 $ 104,902 $ 118,883 $ 113,920 $ 109,102 Depreciation, depletion and amortization 39,726 26,331 25,979 22,379 19,343 Impairment of oil and gas properties - 477 1,398 - 5,774 (Loss) income from continuing operations before cummulative effect of change in accounting principle (17,922) 3,425 5,776 3,745 (4,610) BALANCE SHEET DATA: Working capital from continuing operations (43,893) 2,715 12,727 (6,466) (6,973) Oil and gas properties and gathering systems, net 267,986 212,714 223,180 220,397 236,075 Total assets 350,695 285,117 305,349 263,845 283,911 Long-term liabilities, less current portion 303,731 286,858 284,745 251,959 277,132 Total shareholders' equity (deficit) (51,590) (48,313) (27,279) (44,645) (57,340)
(1) See Note 2 to the Consolidated Financial Statements. The cummulative effect of change in accounting principle, net of tax, was $2.4 million. (2) See Note 4 to the Consolidated Financial Statements for information on discontinued operations. (3) In March 2000, the Company sold Peake. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OVERVIEW The Company conducts its operations in the United States in one reportable segment which is oil and gas exploration and production. The Company's principal business is producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. The Company operates primarily in the Appalachian and Michigan Basins (a region which includes Ohio, Pennsylvania, New York, West Virginia and Michigan). The Company earns revenue through the production and sale of natural gas and oil and, to a lesser extent, from oilfield services, gas gathering and marketing. The Company's financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. The Company utilizes derivative instruments on a portion of its natural gas production to reduce the volatility of natural gas prices and to protect cash flow available for its development drilling and exploration program. Commodity prices of natural gas and oil increased during 2003 over 2002. The monthly average settle for natural gas trading on the NYMEX increased from $3.22 per Mmbtu during 2002 to $5.39 per Mmbtu during 2003. The Company's average unit price for natural gas was $4.95 per Mcf in 2002 and $4.93 per Mcf in 2003. The Company's selling price of natural gas is generally higher than the NYMEX price due to the favorable regional basis received throughout its areas of operations along with a favorable Btu content of its gas. The remainder of the difference is due to fixed price contracts and its hedging 18 activities during 2002 and 2003. The price the Company received for its oil sales was $22.72 per Bbl in 2002 and $28.06 per Bbl in 2003. The Company's production volumes declined from 2002 to 2003 due to the sale of wells during 2002, the natural decline of the wells and cold weather in the first quarter of 2003. These declines were partially offset by new drilling and other production enhancement actions taken during 2002 and 2003. Production volumes bottomed out in the first quarter of 2003 at 45.0 Mmcfe per day following the asset sales in 2002 and increased each quarter throughout 2003 reaching 50.6 Mmcfe per day in the fourth quarter of 2003. The fourth quarter 2003 production rate was an increase of 11% over the fourth quarter of 2002 and a 12% increase over the first quarter of 2003. CRITICAL ACCOUNTING POLICIES The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States ("GAAP") and SEC guidance. See the "Notes to Consolidated Financial Statements" included in "Item 8. Financial Statements and Supplementary Data" for a more comprehensive discussion of the Company's significant accounting policies. GAAP requires information in financial statements about the accounting principles and methods used and the risks and uncertainties inherent in significant estimates including choices between acceptable methods. Following is a discussion of the Company's most critical accounting policies: SUCCESSFUL EFFORTS METHOD OF ACCOUNTING The accounting for and disclosure of oil and gas producing activities requires the Company's management to choose between GAAP alternatives and to make judgments about estimates of future uncertainties. The Company utilizes the "successful efforts" method of accounting for oil and gas producing activities as opposed to the alternate acceptable "full cost" method. Under the successful efforts method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry hole costs and costs of carrying and retaining unproved properties, are expensed as incurred. The major difference between the successful efforts method of accounting and the full cost method is under the full cost method of accounting, such exploration costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the net income (loss) of future periods as a component of depletion expense. OIL AND GAS RESERVES The Company's proved developed and proved undeveloped reserves are all located within the Appalachian and Michigan Basins in the United States. The Company cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred may vary significantly from assumptions used. Proved reserves represent estimated quantities of natural gas and oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods 19 being utilized at the time the estimates were made. The accuracy of a reserve estimate is a function of: -- the quality and quantity of available data; -- the interpretation of that data; -- the accuracy of various mandated economic assumptions; and -- the judgment of the persons preparing the estimate. The Company's proved reserve information included in this Report is based on estimates prepared by independent petroleum engineers. Estimates prepared by others may be higher or lower than these estimates. CAPITALIZATION, DEPRECIATION, DEPLETION AND IMPAIRMENT OF LONG-LIVED ASSETS See the "Successful Efforts Method of Accounting" discussion above. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties are calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized. Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense. Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. Fair value is determined on management's outlook of future oil and natural gas prices and estimated future cash flows to be generated by the assets, discounted at a market rate of interest. Impairment of unproved properties is based on the estimated fair value of the property. DERIVATIVES AND HEDGING On January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. As a result of the adoption of SFAS 133, the Company recognizes all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss). 20 Ineffective portions of a derivative instrument's change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be recognized as increases or decreases to oil and gas revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss). The relationship between the hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. The Company measures effectiveness on changes in the hedge's intrinsic value. The Company considers these hedges to be highly effective and expects there will be no ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging instruments and the hedged forecasted transactions are the same. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. The Company measures effectiveness on at least a quarterly basis. The Company's financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. To manage its exposure to natural gas or oil price volatility, the Company has entered into NYMEX based commodity derivative contracts, currently natural gas swaps and collars, and has designated the contracts for the special hedge accounting treatment permitted under SFAS 133. Prior to January 1, 2001, under the deferral method, gains and losses from derivative instruments that qualified as hedges were deferred until the underlying hedged asset, liability or transaction monetized, matured or was otherwise recognized under generally accepted accounting principles. When recognized in net income (loss), hedge gains and losses were included as an adjustment to gas revenue or interest expense. REVENUE RECOGNITION Oil and gas production revenue is recognized as production and delivery take place. Oil and gas marketing revenues are recognized when title passes. Oilfield service revenues are recognized when the goods or services have been provided. ASSET RETIREMENT OBLIGATIONS On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 amends SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" to require the Company to recognize a liability for the fair value of its asset retirement obligations associated with its tangible, long-lived assets. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment (excluding salvage value) of its oil and gas properties. NEW ACCOUNTING PRONOUNCEMENTS On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 amends SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" to require the Company to recognize a liability for the fair value of its asset retirement obligations associated with its tangible, long-lived assets. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment (excluding salvage value) of its oil and gas properties. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $4.0 million increase in long-term asset retirement obligation liabilities, a $621,000 increase in current asset retirement obligation liabilities, a $3.2 million increase in the carrying value of oil and gas assets, a $5.2 million decrease in accumulated depreciation, depletion and amortization and a $1.4 million increase in deferred income tax liabilities. The net effect of adoption was 21 to record a gain of $2.4 million, net of tax, as a cumulative effect of a change in accounting principle in the Company's consolidated statement of operations in the first quarter of 2003. Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The unaudited pro forma income from continuing operations for the years ended December 31, 2002 and 2001 was $4.3 million and $6.9 million, respectively, and has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002 and January 1, 2001. Assuming retroactive application of the change in accounting principle as of January 1, 2002, liabilities would have increased approximately $6 million. A reconciliation of the Company's liability for asset retirement obligations for the year ended December 31, 2003 is as follows (in thousands): Asset retirement obligation, December 31, 2002 $ - Cumulative effect adjustment 4,603 Liabilities incurred 345 Liabilities settled (491) Accretion expense 365 Revisions in estimated cash flows 294 ---------- Asset retirement obligation, December 31, 2003 $ 5,116 ==========
On January 1, 2003, the Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt," SFAS 44, "Accounting for Intangible Assets of Motor Carriers" and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements" and amends SFAS No. 13, "Accounting for Leases." Statement 145 also makes technical corrections to other existing pronouncements. SFAS 4 required gains and losses from extinguishment of debt to be classified as an extraordinary item, net of the related income tax effect. As a result of the rescission of SFAS 4, the criteria for extraordinary items in Accounting Principles Board Opinion No. (APB) 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," now will be used to classify those gains and losses. The adoption of SFAS 145 did not have any effect on the Company's financial position, results of operations or cash flows. In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 was effective for the Company for disposal activities initiated after December 31, 2002. The adoption of this standard did not have any effect on the Company's financial position, results of operations or cash flows. In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities - An Interpretation of Accounting Research Bulletin (ARB) 51." FIN 46 is an interpretation of ARB 51, "Consolidated Financial Statements," and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an 22 interest after that date. It applies in the first fiscal year or interim period beginning after December 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. The adoption of FIN 46 did not have any effect on the Company's financial statement disclosures, financial position, results of operations or cash flows. In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This Statement is intended to result in more consistent reporting of contracts as either freestanding derivative instruments subject to Statement 133 in its entirety, or as hybrid instruments with debt host contracts and embedded derivative features. SFAS 149 is effective for the Company's financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 149 did not have a material effect on the Company's financial position, results of operations or cash flows. In May 2003, the FASB issued SFAS 150, "Accounting for Financial Instruments with Characteristics of both Liabilities and Equity." This Statement establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity. Instruments that are indexed to and potentially settled in an issuer's own shares that are not within the scope of Statement 150 remain subject to existing guidance. SFAS 150 is effective for the Company's financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 150 did not have a material effect on the Company's financial position, results of operations or cash flows. The Company has been made aware of an issue regarding the application of provisions of SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," to oil and gas companies. The issue is whether SFAS 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS 69, "Disclosures about Oil and Gas Producing Activities." If it is ultimately determined that SFAS 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the Company currently believes that its financial condition, results of operations or cash flows would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. The Company had undeveloped leasehold costs of $7.7 million and $14.2 million at December 31, 2003 and 2002, respectively. The amount of potential balance sheet reclassifications for developed leasehold costs has not been determined. In December 2003, the FASB issued SFAS 132 (revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits," an amendment of SFAS 87, 88, and 106, and a revision of SFAS 132. This statement revises employers' disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by FASB Statements No. 87, Employers' Accounting for Pensions, No. 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, and No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. This Statement retains the disclosure requirements contained in FASB Statement No. 132, Employers' Disclosures about Pensions and Other Postretirement Benefits, which it replaces. It requires additional disclosures to those in the original Statement 132 about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. The required information should be provided separately for pension plans and for other postretirement benefit plans. This Statement is 23 effective for financial statements with fiscal years ending after December 15, 2003. The adoption of this standard did not have a material effect on the Company's financial position, results of operations or cash flows. RESULTS OF OPERATIONS The following table sets forth financial data for the periods indicated. Dollars are stated in thousands and percentages are stated as a percentage of total revenues.
YEAR ENDED DECEMBER 31, ---------------------------------------------------------------------------- 2003 2002 2001 ---------------------- ---------------------- ---------------------- REVENUES Oil and gas sales $ 85,023 77.9% $ 90,462 79.4% $ 89,491 75.3% Gas gathering, marketing, and oilfield service 23,741 21.8 21,624 19.0 27,348 23.0 Other 338 0.3 1,834 1.6 2,044 1.7 --------- -------- --------- -------- --------- -------- 109,102 100.0 113,920 100.0 118,883 100.0 EXPENSES Production expense 19,937 18.2 19,936 17.5 20,952 17.6 Production taxes 2,455 2.3 1,789 1.6 2,298 1.9 Gas gathering, marketing, and oilfield service 21,378 19.6 17,996 15.8 22,760 19.1 Exploration expense 16,882 15.5 16,256 14.3 8,335 7.0 General and administrative expense 4,559 4.2 4,557 4.0 4,395 3.7 Franchise, property and other taxes 282 0.3 91 0.1 238 0.2 Depreciation, depletion and amortization 19,343 17.7 22,379 19.6 25,979 21.9 Impairment of oil and gas properties 5,774 5.3 - - 1,398 1.2 Accretion expense 365 0.3 - - - - Derivative fair value gain (319) (0.3) - - - - Severance and other nonrecurring expense - - 953 0.8 1,954 1.7 --------- -------- --------- -------- --------- -------- 90,656 83.1 83,957 73.7 88,309 74.3 --------- -------- --------- -------- --------- -------- OPERATING INCOME 18,446 16.9 29,963 26.3 30,574 25.7 OTHER EXPENSE Loss on sale of businesses - - 154 0.1 - - Interest expense 25,537 23.4 23,608 20.7 25,753 21.7 --------- -------- --------- -------- --------- -------- (LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (7,091) (6.5) 6,201 5.5 4,821 4.0 (Benefit) provision for income taxes (2,481) (2.3) 2,456 2.2 (955) (0.8) --------- -------- --------- -------- --------- -------- (LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (4,610) (4.2) 3,745 3.3 5,776 4.8 (Loss ) income from discontinued operations, net of tax (111) (0.1) (1,280) (1.1) 691 0.6 --------- -------- --------- -------- --------- -------- (LOSS) INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (4,721) (4.3) 2,465 2.2 6,467 5.4 Cumulative effect of change in accounting principle, net of tax 2,397 2.2 - - - - --------- -------- --------- -------- --------- -------- NET (LOSS) INCOME $ (2,324) (2.1)% $ 2,465 2.2% $ 6,467 5.4% ========= ======== ========= ======== ========= ========
24 The following Management's Discussion and Analysis is based on the results of operations from continuing operations, unless otherwise noted. Accordingly, the discontinued operations have been excluded. See Note 4 to the Consolidated Financial Statements. 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. This table includes continuing operations only.
YEAR ENDED DECEMBER 31, -------------------------------------- 2003 2002 2001 ---------- ---------- ---------- PRODUCTION Gas (Mmcf) 14,909 15,882 17,164 Oil (Mbbl) 413 522 644 Total production (Mmcfe) 17,386 19,012 21,030 AVERAGE PRICE Gas (per Mcf) $ 4.93 $ 4.95 $ 4.35 Oil (per Bbl) 28.06 22.72 23.04 Mcfe 4.89 4.76 4.26 AVERAGE COSTS (PER MCFE) Production expense 1.15 1.05 1.00 Production taxes 0.14 0.09 0.11 Depletion 0.84 0.88 0.91 OPERATING MARGIN (PER MCFE) 3.60 3.62 3.15
Mmcf - Million cubic feet Mmcfe - Million cubic feet equivalent Bbl - Barrel Mbbl - Thousand barrels Mcf - Thousand cubic feet
Operating margin (per Mcfe) - average price less production expense and production taxes 2003 COMPARED TO 2002 REVENUES Net operating revenues decreased from $112.1 million in 2002 to $108.8 million in 2003. The decrease was due to lower gas sales revenues of $5.2 million and lower oil sales revenues of $266,000 partially offset by higher revenues from gas gathering, marketing and oilfield service services of $2.1 million. Gas volumes sold decreased 1.0 Bcf (6%) from 15.9 Bcf in 2002 to 14.9 Bcf in 2003 resulting in a decrease in gas sales revenues of approximately $4.8 million. Oil volumes sold decreased approximately 109,000 Bbls (21%) from 522,000 Bbls in 2002 to 413,000 Bbls in 2003 resulting in a decrease in oil sales revenues of approximately $2.5 million. The oil and gas volume decreases were due to the sale of 202 wells in Ohio in the first quarter of 2002, 1,138 wells in Ohio in the third quarter of 2002 and 135 wells in Pennsylvania in the fourth quarter of 2002 and the natural production decline of the wells partially offset by production from wells drilled in 2002 and 2003. The average price realized for the Company's natural gas decreased $0.02 per Mcf to $4.93 per Mcf in 2003 compared to 2002 which decreased gas sales revenues in 2003 by approximately $300,000. As a result of the Company's hedging activities, gas sales revenues were decreased by $10.3 million ($0.69 per Mcf) in 2003 and increased by $21.6 million ($1.36 per Mcf) in 2002. The average price paid for the Company's oil increased from $22.72 per barrel in 2002 to $28.06 per barrel in 2003 which increased oil sales revenues by approximately $2.2 million. 25 The operating margin from oil and gas sales (oil and gas sales revenues less production expense and production taxes) on a per unit basis decreased from $3.62 per Mcfe in 2002 to $3.60 per Mcfe in 2003. The increase in gas gathering, marketing and oilfield service revenues was primarily due to a $5.1 million increase in oilfield service revenues partially offset by a $3.0 million decrease in gas gathering and marketing revenues. The increase in oilfield service revenues was due primarily to the acquisition of a drilling consulting business in the second quarter of 2002. The lower gas gathering and marketing revenues were the result of decreased gas marketing activity, the termination of a gas marketing contract and lower margins on a gathering system in Pennsylvania. COSTS AND EXPENSES Production expense in 2003 was flat with 2002 at $19.9 million. Production expense in 2003 decreased due to the sale of wells in Ohio and Pennsylvania during 2002, but this was offset by higher operating costs incurred as a result of colder temperatures and greater amounts of snow during the first quarter of 2003 coupled with increased costs to stimulate production on declining wells in the higher oil and natural gas price environment of 2003. These efforts increased production volumes during 2003 but also had the effect of increasing the per unit cost. The average production cost increased from $1.05 per Mcfe in 2002 to $1.15 per Mcfe in 2003. The per unit increase was primarily due to the higher costs incurred during 2003 as discussed above and due to certain fixed costs spread over fewer volumes in 2003. Production taxes increased $666,000 from $1.8 million in 2002 to $2.5 million in 2003 primarily due to higher oil and gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes increased 50% from $0.09 per Mcfe in 2002 to $0.14 per Mcfe in 2003 primarily due to a 56% increase in the selling price of natural gas in 2003, excluding the effects of hedging. Exploration expense increased $626,000 from $16.3 million in 2002 to $16.9 million in 2003 due to a $4.0 million increase in exploratory dry hole cost, partially offset by a decrease in land leasing costs of $956,000, a decrease in seismic costs of $1.7 million along with a decrease in expired or dropped leases of $500,000. The increase in exploratory dry hole cost was primarily due to the increased exploration activities in the TBR play. During 2003 the Company drilled six TBR wells with a cost of $7.0 million that were dry holes compared with five wells in 2002 with a cost of $3.4 million. Depreciation, depletion and amortization decreased by $3.1 million from $22.4 million in 2002 to $19.3 million in 2003. This decrease was primarily due to a $286,000 reduction in amortization of loan costs, a $404,000 reduction in the amortization of nonconventional fuel source tax credits and a decrease in depletion expense. Depletion expense decreased $2.1 million (12%) from $16.7 million in 2002 to $14.6 million in 2003 due to lower oil and gas volumes and a lower depletion rate per Mcfe. Depletion per Mcfe decreased from $0.88 per Mcfe in 2002 to $0.84 per Mcfe in 2003, primarily due to the effect of the adoption of SFAS 143. The basis used to calculate depletion expense for oil and gas properties was increased by the fair value of the estimated future plugging liability and decreased by the gross amount of the estimated salvage value of the well equipment. Impairment of oil and gas properties was $5.8 million in 2003 due to impairment of acreage of $5.2 million in certain areas and an impairment of $572,000 in two of the Company's smaller producing pools. The Company impaired the value of certain TBR acreage in areas where drilling resulted in dry holes and where no future drilling is planned. The impairments reduced the property's book value to its estimated fair value. 26 Accretion expense was $365,000 in 2003 as a result of the adoption of SFAS 143 at the beginning of 2003. Derivative fair value gain was $319,000 in 2003 related to certain derivative instruments that are not designated as cash flow hedges. The gain reflects the changes in fair value of those instruments. The Company recorded severance and other nonrecurring charges of $1.0 million in 2002 which were primarily related to employment reductions. In 2002, a total of 28 positions were eliminated when the Company combined its Pennsylvania/New York District with its Ohio District to form a new "Appalachian District." These actions were necessary to capitalize on operational and administrative efficiencies and bring the Company's employment level in line with current and anticipated future staffing. Interest expense increased $1.9 million (8%) from $23.6 million in 2002 to $25.5 million in 2003. This increase was due to a increase in average outstanding borrowings and higher blended interest rates. Income tax expense decreased $5.0 million from expense of $2.5 million in 2002 to an income tax benefit of $2.5 million in 2003. The decrease in expense is due to a decrease in income from continuing operations and a lower effective tax rate in 2003. Discontinued operations relating to the New York Medina wells sold in 2002 resulted in a net loss of $1.3 million in 2002 and $111,000 in 2003. The 2002 amount is primarily attributable to the $3.2 million ($1.8 million net of tax benefit) loss recorded on the sale in 2002. 2002 COMPARED TO 2001 REVENUES Net operating revenues decreased from $116.8 million in 2001 to $112.1 million in 2002. The decrease was due to lower oil sales revenues of $3.0 million, lower revenues from gas gathering, marketing and oilfield service services of $5.7 million, partially offset by higher gas sales revenues of $4.0 million. Gas volumes sold decreased 1.3 Bcf (7%) from 17.2 Bcf in 2001 to 15.9 Bcf in 2002 resulting in a decrease in gas sales revenues of approximately $5.6 million. Oil volumes sold decreased approximately 122,000 Bbls (19%) from 644,000 Bbls in 2001 to 522,000 Bbls in 2002 resulting in a decrease in oil sales revenues of approximately $2.8 million. The oil and gas volume decreases were due to the sale of 202 wells in Ohio in the first quarter of 2002, 1,138 wells in Ohio in the third quarter of 2002 and 135 wells in Pennsylvania in the fourth quarter of 2002 and the natural production decline of the wells partially offset by production from wells drilled in 2001 and 2002. The average price realized for the Company's natural gas increased $0.60 per Mcf to $4.95 per Mcf in 2002 compared to 2001 which increased gas sales revenues in 2002 by approximately $9.5 million. As a result of the Company's hedging activities, gas sales revenues were increased by $21.6 million ($1.36 per Mcf) in 2002 and $4.5 million ($0.26 per Mcf) in 2001. The average price paid for the Company's oil decreased from $23.04 per barrel in 2001 to $22.72 per barrel in 2002 which decreased oil sales revenues by approximately $170,000. The operating margin from oil and gas sales (oil and gas sales revenues less production expense and production taxes) on a per unit basis increased 15% from $3.15 per Mcfe in 2001 to $3.62 per Mcfe in 2002. 27 The decrease in gas gathering, marketing and oilfield service revenues was due to a decrease in gas marketing activity and the termination of a gas marketing contract. COSTS AND EXPENSES Production expense decreased $1.1 million (5%) from $21.0 million in 2001 to $19.9 million in 2002. The average production cost increased from $1.00 per Mcfe in 2001 to $1.05 per Mcfe in 2002. The per unit increase was primarily due to certain fixed costs spread over fewer volumes in 2002. Production taxes decreased $509,000 from $2.3 million in 2001 to $1.8 million in 2002 primarily due to the wells sold during 2002. Average per unit production taxes decreased 14% from $0.11 per Mcfe in 2001 to $0.09 per Mcfe in 2002 primarily due to a 12% decrease in the selling price of natural gas in 2002, excluding the effects of hedging. Exploration expense increased $8.0 million from $8.3 million in 2001 to $16.3 million in 2002 due to a $3.4 million increase in exploratory dry holes, an increase in land leasing costs of $614,000, an increase in delay rentals of $1.1 million and an increase in seismic costs of $1.5 million all of which are primarily due to the Company's increased exploration activities in the TBR play along with an increase in expired or dropped leases of $1.3 million. Depreciation, depletion and amortization decreased by $3.6 million from $26.0 million in 2001 to $22.4 million in 2002. This decrease was primarily due to a $570,000 reduction in amortization of loan costs from the extension of the Revolver's final maturity date, a $173,000 reduction in amortization of non-compete covenants which expired in 2001, a $323,000 reduction in the amortization of nonconventional fuel source tax credits in 2002 and a decrease in depletion expense. Depletion expense decreased $2.5 million (13%) from $19.2 million in 2001 to $16.7 million in 2002. Depletion per Mcfe decreased from $0.91 per Mcfe in 2001 to $0.88 per Mcfe in 2002. These decreases were primarily the result of a lower amortization rate per Mcfe due to higher reserves resulting from higher oil and gas prices at year-end 2002. Impairment of oil and gas properties and other assets decreased $1.4 million due to no impairment in 2002. The Company recorded severance and other nonrecurring charges of $1.0 million in 2002 and $2.0 million in 2001 which were primarily related to employment reductions. In 2002, a total of 28 positions were eliminated when the Company combined its Pennsylvania/New York District with its Ohio District to form a new "Appalachian District." These actions were necessary to capitalize on operational and administrative efficiencies and bring the Company's employment level in line with current and anticipated future staffing. Interest expense decreased $2.2 million (8%) from $25.8 million in 2001 to $23.6 million in 2002. This decrease was due to a decrease in average outstanding borrowings and lower blended interest rates. Income tax expense increased $3.5 million from a benefit of $1.0 million in 2001 to income tax expense of $2.5 million in 2002. The increase in expense is due to an increase in income from continuing operations and income tax benefits of $2.7 million recorded in 2001. During 2001, the Company concluded an IRS income tax examination of the years 1994 through 1997 and favorably settled other tax issues. A federal income tax benefit of $2.0 million was recorded as a result. Also during 2001, a federal income tax benefit was recorded for approximately $700,000 along with a corresponding reduction in the valuation allowance as a result of certain net operating loss carryforwards which the Company now believes it can fully utilize. 28 Discontinued operations relating to the New York Medina wells sold resulted in a net loss of $1.3 million in 2002 compared to net income of $691,000 in 2001. This was primarily attributable to the $3.2 million ($1.8 million net of tax benefit) loss recorded on the sale in 2002. LIQUIDITY AND CAPITAL RESOURCES CASH FLOWS The primary sources of cash in the three-year period ended December 31, 2003 have been from funds generated from operations, asset dispositions and from borrowings under the credit agreement. Funds used during this period were primarily used for operations, exploration and development expenditures, interest expense and repayment of debt. 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 following table summarizes the net cash flow from operations, investing activities and financing activities:
YEAR ENDED DECEMBER 31, ----------------------------------------- 2003 2002 CHANGE ----------- ----------- ----------- (IN MILLIONS) Cash flows provided by operating activities $ 27.1 $ 50.9 $ (23.8) Cash flows from investing activities (48.2) (32.5) (15.7) Cash flows from financing activities 20.2 (33.4) 53.6 Changes in cash from discontinued operations 0.6 14.8 (14.2) ----------- ----------- ----------- Net increase or decrease in cash and cash equivalents $ (0.3) $ (0.2) $ (0.1) =========== =========== ===========
The Company's operating activities provided cash flows of $27.1 million during 2003 compared to $50.9 million in 2002. The decrease was primarily due to lower cash received for oil and gas revenues (net of hedging) of $11 million, higher interest expense of $2 million and changes in working capital items of $9 million. Cash flows used in investing activities increased in 2003 due to $11 million in lower asset sales in 2003 compared to 2002, $2 million of increased acquisitions in 2003 and $3 million of increased capital expenditures. Cash flows provided by financing activities in 2003 were primarily due to borrowings on the credit facility during 2003 to fund the acquisitions, exploration and development expenditures in 2003. During 2003, working capital from continuing operations decreased $507,000 from a deficit of $6.5 million at December 31, 2002 to a deficit of $7.0 million at December 31, 2003. The decrease was primarily due to an increase in liability for the fair value of derivatives of $9.0 million which was partially offset by an increase in accounts receivable of $2.9 million, an increase in deferred tax assets of $2.7 million and a decrease in accrued expenses of $2.4 million. 29 CAPITAL EXPENDITURES The table below sets forth the Company's' capital and exploration expenditures for the three years ending December 31, 2003.
YEAR ENDED DECEMBER 31, ------------------------------------------------ FORECAST ACTUAL --------- ----------------------------------- 2004 2003 2002 2001 --------- --------- --------- --------- (IN MILLIONS) Drilling and completion $ 25 $ 25 $ 16 $ 23 Production enhancements and field improvements 4 3 2 4 Leasehold acreage 3 1 6 6 Other capital expenditures 1 2 4 4 --------- --------- --------- --------- Subtotal capital expenditures $ 33 $ 31 $ 28 $ 37 Exploration costs 8 8 12 7 Exploratory dry hole costs 3 9 4 1 Acquisitions -- 5 3 2 --------- --------- --------- --------- Total $ 44 $ 53 $ 47 $ 47 ========= ========= ========= =========
During 2003, the Company invested $33.9 million, including exploratory dry hole expense, to drill 83 development wells and 15 exploratory wells. Of these wells, all 83 development wells and five exploratory wells were completed as producers in the target formation, for a completion rate of 100% and 33%, respectively (an overall completion rate of 90%). In addition, $3.8 million was invested in proved developed reserve acquisitions. During 2003 the Company explored the TBR in six different areas and drilled 12 gross wells of which six were completed as producers in the TBR. The Company has abandoned certain areas where it has been unsuccessful and as a result recorded impairment expense for acreage in those areas. The Company plans to continue to explore certain TBR areas with a focus on those areas where commercial production has been established by the Company or others. The Company currently expects to spend approximately $36 million during 2004 on its drilling activities, including exploratory dry hole expense, and other capital expenditures. The Company intends to finance its planned capital expenditures through its available cash flow, available revolving credit facility and, to a lesser extent, the sale of non-strategic assets. At December 31, 2003, the Company had approximately $38.9 million available under the Revolver. At February 29, 2004, the Company had approximately $38.0 million available under the Revolver. The level of the Company's future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of its drilling activities and its ability to acquire additional producing properties. FINANCING AND CREDIT FACILITIES During 2003, amendments to the Company's $100 million revolving credit facility extended the Revolver's final maturity date to June 30, 2006, from December 31, 2005, increased the letter of credit sub-limit from $40 million to $55 million, then increased the total commitment amount from $100 million to $125 million solely to provide for a special letter of credit facility in the amount of $25 million which combined with the existing letter of credit sub-limit of $55 million would allow a total of $80 million in letters of credit. This amendment also permitted the Company to enter into the transactions to sell oil and gas leases in Ohio during 2003. 30 The Revolver, as amended, is subject to certain financial covenants. These include a quarterly senior debt interest coverage ratio of 3.2 to 1 extended through March 31, 2006; and a senior debt leverage ratio of 2.7 to 1 extended through March 31, 2006. The amendment extended the early termination fee, equal to .125% of the Revolver, through June 30, 2005. There is no termination fee after June 30, 2005. The Company is required to hedge, through financial instruments or fixed price contracts, at least 20% but not more than 80% of its estimated hydrocarbon production, on a Mcfe basis, for the succeeding 12 months on a rolling 12-month basis. Based on the Company's hedges currently in place and its expected production levels, the Company is in compliance with this hedging requirement through September 2005. The Revolver, as amended, also contains other financial covenants. EBITDA, as defined in the Revolver, and consolidated interest expense on senior debt in these ratios are calculated quarterly based on the financial results of the previous four quarters. In addition, the Company is required to maintain a current ratio (including available borrowing capacity in current assets, excluding current debt and accrued interest from current liabilities and excluding any effects from the application of SFAS 133 to other current assets or current liabilities) of at least 1.0 to 1 and maintain liquidity of at least $5 million (cash and cash equivalents including available borrowing capacity). As of December 31, 2003, the Company's current ratio including the above adjustments was 3.46 to 1. The Company had satisfied all financial covenants as of December 31, 2003. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At December 31, 2003, the interest rate was 6.00%. At December 31, 2003, the Company had $38.7 million of outstanding letters of credit. At December 31, 2003, the outstanding balance under the credit agreement was $47.4 million with $38.9 million of borrowing capacity available for general corporate purposes. As of February 29, 2004, there was $47.3 million outstanding under the Revolver, letters of credit commitments of $39.7 million and $38.0 million available for general corporate purposes. The Revolver is secured by security interests and mortgages against substantially all of the Company's assets and is subject to periodic borrowing base determinations. The borrowing base is the lesser of $100 million or the sum of (i) 65% of the value of the Company's proved developed producing reserves subject to a mortgage; (ii) 45% of the value of the Company's proved developed non-producing reserves subject to a mortgage; and (iii) 40% of the value of the Company's proved undeveloped reserves subject to a mortgage. The price forecast used for calculation of the future net income from proved reserves is the three-year NYMEX strip for oil and natural gas as of the date of the reserve report. Prices beyond three years are held constant. Prices are adjusted for basis differential, fixed price contracts and financial hedges in place. The weighted average price at December 31, 2003, was $4.87 per Mcfe. The present value (using a 10% discount rate) of the Company's future net income at December 31, 2003, using the borrowing base price forecast was $426 million. The present value under the borrowing base formula above, was approximately $253 million for all proved reserves of the Company and $174 million for properties secured by a mortgage. The Company has $225 million of 9 7/8% Senior Subordinated Notes outstanding as of December 31, 2003. The notes mature on 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 31 subordinated in right of payment to senior debt. The notes are subject to redemption at the option of the Company at specific redemption prices. June 15, 2003........................ 103.292% June 15, 2004........................ 101.646% June 15, 2005 and thereafter......... 100.000%
The notes were issued pursuant to an indenture which contains certain covenants that limit the ability of the Company and its subsidiaries to incur additional indebtedness and issue stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens and engage in mergers and consolidations. From time to time the Company may enter into interest rate swaps to hedge the interest rate exposure associated with the credit facility, whereby a portion of the Company's floating rate exposure is exchanged for a fixed interest rate. There were no interest rate swaps in 2003 or 2002. DERIVATIVE INSTRUMENTS On January 17 and 18, 2002, the Company monetized 9,350 Bbtu (billion British thermal units) of its 2002 natural gas hedge position at a weighted average NYMEX price of $2.53 per Mmbtu and 3,840 Bbtu of its 2003 natural gas hedge position at a NYMEX price of $3.01 per Mmbtu. The Company received net proceeds of $22.7 million, a portion of which was recognized as an increase to natural gas revenues during 2002, with the balance to be recognized in 2003 during the same periods in which the underlying forecasted transactions were recognized in net income (loss). In January 2002, the Company entered into a collar for 9,350 Bbtu of its natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a floor price of $2.25 per Mmbtu. The Company also sold a floor at $1.75 per Mmbtu on this volume of gas. This aggregate structure had the effect of: 1) setting a maximum price of $4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per Mmbtu; 3) locking in a price of $2.25 per Mmbtu if prices are between $1.75 and $2.25 per Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the price if the price is $1.75 or less. All prices are based on monthly NYMEX settle. The Company paid $1.0 million for the options in 2002. The Company used the net proceeds of $21.7 million from the two transactions above to pay down on its credit facility. The following table summarizes, as of December 31, 2003, the Company's deferred gains on natural gas hedges terminated in 2002. Cash has been received and the deferred gains recorded in accumulated other comprehensive income. The deferred gains have been recognized as increases to gas revenues during the same periods in which the underlying forecasted transactions were recognized in net income (loss).
FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER TOTAL ------- ------- ------- ------- ------- (IN THOUSANDS) 2003 $ 723 $ 865 $ 771 $ 585 $ 2,944
To manage its exposure to natural gas or oil price volatility, the Company may partially hedge its physical gas or oil sales prices by selling futures contracts on the NYMEX or by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company 32 believes are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options. In March 2003, the Company entered into a collar for 4,320 Bbtu of its natural gas production in 2004 with a ceiling price of $5.80 per Mmbtu and a floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.00 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $5.80 per Mmbtu; 2) floating at prices from $4.00 to $5.80 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.00 and $4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu above the price if the price is $3.00 or less. All prices are based on monthly NYMEX settle. In April 2003, the Company entered into a collar for 6,000 Bbtu of its natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.10 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.10 and $4.00 per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if the price is $3.10 or less. All prices are based on monthly NYMEX settle. The Company's financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Accordingly, the Company may modify its fixed price contract and financial hedging positions by entering into new transactions or terminating existing contracts. The following tables reflect the natural gas volumes and the weighted average prices under financial hedges (including settled hedges) and fixed price contracts at February 29, 2004:
NATURAL GAS SWAPS NATURAL GAS COLLARS FIXED PRICE CONTRACTS ------------------------------------- ---------------------------------------- ------------------------- ESTIMATED NYMEX PRICE ESTIMATED ESTIMATED NYMEX PRICE WELLHEAD PER MMBTU WELLHEAD PRICE ESTIMATED WELLHEAD QUARTER ENDING BBTU PER MMBTU PRICE PER MCF BBTU FLOOR/CAP (1) PER MCF (1) MMCF PRICE PER MCF ------------------ ----- ----------- ------------- ----- ------------- -------------- --------- ------------- March 31, 2004 2,040 $ 3.84 $ 4.09 1,080 $ 4.00 - 5.80 $ 4.25 - 6.05 54 $ 4.10 June 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 37 4.06 September 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 - - December 31, 2004 2,040 3.84 4.06 1,080 4.00 - 5.80 4.22 - 6.02 - - ----- ----------- ------------- ----- ------------- -------------- --------- ------------- 8,160 $ 3.84 $ 4.03 4,320 $ 4.00 - 5.80 $ 4.19 - 5.99 91 $ 4.08 ===== =========== ============= ===== ============= ============== ========= ============= March 31, 2005 1,500 $ 3.84 $ 4.09 1,500 $ 4.00 - 5.37 $ 4.25 - 5.62 June 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52 September 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52 December 31, 2005 1,500 3.73 3.95 1,500 4.00 - 5.37 4.22 - 5.59 ----- ----------- ------------- ----- ------------- -------------- 6,000 $ 3.76 $ 3.95 6,000 $ 4.00 - 5.37 $ 4.19 - 5.56 ===== =========== ============= ===== ============= ==============
MCF - THOUSAND CUBIC FEET MMBTU - MILLION BRITISH THERMAL UNITS MMCF - MILLION CUBIC FEET BBTU - BILLION BRITISH THERMAL UNITS (1) The NYMEX price per Mmbtu floor/cap and the estimated wellhead price per Mcf for the natural gas collars in 2004 assume the monthly NYMEX settles at $3.00 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.00 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $1.00 and the estimated wellhead price per Mcf will be the NYMEX settle plus $1.15 to $1.25. The NYMEX price per Mmbtu floor/cap and the estimated wellhead price per Mcf for the natural gas collars in 2005 assume the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.10 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90 and the estimated wellhead price per Mcf will be the NYMEX settle plus $1.05 to $1.15. 33 INFLATION AND CHANGES IN PRICES The average price of the Company's natural gas increased from $4.35 per Mcf in 2001 to $4.95 per Mcf in 2002, then decreased to $4.93 in 2003. During 2001, the price paid for the Company's crude oil fluctuated between a low of $13.50 per barrel and a high of $28.50 per barrel, with an average price of $23.04 per barrel. During 2002, the price paid for the Company's crude oil increased from $16.25 per barrel at the beginning of the year to $27.50 per barrel at year-end, with an average price of $22.72 per barrel. During 2003, the price paid for the Company's crude oil fluctuated between a low of $22.00 per barrel and a high of $34.25 per barrel, with an average price of $28.06 per barrel. These prices reflect average prices for oil and gas sales of the Company's continuing operations. The natural gas prices include the effect of the Company's hedging activity. The price of oil and natural gas has a significant impact on the Company's results of operations. Oil and natural gas prices fluctuate based on market conditions and, accordingly, cannot be predicted. Costs to drill, complete and service wells can fluctuate based on demand for these services which is generally influenced by high or low commodity prices. The Company's costs and expenses may be subject to inflationary pressures if oil and gas prices are favorable. A large portion of the Company's natural gas is sold subject to market sensitive contracts. Natural gas price risk is mitigated (hedged) by the utilization of over-the-counter NYMEX swaps, options or collars. Natural gas price hedging decisions are made in the context of the Company's strategic objectives, taking into account the changing fundamentals of the natural gas marketplace. CONTRACTUAL OBLIGATIONS The Company has various commitments primarily related to leases for office space, vehicles, natural gas compressors and computer equipment. The Company expects to fund these commitments with cash generated from operations. The Company has no off-balance sheet debt or other such unrecorded obligations, and has not guaranteed the debt of any other party. The following table summarizes the Company's contractual obligations at December 31, 2003.
PAYMENTS DUE BY PERIOD -------------------------------------------------------------------- CONTRACTUAL OBLIGATIONS AT LESS THAN 1 AFTER 5 DECEMBER 31, 2003 TOTAL YEAR 1 - 3 YEARS 4 - 5 YEARS YEARS ---------------------------------- --------- ----------- ------------ ----------- --------- (IN THOUSANDS) Long term debt $ 272,508 $ 5 $ 47,418 $ 225,015 $ 70 Capital lease obligations 208 100 71 37 - Operating leases 10,784 3,465 5,180 2,139 - --------- ----------- ------------ ----------- --------- Total contractual cash obligations $ 283,500 $ 3,570 $ 52,669 $ 227,191 $ 70 ========= =========== ============ =========== =========
In addition to the items above, the Company has an employment agreement with its Chief Executive Officer, a retention plan, a severance plan and a change of control plan. See "Executive Compensation - Employment and Severance Agreements" in Item 11 of this Report. The Company has entered into joint operating agreements, area of mutual interest agreements and joint venture agreements with other companies. These agreements may include drilling commitments or other obligations in the normal course of business. 34 The following table summarizes the Company's commercial commitments at December 31, 2003.
AMOUNT OF COMMITMENT EXPIRATION PER PERIOD --------------------------------------------------- TOTAL COMMERCIAL COMMITMENTS AT AMOUNTS LESS THAN 1 OVER 5 DECEMBER 31, 2003 COMMITTED YEAR 1 - 3 YEARS 4 - 5 YEARS YEARS ---------------------------- --------- ----------- ----------- ----------- ------ (IN THOUSANDS) Standby Letters of Credit $ 38,650 $ 38,650 $ - $ - $ - --------- ----------- ----------- ----------- ------ Total Commercial Commitments $ 38,650 $ 38,650 $ - $ - $ - ========= =========== =========== =========== ======
In the normal course of business, the Company has performance obligations which are supported by surety bonds or letters of credit. These obligations are primarily site restoration and dismantlement, royalty payments and exploration programs where governmental organizations require such support. The Company also has letters of credit with its hedging counterparty. The Company has certain other commitments and uncertainties related to its normal operations, including any obligation to plug wells. FORWARD-LOOKING INFORMATION The forward-looking statements regarding future operating and financial performance contained in this report involve risks and uncertainties that include, but are not limited to, the Company's availability of capital, production and costs of operation, the market demand for, and prices of oil and natural gas, results of the Company's future drilling, the uncertainties of reserve estimates, environmental risks, availability of financing and other factors detailed in the Company's filings with the SEC. Actual results may differ materially from forward-looking statements made in this report. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Among other risks, 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, 2003, 2002 and 2001. If market interest rates for short-term borrowings increased 1%, the increase in the Company's interest expense would be approximately $474,000. This sensitivity analysis is based on the Company's financial structure at December 31, 2003. The commodity price risk relates to natural gas and crude oil produced, held in storage and marketed by the Company. The Company's financial results can be significantly impacted as commodity prices fluctuate widely in response to changing market forces. From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to commodity price volatility. The fixed-price physical contracts generally have terms of a year or more. The Company employs a policy of hedging gas production sold under NYMEX based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. If NYMEX gas prices decreased $0.50 per Mcf, the Company's 35 gas sales revenues would decrease by $3.3 million, after considering the effects of the hedging contracts in place at December 31, 2003. The Company had no hedges or fixed price contracts on its oil production during 2003. If the price of crude oil decreased $3.00 per Bbl, the Company's oil sales revenues would decrease by $1.2 million. This sensitivity analysis is based on the Company's 2003 oil and gas sales volumes and assumes the NYMEX gas price would be within the collars in 2004 listed in the table on page 33. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Index to Consolidated Financial Statements and Schedules on page F-1 sets forth the financial statements included in this Annual Report on Form 10-K and their location herein. Schedules have been omitted as not required or not applicable because the information required to be presented is included in the financial statements and related notes. The financial statements have been prepared by management in conformity with accounting principles generally accepted in the United States. Management is responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary to make informed estimates and judgments based on currently available information on the effects of certain events and transactions. The Company maintains accounting and other controls which management believes provide reasonable assurance that financial records are reliable, assets are safeguarded and that transactions are properly recorded. However, limitations exist in any system of internal control based upon the recognition that the cost of the system should not exceed benefits derived. The Company's independent auditors, Ernst & Young LLP ("E&Y"), are engaged to audit the financial statements and to express an opinion thereon. Their audit is conducted in accordance with auditing standards generally accepted in the United States to enable them to report whether the financial statements present fairly, in all material respects, the financial position and results of operations in accordance with accounting principles generally accepted in the United States. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. ITEM 9A. CONTROLS AND PROCEDURES The Company's management, with the participation of the Company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the Company's disclosure controls and procedures as of December 31, 2003. Based on that evaluation, the Company's Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures were effective as of December 31, 2003. There were no changes in the Company's internal control over financial reporting during the fourth quarter of 2003 that materially affected, or are reasonably likely to affect, the Company's internal control over financial reporting. 36 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Executive officers and directors of the Company as of March 5, 2004 were as follows:
Name Age Position --------------------- ---- ---------------------------------------------------------- John L. Schwager 55 President, Chief Executive Officer and Director R. Mark Hackett 41 Senior Vice President Geoscience and Engineering Richard R. Hoffman 53 Senior Vice President Operations Robert W. Peshek 49 Senior Vice President and Chief Financial Officer David M. Becker 42 Vice President and General Manager, Michigan Exploration and Production District Duane D. Clark 48 Vice President Legal Affairs/Gas Marketing John G. Corp 44 Vice President and General Manager, Arrow Oilfield Service Company Patricia A. Harcourt 40 Vice President Administration Frederick J. Stair 44 Vice President and Corporate Controller Lawrence W. Kellner 45 Director Robert S. Maust 66 Director William S. Price, III 47 Director Gareth Roberts 51 Director Jeffrey C. Smith 42 Director
All executive officers of the Company serve at the pleasure of its Board of Directors. None of the executive officers of the Company is related to any other executive officer or director. The Board of Directors consists of six members each of whom is elected annually to serve one-year terms. The business experience of each executive officer and director is summarized below. JOHN L. SCHWAGER has been Chief Executive Officer of the Company since June of 1999. Mr. Schwager was elected to the Board of Directors in August of 1999 and was appointed to the additional position of President in September 1999. He has over 35 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 - 37 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 by Callon Petroleum Company in Natchez, Mississippi, serving as the Vice President of Production from 1982 to 1984. 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, is a current a member and past director of the Ohio Oil and Gas Association and is a current member of the Independent Petroleum Association of America. He also was the cofounder of the Oil and Gas Political Action Committee of West Virginia, serving as co-chairman for many years. R. MARK HACKETT joined the Company as Senior Vice President of Geoscience and Engineering in December of 2003. He has over 15 years of extensive experience in drilling, engineering and producing operations in the Appalachian Basin. Prior to joining the Company, Mr. Hackett held various positions at Columbia Natural Resources, Inc. from 1997 to 2003, including Vice President of Operations. From 1988 to 1997, he was employed by Alamco, Inc., where he last held the position of Vice President of Engineering. Mr. Hackett graduated from West Virginia University in 1985 with a Bachelor of Science degree in Petroleum and Natural Gas Engineering. RICHARD R. HOFFMAN joined the Company as Senior Vice President of Exploration and Production in March of 2001. As of December, 2003 Mr. Hoffman became Senior Vice President of Operations. Mr. Hoffman has worked in the oil and gas industry for 31 years and has extensive operational experience in the Appalachian Basin. From 1998 to 2000, he served as Manager of Production for Dominion Appalachian Development Inc., a subsidiary of Dominion Resources, Inc., specializing in natural gas exploration and production. From 1982 to 1997, he was Executive Vice President and Chief Operating Officer of Alamco, Inc., and served on its Board of Directors from 1988 to 1997. Mr. Hoffman served as Superintendent Production and Drilling/Field Engineer for Cabot Oil and Gas Corporation from 1980 to 1982, and from 1977 to 1980 he was employed by Flint Oil and Gas, Inc., as a Field Engineer. From 1973 to 1977, he held the title of Assistant Production Superintendent/Engineer with The Wiser Oil Company. Mr. Hoffman graduated from West Virginia University with a Bachelor of Science degree in Geology. He is affiliated with numerous oil and gas associations including the Ohio Oil and Gas Association, the West Virginia Oil and Natural Gas Association and the Independent Oil and Gas Association of West Virginia where he served as a Director from 1995 to 1997. He is also a member of the Society of Petroleum Engineers. ROBERT W. PESHEK has been elected by the Board of Directors as Senior Vice President of the Company in December 2003. Previously, he served as Vice President of Finance for the Company since 1997 and in 1999 was appointed Chief Financial Officer. Prior to that, 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. 38 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 22 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. DUANE D. CLARK has been Vice President of Legal Affairs/Gas Marketing for the Company since April 2001. Previously, he served as Vice President of Gas Marketing. He joined the Company in 1995 as a Gas Marketing Analyst. Prior to joining the Company, Mr. Clark held various management positions with Quaker State Corporation from 1978 to 1995. He has 25 years of experience in the oil and gas industry. Mr. Clark received his Bachelor of Arts degree in Mathematics and Economics from Ohio Wesleyan University. His professional affiliations include the Ohio Oil and Gas Association and the Pennsylvania Oil and Gas Association. JOHN G. CORP was appointed Vice President of the Company in May 2000, and has been the General Manager of Arrow Oilfield Service Company, the Company's oilfield service division, since November 1999. Prior to that he served as General Manager of the Company's Southern Ohio Exploration and Production 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 25 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. PATRICIA A. HARCOURT was appointed Vice President of Administration of the Company in January 2003. Previously she served as Director of Administration from 2001 to 2003 and Director of Corporate Communications from 1994 to 2001. She joined the Company in 1988 as Investor Relations Coordinator. Prior to joining the company, Ms. Harcourt was employed by Austin Powder Company as Employee Relations Administrator. She received her Bachelor of Arts degree in Communications from Bowling Green State University. She has 16 years of experience in the oil and gas industry and is a member of the Ohio Oil and Gas Association. Ms. Harcourt is also a member of the National Investor Relations Institute and the Society for Human Resource Management. FREDERICK J. STAIR was appointed Vice President of the Company in January 2003 and has been the Corporate Controller since 1997. Prior to that date he served as Controller of the Exploration and Production Division from 1991 to 1997. Mr. Stair joined the Company in 1981 and has 23 years of accounting experience in the oil and gas industry. He graduated from the University of Akron where he received a Bachelor of Science degree in Accounting. Mr. Stair is a member of the Petroleum Accountants Society of Appalachia. LAWRENCE W. KELLNER has been a director since 1997. He has been President and Chief Operating Officer of Continental Airlines, Inc. since May 2003. He was President (May 2001-March 2003) and Executive Vice President and Chief Financial Officer (November 1996-May 2001). Mr. Kellner graduated magna cum laude with a Bachelor of Science, Business Administration degree from the University of South Carolina. Mr. Kellner is also a director of Continental Airlines, Inc., Express Jet Holdings, Inc., and Mariott International, Inc. 39 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 Director of the Division of Accounting for 15 years. He has been a professor at the University since 1963 and has received numerous teaching and professional honors during his 40-year career. He has published several papers and has contributed to various books and manuals on accounting and business. Mr. Maust is a Certified Public Accountant and has served as an officer of several state, regional and national professional organizations. He received his Bachelor and Master degrees from West Virginia University and Certificate of Ph.D. Candidacy from the University of Michigan. From 1987 to 1997, he served on the Board of Directors of Alamco, Inc., an Appalachian Basin-based firm engaged in the acquisition, exploration, development and production of domestic gas and oil. WILLIAM S. PRICE, III, who became a director upon TPG's investment in 1997, was a founding partner of Texas Pacific Group in 1992. Prior to forming Texas Pacific, Mr. Price was Vice President of Strategic Planning and Business Development for G.E. Capital, reporting to the Chairman. In this capacity, Mr. Price was responsible for acquiring new business units and determining the business and acquisition strategies for existing businesses. From 1985 to 1991, Mr. Price was employed by the management consulting firm of Bain & Company, attaining officer status and acting as co-head of the Financial Services Practice. Prior to 1985, Mr. Price was employed as an associate specializing in corporate securities transactions with the legal firm of Gibson, Dunn & Crutcher. Mr. Price is a member of the California Bar and graduated with honors in 1981 from the Boalt Hall School of Law at the University of California, Berkeley. He is a 1978, Phi Beta Kappa graduate of Stanford University. Mr. Price serves on the Board of Directors of Del Monte Foods Company, Denbury Resources, Inc., Gemplus International, S.A., Petco, and several private companies. GARETH ROBERTS has been a director since 1997. He has been President, Chief Executive Officer and a director of Denbury Resources, Inc. ("Denbury") since 1992. Mr. Roberts founded Denbury Management, Inc., the former operating subsidiary of Denbury in April 1990. Mr. Roberts has more than 28 years of experience in the exploration and development of oil and gas properties with Texaco, Inc., Murphy Oil Corporation and Coho Resources, Inc. His expertise is particularly focused in the Gulf Coast region where he specializes in the acquisition and development of old fields with low productivity. Mr. Roberts holds honors and masters degrees from St. Edmund Hall, Oxford University, where he has been elected to an Honorary Fellowship. Mr. Roberts also serves as chairman of the board of directors of Genesis Energy, L.P. 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 11 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. AUDIT COMMITTEE The primary purpose of the Audit Committee is to assist the Board of Directors' oversight of (1) the integrity of the Company's financial statements, (2) the Company's compliance with legal and regulatory requirements, (3) the independent auditor's qualifications and independence, and (4) the performance of the Company's internal audit function and independent auditors. The Audit Committee is solely responsible for the appointment and compensation of the Company's independent auditors. The 40 Audit Committee operates under a written charter adopted and approved by the Board of Directors. The Audit Committee is composed of three members of the Board of Directors, Messrs. Kellner, Smith and Maust. Mr. Kellner is the Audit Committee Chairman and has been designated by the Board of Directors as the "audit committee financial expert" as described in Item 401(h) of Regulation S-K. In addition, the Board of Directors has determined that Messrs. Kellner and Maust are "independent audit committee members" as defined in the listing standards for the New York Stock Exchange. Mr. Smith is not independent. Mr. Smith is employed by TPG, a significant stockholder of the Company. TPG is deemed to be an affiliate of the Company as a result of its controlling ownership of the Company. However, the Board of Directors has determined that Mr. Smith's membership on the committee is required by the best interests of the Company. The Committee meets periodically with the Company's independent auditors, Ernst & Young, LLP, representatives of the Company's internal audit staff and management to review financial statements and the results of audit activities. REPORT OF THE AUDIT COMMITTEE The Audit Committee oversees the Company's financial reporting process on behalf of the Board of Directors. Management has the primary responsibility for the financial statements and the reporting process including the systems of internal controls. In fulfilling its oversight responsibilities, the Committee reviewed the audited financial statements in the Annual Report with management including a discussion of the quality, not just the acceptability, of the accounting principles, the reasonableness of significant judgments, and the clarity of disclosures in the financial statements. The Committee reviewed with the independent auditors, who are responsible for expressing an opinion on the conformity of those audited financial statements with generally accepted accounting principles, their judgments as to the quality, not just the acceptability, of the Company's accounting principles and such other matters as are required to be discussed with the Committee by Statement on Auditing Standards No. 61, as amended by Statement on Auditing Standards No. 90 (Communication With Audit Committees). In addition, the Committee has discussed with the independent auditors the auditors' independence from management and the Company, including the matters in the written disclosures required by Independence Standards Board Standard No. 1, and considered the compatibility of nonaudit services with the auditors' independence. The Committee discussed with the Company's internal and independent auditors the overall scope and plans for their respective audits. The Committee meets with the internal and independent auditors, with and without management present, to discuss the results of their examinations, their evaluations of the Company's internal controls, and the overall quality of the Company's financial reporting. In reliance on the reviews and discussions referred to above, the Committee recommended to the Board of Directors (and the Board has approved) that the audited financial statements be included in the Annual Report on Form 10-K for the year ended December 31, 2003 for filing with the Securities and Exchange Commission. The Committee and the Board have also recommended the selection of the Company's independent auditors. 41 The Committee is governed by a charter. The committee held four meetings during the year 2003. Lawrence W. Kellner, Audit Committee Chairman Robert S. Maust, Audit Committee Member Jeffrey C. Smith, Audit Committee Member March 12, 2004 The Company has adopted a Code of Ethics that applies to its Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Corporate Controller and any person performing similar functions. The Company's Code of Ethics is attached as Exhibit 14.1 to this Form 10-K. 42 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, 2003, 2002 and 2001 of the Company's Chief Executive Officer and its other four most highly compensated executive officers. SUMMARY COMPENSATION TABLE
Long-Term Compensation Annual Compensation Awards ------------------------------------------------- ------------ No. of Shares Other Annual Underlying All Other Name and Principal Position Year Salary Bonus Compensation Options/SARs Compensation (1) --------------------------- ---- ------ ----- ------------ ------------ ---------------- John L. Schwager 2003 $ 349,327 $ 540,000 (3) $ - - $ 10,000 President and 2002 325,000 573,750 - - 10,500 Chief Executive Officer 2001 317,692 292,277 - 100,000 8,500 Richard R. Hoffman (4) 2003 207,111 52,075 - - 5,941 Senior Vice President of 2002 198,000 39,600 - - 5,000 Exploration and Production 2001 145,385 83,769 - 82,500 43,742 (2) Robert W. Peshek 2003 178,924 63,108 - - 10,000 Senior Vice President and 2002 168,308 58,910 - - 9,187 Chief Financial Officer 2001 164,915 90,703 - 17,500 8,500 David M. Becker 2003 159,130 30,741 - - 9,133 Vice President of 2002 154,707 23,200 - - 9,187 Michigan Operations 2001 139,644 41,893 - - 7,831 Duane D. Clark 2003 109,502 33,092 - - 7,202 Vice President of Legal 2002 103,310 36,160 - - 7,953 Affairs and Gas Marketing 2001 101,371 55,754 - - 6,328 Barry K. Lay (5) 2003 129,423 19,500 - - - 2002 - - - - - 2001 - - - - -
(1) Represents contributions of cash and common stock to the Company's 401(k) Sharing Plan for the account of the named executive officer. (2) Includes moving expenses of $41,373. (3) This consists of an annual performance bonus of $210,000 and an annual retention bonus of $330,000 paid to Mr. Schwager on June 30, 2003. For financial statement purposes the Company has accrued an additional retention bonus of $165,000 for the period July 1, 2003 through December 31, 2003. (4) Mr. Hoffman joined the Company in March 2001. (5) Mr. Lay was not an Executive Officer as of December 31, 2003, as he moved into an operations role. 43 AGGREGATED OPTION/SAR EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION/SAR VALUES
Number of Shares Value of Unexercised Underlying Unexercised In-the-Money Shares Options/SARs at FY-End Options/SARs at FY-End Acquired on Value ----------------------- -------------------------- Name Exercise Realized Exercisable Unexercisable Exercisable Unexercisable ---- -------- -------- ----------- ------------- ----------- ------------- John L. Schwager 97,915 $ 105,653 25,000 29,353 $ 45,625 $ 61,971 Richard R. Hoffman - - 41,250 41,250 75,281 75,281 Robert W. Peshek 15,000 31,950 62,500 8,750 223,050 15,969 David M. Becker - - 25,000 - 96,875 - Duane D. Clark - - 30,000 - 116,650 - Barry K. Lay - - 11,875 18,125 21,627 33,078
COMPENSATION OF DIRECTORS The outside directors of the Company are compensated $7,500 per quarter for their services. Directors employed by the Company or by TPG are not compensated for their services. EMPLOYMENT AND SEVERANCE AGREEMENTS Effective July 1, 2001, John Schwager's employment agreement with the Company was amended and restated (the "Agreement"). The term of the Agreement is for three years, subject to extension by mutual agreement. Under the Agreement, Mr. Schwager is entitled to base compensation of $325,000 per annum beginning July 1, 2001 with an increase of $25,000 beginning on January 1, 2003. The Agreement provides for an incentive based bonus, at the discretion of the Board of Directors, of up to 100% of base compensation. There is no minimum incentive based bonus established in the Agreement. The Agreement also provides for an annual retention bonus of $330,000 each year during the term of the Agreement. The annual retention bonus is accelerated and payable in the event of change in control which is defined as any occurrence which would cause TPG's fully diluted equity ownership to drop below 35%. The Agreement further provides for a special retention bonus of $1,000,000, should a change of control occur during or within six months after the expiration of the Agreement, unless Mr. Schwager is employed as the chief executive officer of the surviving company. Either Mr. Schwager or the Company may terminate the Agreement at any time, with or without cause. If Mr. Schwager terminates his employment or is removed for cause, he will not be entitled to receive any compensation or severance pay except for the base compensation, benefits, bonuses and expense reimbursements that have accrued up to and including the final day of his employment with the Company. If the Company terminates Mr. Schwager's employment without cause or if he resigns for good reason (as defined in the Agreement), Mr. Schwager will be entitled to receive monthly payments of 150% of his base salary plus the remaining annual retention bonus payments and continued health care benefits at the Company's expense for two years. In the event of a change of control, all of the aforementioned payments become due and payable at the closing. With the exception of the cost of health care benefits, the amounts payable to Mr. Schwager as outlined above cannot exceed $1,990,000. Mr. Schwager is also entitled to receive an additional payment plus any associated interest and penalties (the "gross up") sufficient to cover any tax imposed by Section 4999 of the Internal Revenue Code on payments made under the Agreement. 44 On February 7, 2001, Mr. Schwager was granted an option to purchase 25,000 shares of the common stock of the Company at $3.59 per share which were repriced on December 5, 2001 at $2.14 per share. He was also granted an option to purchase 75,000 shares of the common stock of the Company on December 5, 2001 at $2.14 per share. One fourth of the option shares shall become exercisable on the last day of each calendar quarter commencing June 30, 2003, provided that he is then an employee or director of the Company. On December 21, 2001, the Company and Leo A. Schrider entered into a Letter of Agreement for Mr. Schrider's transition into retirement. During the transition period from January 2, 2002 through December 31, 2003, Mr. Schrider worked as a part-time employee of the Company. During the transition period, Mr. Schrider received the full base salary per year that he was receiving as of December 31, 2001. In February 2004, the Company entered into a retention plan effective until December 31, 2006, for certain executive officers that provides for a retention bonus payable six months after a change of control event (as defined in the plan). The purpose of the plan is to promote a stable management team during the period preceding and immediately following a potential change of control event. Under the plan, Messrs. Becker, Clark, Hoffman and Peshek would be eligible for a retention bonus (as defined in the plan) after a change of control event. Under the Company's 1999 Severance Pay Plan, all employees whose employment is terminated by the Company without "cause" (as defined therein) are eligible to receive severance benefits ranging from four weeks to twenty-four months, depending on their years of service and position with the Company. Under the Plan, Messrs. Becker, Clark, Hoffman and Peshek would be eligible to receive severance pay ranging from twelve months to twenty-four months. The Company has a 1999 Change in Control Protection Plan for Key Employees providing severance benefits for such employees if, within six months prior to a change in control or within two years thereafter, their employment is terminated without "cause" (as defined therein) or if they resign in response to a reduction in duties, responsibilities, position, compensation or medical benefits or a change in the location of their place of work as defined in the agreement. Such benefits range from twelve months to twenty-four months, depending on their position with the Company. Under the Plan, Messrs. Becker, Clark, Hoffman and Peshek would be eligible to receive severance pay of twenty-four months. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION The Compensation and Organization Committee consisted of two outside directors, William S. Price, III and Gareth Roberts. No executive officer of the Company was a director or member of a compensation committee of any entity of which a member of the Company's Board of Directors was or is an executive member. 45 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS The following table sets forth certain information as of February 29, 2004 regarding the beneficial ownership of the Company's common stock by each person who beneficially owns more than five percent of the Company's outstanding common stock, each director, the chief executive officer and the four other most highly compensated executive officers and by all directors and executive officers of the Company, as a group:
PERCENTAGE OF FIVE PERCENT SHAREHOLDERS NUMBER OF SHARES SHARES ------------------------- ---------------- ------ TPG Advisors II, Inc. 201 Main Street, Suite 2420 Fort Worth, Texas 76102 9,353,038 (1) 86.9% State Treasurer of the State of Michigan, Custodian of the Public School Employees' Retirement System, State Employees Retirement System, Michigan State Police Retirement System and Michigan Judges Retirement System 430 West Allegan Lansing, MI 48922 554,376 5.2% OFFICERS AND DIRECTORS ---------------------- William S. Price, III 9,353,038 (1) 86.9% John L. Schwager 309,075 (2) 2.9% Lawrence W. Kellner -0- -0- Gareth Roberts -0- -0- Robert S. Maust -0- -0- Jeffrey C. Smith -0- -0- Richard R. Hoffman 46,406 (2) * Robert W. Peshek 92,344 (2) * David M. Becker 30,000 (2) * Duane D. Clark 30,000 (2) * All directors and executive officers (14) as a group 9,916,802 92.2%
* Less than 1% (1) Neither TPG Advisors II, Inc. nor Mr. Price is the record owner of any shares of the Company's common stock. Mr. Price is, however, a director, executive officer and shareholder of TPG Advisors II, Inc., which is the general partner of TPG GenPar II, L.P., which in turn is the general partner of each of TPG Partners II, L.P., TPG Investors II, L.P. and TPG Parallel II, L.P. which are the direct beneficial owners of 7,976,645, 832,047 and 544,346 shares of common stock, respectively. (2) Consists of shares subject to stock options exercisable within 60 days by Mr. Schwager as to 29,353 shares, Mr. Hoffman as to 46,406 shares, Mr. Peshek as to 63,594 shares, Mr. Becker as to 25,000 shares and Mr. Clark as to 30,000 shares. 46 EQUITY COMPENSATION PLAN INFORMATION:
Weighted- Number of securities Number of average remaining available securities to be exercise price for future issuance issued upon of under equity exercise of outstanding compensation plans outstanding options, (excluding securities options, warrants warrants and reflected in column Plan category and rights rights (a)) ------------- ----------------- ------------- --------------------- (a) (b) (c) Equity compensation plans approved by security holders - $ - - Equity compensation plans not approved by security holders 616,321 $ 1.29 733,394
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, 2003, options to purchase 616,321 shares were outstanding under the plan. These options, except for the 100,000 options described below, become exercisable at a rate of one fourth of the shares one year from the date of grant and an additional one twelfth of the remaining shares on every calendar quarter-end thereafter. The remaining 100,000 options become exercisable at a rate of one fourth of the shares on the last day of each quarter commencing June 30, 2003. 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. TPG has advised the Company that it has waived its fees under this agreement for acquisition and sale transactions in all years prior to 2002. TPG was paid a transaction fee pursuant to this agreement for the $16.2 million sale of the properties in New York and Pennsylvania in December 2002. The fee amounted to $238,000 which was accrued in 2002 and paid in 2003. TPG waived the fee on all other acquisition and sale transactions in 2003 and 2002. 47 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES Ernst & Young served as the Company's independent auditor for the year ended December 31, 2003. Aggregate fees for professional services provided to the Company by Ernst & Young for the years ended December 31, 2003 and 2002 were as follows:
DECEMBER 31, ------------------------ 2003 2002 ---- ---- Audit fees $ 187,000 $ 192,245 Audit-related fees - 4,500 Tax fees 41,120 54,700 Other fees 1,600 1,500 --------- --------- $ 229,720 $ 252,945 ========= =========
Fees for audit services include fees associated with the annual audit and the reviews of the Company's quarterly reports on Form 10-Q. Audit-related fees principally included accounting consultation. Tax fees included tax compliance and tax planning. Other fees include research materials. AUDIT COMMITTEE PRE-APPROVAL POLICIES AND PROCEDURES The Audit Committee has adopted a policy that requires advance approval of all audit, audit-related, and other services performed by the independent auditor or other public accounting firms. The policy provides for pre-approval by the Audit Committee of specifically defined audit and non-audit services. Unless the specific service has been previously pre-approved with respect to that year, the Audit Committee must approve the permitted service before the independent auditor or public accounting firm is engaged to perform it. The Audit Committee has delegated to the Chairman of the Audit Committee authority to approve permitted services up to $75,000 per year provided that the Chairman reports any decisions to the Committee at its next scheduled meeting. All services of $75,000 or more are required to be approved by a majority of the Committee members. PART IV ITEM 15. 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 48 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). 10.1(a) Peake Energy, Inc. Stock Purchase Agreement between the Company and North Coast Energy, Inc. --incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000. 10.1(b) Credit Agreement dated as of August 23, 2000 by and among the Company, Ableco Finance LLC and Foothill Capital Corporation. --incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2000. 10.1(c) Amendment to the Credit Agreement dated as of June 29, 2001 by and among the Company, Ableco Finance LLC and Foothill Capital Corporation.--incorporated by reference to Exhibit 10.1(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 2001. 10.1(d) Amendment to the Credit Agreement dated as of July 25, 2002 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 June 30, 2002. 49 10.1(e) Amendment to the Credit Agreement and Waiver dated as of December 5, 2002 by and among the Company, Ableco Finance LLC and Foothill Capital Corporation.-- incorporated by reference to Exhibit 10.1 (e) to the Company's Annual Report on Form 10-K for the year ended December 31, 2002. 10.1(f) Amendment to the Credit Agreement dated as of March 31, 2003 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 March 31, 2003. 10.1(g) Amendment to the Credit Agreement dated as of May 30, 2003 by and among the Company, Ableco Finance LLC and Foothill Capital Corporation.--incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K dated May 30, 2003. 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. 10.7(a) Amendment No. 1 of the Belden & Blake Corporation 1999 Change in Control Protection Plan for Key Employees dated as of February 26, 2002.--incorporated by reference to Exhibit 10.7 (a) to the Company's Annual Report on Form 10-K for the year ended December 31, 2002. 10.7(b) Amendment No. 2 of the Belden & Blake Corporation 1999 Change in Control Protection Plan for Key Employees dated as of October 23, 2002.--incorporated by reference to Exhibit 10.7 (b) to the Company's Annual Report on Form 10-K for the year ended December 31, 2002. 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. 10.8(a) Amendment - 1 to the Belden & Blake Corporation 1999 Severance Pay Plan dated as of May 29, 2000.--incorporated by reference to Exhibit 10.8 (a) to the Company's Annual Report on Form 10-K for the year ended December 31, 2002. 50 10.8(b) Amendment - 2 to the Belden & Blake Corporation 1999 Severance Pay Plan dated as of September 12, 2002.--incorporated by reference to Exhibit 10.8 (b) to the Company's Annual Report on Form 10-K for the year ended December 31, 2002. 10.10 Employment Agreement dated June 1, 1999 and amended November 1, 1999 by and between the Company and John L. Schwager--incorporated by reference to Exhibit 10.10 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999. 10.11 Amended and Restated Employment Agreement dated July 1, 2001 by and between the Company and John L. Schwager--incorporated by reference to Exhibit 10.11 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001. 10.12 Letter of Agreement dated December 21, 2001 by and between the Company and Leo A. Schrider--incorporated by reference to Exhibit 10.12 to the Company's Annual Report on Form 10-K for the year ended December 31, 2001. 14.1* Code of Ethics for Senior Financial Officers. 21* Subsidiaries of the Registrant 23* Consent of Independent Auditors 31.1* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. * Filed herewith (b) Reports on Form 8-K On December 4, 2003, the Company filed a Current Report on Form 8-K dated December 1, 2003, reporting under Item 9 the Company's operational outlook for 2003. (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 15(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. 51 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 16, 2004 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 16, 2004 ---------------------------------- and Chief Executive Officer -------------- John L. Schwager (Principal Executive Officer) Date /s/ Robert W. Peshek Senior Vice President and March 16, 2004 ---------------------------------- Chief Financial Officer -------------- Robert W. Peshek (Principal Financial and Date Accounting Officer) /s/ Lawrence W. Kellner Director March 16, 2004 ---------------------------------- -------------- Lawrence W. Kellner Date /s/ Robert S. Maust Director March 16, 2004 ---------------------------------- -------------- Robert S. Maust Date /s/ William S. Price, III Director March 15, 2004 ---------------------------------- -------------- William S. Price, III Date /s/ Gareth Roberts Director March 16, 2004 ---------------------------------- -------------- Gareth Roberts Date /s/ Jeffrey C. Smith Director March 17, 2004 ---------------------------------- -------------- Jeffrey C. Smith Date
52 BELDEN & BLAKE CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES ITEM 15(a) (1) AND (2) CONSOLIDATED FINANCIAL STATEMENTS
Page Report of Independent Auditors.................................................................. F-2 Consolidated Balance Sheets as of December 31, 2003 and 2002.................................... F-3 Consolidated Statements of Operations: Years ended December 31, 2003, 2002 and 2001.................................................. F-4 Consolidated Statements of Shareholders' Equity (Deficit): Years ended December 31, 2003, 2002 and 2001.................................................. F-5 Consolidated Statements of Cash Flows: Years ended December 31, 2003, 2002 and 2001.................................................. F-6 Notes to Consolidated Financial Statements...................................................... F-7
All financial statement schedules have been omitted since the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements. F-1 REPORT OF INDEPENDENT AUDITORS To the Shareholders and Board of Directors Belden & Blake Corporation We have audited the accompanying consolidated balance sheets of Belden & Blake Corporation ("Company") as of December 31, 2003 and 2002, 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, 2003. 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, 2003 and 2002 and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States. As discussed in Note 1 to the consolidated financial statements, in 2003 the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, "Asset Retirement Obligations." ERNST & YOUNG LLP Cleveland, Ohio March 8, 2004 F-2 BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
DECEMBER 31, ---------------------------- 2003 2002 ---- ---- ASSETS CURRENT ASSETS Cash and cash equivalents $ 1,440 $ 1,722 Accounts receivable, net 17,597 14,652 Inventories 786 848 Deferred income taxes 6,853 4,200 Other current assets 2,415 1,341 Fair value of derivatives 319 - Assets of discontinued operations - 1,066 ---------- --------- TOTAL CURRENT ASSETS 29,410 23,829 PROPERTY AND EQUIPMENT, AT COST Oil and gas properties (successful efforts method) 464,262 438,240 Gas gathering systems 15,264 14,482 Land, buildings, machinery and equipment 23,107 22,748 ---------- --------- 502,633 475,470 Less accumulated depreciation, depletion and amortization 256,050 243,596 ---------- --------- PROPERTY AND EQUIPMENT, NET 246,583 231,874 FAIR VALUE OF DERIVATIVES 755 3 OTHER ASSETS 7,163 8,139 ---------- --------- $ 283,911 $ 263,845 ========== ========= LIABILITIES AND SHAREHOLDERS' DEFICIT CURRENT LIABILITIES Accounts payable $ 5,496 $ 5,661 Accrued expenses 15,393 17,767 Current portion of long-term liabilities 729 315 Fair value of derivatives 14,765 5,486 Liabilities of discontinued operations - 335 ---------- --------- TOTAL CURRENT LIABILITIES 36,383 29,564 LONG-TERM LIABILITIES Bank and other long-term debt 47,503 26,868 Senior subordinated notes 225,000 225,000 Other 4,629 91 ---------- --------- 277,132 251,959 FAIR VALUE OF DERIVATIVES 9,723 4,371 DEFERRED INCOME TAXES 18,013 22,596 SHAREHOLDERS' DEFICIT Common stock without par value; $.10 stated value per share; authorized 58,000,000 shares; issued 10,610,450 and 10,490,440 shares (which includes 214,593 and 194,890 treasury shares, respectively) 1,040 1,030 Paid in capital 107,633 107,118 Deficit (150,656) (148,332) Accumulated other comprehensive loss (15,357) (4,461) ---------- --------- TOTAL SHAREHOLDERS' DEFICIT (57,340) (44,645) ---------- --------- $ 283,911 $ 263,845 ========== =========
See accompanying notes. F-3 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ----------------------------------------- 2003 2002 2001 ---- ---- ---- REVENUES Oil and gas sales $ 85,023 $ 90,462 $ 89,491 Gas gathering, marketing, and oilfield service 23,741 21,624 27,348 Other 338 1,834 2,044 -------- --------- ----------- 109,102 113,920 118,883 EXPENSES Production expense 19,937 19,936 20,952 Production taxes 2,455 1,789 2,298 Gas gathering, marketing, and oilfield service 21,378 17,996 22,760 Exploration expense 16,882 16,256 8,335 General and administrative expense 4,559 4,557 4,395 Franchise, property and other taxes 282 91 238 Depreciation, depletion and amortization 19,343 22,379 25,979 Impairment of oil and gas properties 5,774 - 1,398 Accretion expense 365 - - Derivative fair value gain (319) - - Severance and other nonrecurring expense - 953 1,954 -------- --------- ----------- 90,656 83,957 88,309 -------- --------- ----------- OPERATING INCOME 18,446 29,963 30,574 OTHER EXPENSE Loss on sale of businesses - 154 - Interest expense 25,537 23,608 25,753 -------- --------- ----------- 25,537 23,762 25,753 -------- --------- ----------- (LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (7,091) 6,201 4,821 (Benefit) provision for income taxes (2,481) 2,456 (955) -------- --------- ----------- (LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (4,610) 3,745 5,776 (Loss) income from discontinued operations, net of tax (111) (1,280) 691 -------- --------- ----------- (LOSS) INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (4,721) 2,465 6,467 Cumulative effect of change in accounting principle, net of tax 2,397 - - -------- --------- ----------- NET (LOSS) INCOME $ (2,324) $ 2,465 $ 6,467 ======== ========= ===========
See accompanying notes. F-4 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT) (IN THOUSANDS)
ACCUMULATED OTHER TOTAL COMMON COMMON PAID IN COMPREHENSIVE EQUITY SHARES STOCK CAPITAL DEFICIT INCOME (DEFICIT) ------ -------- --------- ---------- ------------- ----------- JANUARY 1, 2001 10,303 $ 1,030 $ 107,921 $ (157,264) $ - $ (48,313) Comprehensive income: Net income 6,467 6,467 Other comprehensive income, net of tax: Cumulative effect of accounting change (6,691) (6,691) Change in derivative fair value 24,667 24,667 Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales (2,889) (2,889) ----------- Total comprehensive income 21,554 ----------- Stock options exercised 68 7 (1) 6 Stock-based compensation 275 275 Repurchase of stock options (772) (772) Tax benefit of repurchase of stock options and stock options exercised 260 260 Treasury stock (81) (8) (281) (289) ------ -------- --------- ---------- ------------- ----------- DECEMBER 31, 2001 10,290 1,029 107,402 (150,797) 15,087 (27,279) Comprehensive income: Net income 2,465 2,465 Other comprehensive income, net of tax: Change in derivative fair value (5,518) (5,518) Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales (14,030) (14,030) ----------- Total comprehensive income (17,083) ----------- Stock options exercised 65 7 (2) 5 Stock-based compensation 82 82 Repurchase of stock options (29) (29) Tax benefit of repurchase of stock options and stock options exercised 57 57 Treasury stock (59) (6) (392) (398) ------ -------- --------- ---------- ------------- ----------- DECEMBER 31, 2002 10,296 1,030 107,118 (148,332) (4,461) (44,645) Comprehensive income: Net loss (2,324) (2,324) Other comprehensive income, net of tax: Change in derivative fair value (17,439) (17,439) Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales 6,543 6,543 ----------- Total comprehensive income (13,220) ----------- Stock options exercised 120 12 108 120 Stock-based compensation 326 326 Repurchase of stock options (48) (48) Tax benefit of repurchase of stock options and stock options exercised 170 170 Treasury stock (20) (2) (41) (43) ------ -------- --------- ---------- ------------- ----------- DECEMBER 31, 2003 10,396 $ 1,040 $ 107,633 $ (150,656) $ (15,357) $ (57,340) ====== ======== ========= ========== ============= ===========
See accompanying notes. F-5 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS IN THOUSANDS
YEAR ENDED DECEMBER 31, ----------------------------------- 2003 2002 2001 --------- --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: (Loss) income from continuing operations $ (2,213) $ 3,745 $ 5,776 Adjustments to reconcile income from continuing operations to net cash provided by operating activities: Depreciation, depletion and amortization 19,343 22,379 25,979 Impairment of oil and gas properties and other assets 5,774 - 1,398 Accretion 365 - - Loss on sale of businesses - 154 - Loss on disposal of property and equipment 1 ,452 198 92 Net monetization of derivatives - 22,185 - Amortization of derivatives and other noncash hedging activities (3,456) (19,241) - Exploration expense 16,882 16,256 8,335 Deferred income taxes (2,481) 2,468 (1,069) Cumulative effect of change in accounting principle (2,397) - - Stock-based compensation 326 82 275 Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses: Accounts receivable and other operating assets (3,969) (1,420) 8,521 Inventories 62 453 571 Accounts payable and accrued expenses (2,539) 3,646 (5,008) --------- --------- --------- NET CASH PROVIDED BY CONTINUING OPERATIONS 27,149 50,905 44,870 CASH FLOWS FROM INVESTING ACTIVITIES: Acquisition of businesses, net of cash acquired (4,841) (2,773) (489) Disposition of businesses, net of cash 100 12,390 897 Proceeds from property and equipment disposals 2,997 1,927 768 Exploration expense (16,882) (16,256) (8,335) Additions to property and equipment (29,540) (26,215) (35,730) Increase in other assets (120) (1,541) (81) --------- --------- --------- NET CASH USED IN INVESTING ACTIVITIES (48,286) (32,468) (42,970) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving line of credit and term loan 195,859 151,158 181,645 Repayment of long-term debt and other obligations (175,573) (184,003) (184,071) Debt issue costs (250) (152) (210) Proceeds from stock options exercised 120 5 6 Repurchase of stock options 122 (29) (772) Purchase of treasury stock (43) (398) (289) --------- --------- --------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 20,235 (33,419) (3,691) --------- --------- --------- NET DECREASE IN CASH AND CASH EQUIVALENTS FROM CONTINUING OPERATIONS (902) (14,982) (1,791) NET INCREASE IN CASH AND CASH EQUIVALENTS FROM DISCONTINUED OPERATIONS 620 14,769 1,928 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,722 1,935 1,798 --------- --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,440 $ 1,722 $ 1,935 ========= ========= =========
F-6 BELDEN & BLAKE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES BUSINESS Belden & Blake Corporation (the "Company") is a privately held company owned by TPG Partners II L.P. ("TPG") and certain other investors. The Company operates in the oil and gas industry. The Company's principal business is the production, development, acquisition and marketing and gathering of oil and gas reserves. Sales of oil are ultimately made to refineries. Sales of natural gas are ultimately made to gas utilities and industrial consumers in Ohio, Michigan, Pennsylvania and New York. The price of oil and natural gas has a significant impact on the Company's working capital and results of operations. PRINCIPLES OF CONSOLIDATION AND FINANCIAL PRESENTATION The accompanying consolidated financial statements include the financial statements of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to conform to the presentation in 2003. USE OF ESTIMATES IN THE FINANCIAL STATEMENTS The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts. Significant estimates used in the preparation of the Company's financial statements which could be subject to significant revision in the near term include estimated oil and gas reserves. Although actual results could differ from these estimates, significant adjustments to these estimates historically have not been required. CASH EQUIVALENTS For purposes of the statements of cash flows, cash equivalents are defined as all highly liquid investments purchased with an initial maturity of three months or less. CONCENTRATIONS OF CREDIT RISK Credit limits, ongoing credit evaluation and account monitoring procedures are utilized to minimize the risk of loss. Collateral is generally not required. Expected losses are provided for currently and actual losses have been within management's expectations. INVENTORIES Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural gas inventories are stated at the lower of average cost or market. PROPERTY AND EQUIPMENT The Company utilizes the "successful efforts" method of accounting for its oil and gas properties. Under this method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry holes and costs of carrying and retaining unproved properties, are expensed as incurred. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions such as the complete disposition of a geographical/geological pool. Sales proceeds are F-7 credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized. Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense. Impairments recorded in 2003 and 2001 were $5.2 million and $179,000, respectively, which reduced the book value of unproved oil and gas properties to their estimated fair value. No impairment was recorded in 2002. Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. In performing the review for long-lived asset recoverability during 2003 and 2001, the Company recorded $572,000 and $1.2 million, respectively, of impairments which reduced the book value of producing properties to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the assets, discounted at a market rate of interest. No impairment was recorded in 2002. INTANGIBLE ASSETS On January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. (SFAS) 142, "Goodwill and Other Intangible Assets" which was issued in June 2001 by the Financial Accounting Standards Board (FASB). Under SFAS 142, goodwill and indefinite lived intangible assets are no longer amortized but are reviewed for impairment annually or if certain impairment indicators arise. Separately identifiable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life). At December 31, 2001, the Company had $2.7 million of unamortized goodwill, representing the costs in excess of the net assets of acquired businesses, which was subject to the transition provisions of SFAS 142. Amortization expense related to goodwill amounted to $130,000 and $132,000 for the years ended December 31, 2001 and 2000, respectively. The Company assessed the impact of SFAS 142 and has determined that adoption of SFAS 142 did not have a material effect on the Company's financial position, results of operations or cash flows, including any transitional impairment losses. The Company performed its required transitional impairment test upon adoption of SFAS 142. Due to the Company's fourth quarter disposition activity, the Company performed its annual impairment test as of December 31, 2002. However, the Company plans to perform its annual impairment test on a recurring basis as of October 1, starting in fiscal 2003. Intangible assets totaling $6.6 million at December 31, 2003, include $3.9 million of deferred debt issuance costs and $2.3 million of unamortized goodwill. Deferred debt issuance costs are being amortized over their respective terms. At December 31, 2003, the amortization of deferred debt issuance costs in the next five years is as follows: $1.2 million in each of the next two years (2004, F-8 and 2005), $1.0 million in 2006 and $403,000 in 2007. During the fourth quarter of 2002, the Company allocated $667,000 of goodwill to disposal transactions. 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 service revenues are recognized when the goods or services have been provided. INCOME TAXES The Company uses the asset and 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 On December 31, 2002, the FASB issued SFAS 148, "Accounting for Stock Based Compensation-Transition and Disclosure." SFAS 148 amends SFAS 123, "Accounting for Stock Based Compensation" by providing alternative methods of transition to SFAS 123's fair value method of accounting for stock-based compensation. SFAS 148 also amends many of the disclosure requirements of SFAS 123. The Company measures expense associated with stock-based compensation under the provisions of Accounting Principles Board Opinion No. (APB) 25, "Accounting for Stock Issued to Employees" and its related interpretations. Under APB 25, no compensation expense is required to be recognized by the Company upon the issuance of stock options to key employees as the exercise price of the option is equal to the market price of the underlying common stock at the date of grant. The fair value of the Company's stock options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the years ended December 31, 2003, 2002 and 2001, respectively: risk-free interest rates of 3.7%, 4.1% and 5.0%; volatility factor of the expected market price of the Company's common stock of near zero; dividend yield of zero; and a weighted-average expected life of the option of seven years. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its stock options. For purposes of the pro forma disclosures required by SFAS 123, the estimated fair value of the options is amortized to expense over the options' vesting period. The changes in net income or loss as if the Company had applied the fair value provisions of SFAS 123 for the years ended December 31, 2003, 2002 and 2001 were not material. The changes in share value and the vesting of shares are reported as adjustments to compensation expense. The change in share value in 2003, 2002 and 2001 resulted in an increase in compensation expense of $325,000, $82,000 and $275,000, respectively. F-9 DERIVATIVES AND HEDGING On January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" which was issued in June 1998 by the FASB, as amended by SFAS 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of Effective Date of SFAS 133" and SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" issued in June 1999 and June 2000, respectively. SFAS 133, as amended, was applied as the cumulative effect of an accounting change effective January 1, 2001. As a result of the adoption of SFAS 133, the Company recognizes all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss). Ineffective portions of a derivative instrument's change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be recognized as increases or decreases to oil and gas revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss). If there is a discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately. See Note 5. The relationship between the hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk, both at the inception of the contract and on an ongoing basis. The Company measures effectiveness on changes in the hedge's intrinsic value. The Company considers these hedges to be highly effective and expects there will be no ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging instruments and the hedged forecasted transactions are the same. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. The Company measures effectiveness at least on a quarterly basis. Adoption of SFAS 133 on January 1, 2001 resulted in recording a $10.5 million ($6.7 million net of tax) net liability related to the decline in fair value of the Company's derivative financial instruments with a corresponding reduction in shareholders' equity to other comprehensive loss. The net liability consisted of $11.8 million in current fair value of derivative liabilities and $1.3 million in current fair value of derivative assets. (2) NEW ACCOUNTING PRONOUNCEMENTS On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 amends SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" to require the Company to recognize a liability for the fair value of its asset retirement obligations associated with its tangible, long-lived assets. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment (excluding salvage value) of its oil and gas properties. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $4.0 million increase in long-term asset retirement obligation liabilities, a $621,000 increase in current asset retirement obligation liabilities, a $3.2 million increase in the carrying value of oil and gas assets, a $5.2 million decrease in accumulated depreciation, depletion and amortization and a $1.4 million increase in deferred income tax liabilities. The net effect of adoption was to record a gain of $2.4 million, net of tax, as a cumulative effect of a change in accounting principle in the Company's consolidated statement of operations in the first quarter of 2003. F-10 Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The unaudited pro forma income from continuing operations for the years ended December 31, 2002 and 2001 was $4.3 million and $6.9 million, respectively, and has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002 and January 1, 2001. Assuming retroactive application of the change in accounting principle as of January 1, 2002, liabilities would have increased approximately $6 million. A reconciliation of the Company's liability for plugging and abandonment costs for the year ended December 31, 2003 is as follows (in thousands): Asset retirement obligation, December 31, 2002 $ - Cumulative effect adjustment 4,603 Liabilities incurred 345 Liabilities settled (491) Accretion expense 365 Revisions in estimated cash flows 294 ------------- Asset retirement obligation, December 31, 2003 $ 5,116 ============= On January 1, 2003, the Company adopted SFAS 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt," SFAS 44, "Accounting for Intangible Assets of Motor Carriers" and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements" and amends SFAS No. 13, "Accounting for Leases." Statement 145 also makes technical corrections to other existing pronouncements. SFAS 4 required gains and losses from extinguishment of debt to be classified as an extraordinary item, net of the related income tax effect. As a result of the rescission of SFAS 4, the criteria for extraordinary items in APB 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," now will be used to classify those gains and losses. The adoption of SFAS 145 did not have any effect on the Company's financial position, results of operations or cash flows. In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 was effective for the Company for disposal activities initiated after December 31, 2002. The adoption of this standard did not have any effect on the Company's financial position, results of operations or cash flows. In October 2002, the FASB issued SFAS 147, "Acquisitions of Certain Financial Institutions - an amendment of FASB Statements No. 72 and 144 and FASB Interpretation No. 9." SFAS 147 was effective for the Company for acquisition activities initiated on or after October 1, 2002. The adoption of this standard did not have any effect on the Company's financial position, results of operations or cash flows. In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45's disclosure requirements are effective for the Company's interim and annual financial statements for periods ending after December 15, 2002. The initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. FIN 45 requires certain guarantees to be recorded at fair value, which is different F-11 from current practice, which is generally to record a liability only when a loss is probable and reasonably estimable. FIN 45 also requires a guarantor to make significant new disclosures, even when the likelihood of making any payments under the guarantee is remote. The adoption of FIN 45 did not have any effect on the Company's financial statement disclosures, financial position, results of operations or cash flows. In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." SFAS 148 amends FASB 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The Company measures expense associated with stock-based compensation using the intrinsic value method prescribed by APB 25, "Accounting for Stock Issued to Employees" and its related interpretations. Under APB 25, no compensation expense is required to be recognized by the Company upon the issuance of stock options to key employees as the exercise price of the option is equal to the market price of the underlying common stock at the date of grant. The provisions of SFAS 148 were effective for financial statements for fiscal years ending after December 15, 2002. The adoption of SFAS 148 did not have a material effect on the Company's financial position, results of operations or cash flows. In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities - An Interpretation of Accounting Research Bulletin (ARB) 51." FIN 46 is an interpretation of ARB 51, "Consolidated Financial Statements," and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after December 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. The adoption of FIN 46 did not have any effect on the Company's financial statement disclosures, financial position, results of operations or cash flows. In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This Statement is intended to result in more consistent reporting of contracts as either freestanding derivative instruments subject to Statement 133 in its entirety, or as hybrid instruments with debt host contracts and embedded derivative features. SFAS 149 is effective for the Company's financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 149 did not have a material effect on the Company's financial position, results of operations or cash flows. In May 2003, the FASB issued SFAS 150, "Accounting for Financial Instruments with Characteristics of both Liabilities and Equity." This Statement establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity. Instruments that are indexed to and potentially settled in an issuer's own shares that are not within the scope of Statement 150 remain subject to existing guidance. SFAS 150 is effective for the Company's financial statements for the interim period beginning July 1, F-12 2003. The adoption of SFAS 150 did not have a material effect on the Company's financial position, results of operations or cash flows. The Company has been made aware of an issue regarding the application of provisions of SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," to oil and gas companies. The issue is whether SFAS 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS 69, "Disclosures about Oil and Gas Producing Activities." If it is ultimately determined that SFAS 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the Company currently believes that its financial condition, results of operations or cash flows would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. The Company had undeveloped leasehold costs of $7.7 million and $14.2 million at December 31, 2003 and 2002, respectively. The amount of potential balance sheet reclassifications for developed leasehold costs has not been determined. In December 2003, the FASB issued SFAS 132 (revised 2003), "Employers' Disclosures about Pensions and Other Postretirement Benefits," an amendment of SFAS 87, 88, and 106, and a revision of SFAS 132. This statement revises employers' disclosures about pension plans and other postretirement benefit plans. It does not change the measurement or recognition of those plans required by FASB Statements No. 87, Employers' Accounting for Pensions, No. 88, Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits, and No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. This Statement retains the disclosure requirements contained in FASB Statement No. 132, Employers' Disclosures about Pensions and Other Postretirement Benefits, which it replaces. It requires additional disclosures to those in the original Statement 132 about the assets, obligations, cash flows, and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans. The required information should be provided separately for pension plans and for other postretirement benefit plans. This Statement is effective for financial statements with fiscal years ending after December 15, 2003. The adoption of this standard did not have a material effect on the Company's financial position, results of operations or cash flows. (3) ACQUISITIONS In February 2003, the Company purchased reserves in certain wells the Company operates in Michigan for $3.8 million in cash. These properties were subject to a prior monetization transaction of the Section 29 tax credits which the Company entered into in 1996. The Company had the option to purchase these properties beginning in 2003. The Company previously held a production payment on these properties including a 75% reversionary interest in certain future production. The Company purchased those reserve volumes beyond its currently held production payment along with the 25% reversionary interest not owned. The estimated volumes acquired were 4.4 Bcf (billion cubic feet) of proved developed producing gas reserves. On July 11, 2002, the Company acquired net reserves totaling 4.2 Bcfe (billion cubic feet of natural gas equivalent) for a cash payment of $1.2 million. The Company previously held a production payment on these properties through December 31, 2002. F-13 During the second quarter of 2002, the Company acquired the assets of a drilling consulting and frac tank rental business for $1.6 million. (4) DISPOSITIONS AND DISCONTINUED OPERATIONS As a result of the Company's decision to shift focus away from exploration and development activities in the Knox formation in Ohio, the Company sold substantially all of its undeveloped Knox acreage in Ohio for approximately $2.8 million in September 2003. The sale resulted in a loss of approximately $150,000. On December 10, 2002, the Company sold 962 oil and natural gas wells in New York and Pennsylvania. The sale included substantially all of the Company's Medina formation wells in New York and a smaller number of Pennsylvania Medina wells. The properties had approximately 23 Bcfe of total proved reserves. At the time of the sale, the Company's net production from these wells was approximately 3.9 Mmcfe (million cubic feet of natural gas equivalent) per day (4 Mcfe (thousand cubic feet of natural gas equivalent) per day per well). The Company disposed of these properties due to the low production volume per well and high cost characteristics. The wells sold had proved developed reserves using Securities and Exchange Commission ("SEC") pricing parameters of approximately 19.4 Bcfe and proved undeveloped reserves of approximately 3.6 Bcfe. The sale resulted in proceeds of approximately $16.2 million. On December 10, 2002, the Company received $15.5 million in cash with the remaining amount of approximately $700,000 received in February 2003. The proceeds were used to pay down the Company's revolving credit facility. As a result of the sale, the Company disposed of all of its properties producing from the New York Medina formation. As a result of the disposition of the entire New York Medina geographical/geological pool, the Company recorded a loss on sale of $3.2 million ($1.8 million net of tax) in 2002. According to SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the disposition of this group of wells is classified as discontinued operations. The Company allocates interest expense to operating areas based on the proportionate share of net assets of the area to the Company's consolidated net assets. The amounts of interest expense allocated to the New York Medina geographical/geological pool and included in income (loss) from discontinued operations for the years ended December 31, 2002 and 2001 were $1.5 million and $1.7 million, respectively. F-14 Revenues and (loss) income from discontinued operations are as follows:
YEAR ENDED DECEMBER 31, ---------------------------------------- 2003 2002 2001 ---------- ----------- --------- Revenue from discontinued operations $ 10 $ 9,245 $ 12,646 (Loss) income from operations of discontinued business $ (107) $ 960 $ 1,155 (Benefit) provision for income taxes (40) 408 464 ---------- ----------- --------- (67) 552 691 Loss on sale of discontinued business (69) (3,188) Income tax benefit (25) (1,356) ---------- ----------- (44) (1,832) ---------- ----------- --------- (Loss) income from discontinued operations, net of tax $ (111) $ (1,280) $ 691 ========== =========== =========
Assets and liabilities of the discontinued operations are as follows: DECEMBER 31, -------------------------- 2003 2002 ---------- ----------- Assets Current assets $ - $ - Net property and equipment - 1,066 ---------- ----------- Total assets $ - $ 1,066 ========== =========== Liabilities Current liabilities $ - $ 335 Noncurrent deferred tax liability - - ---------- ----------- Total liabilities $ - $ 335 ---------- ----------- Net assets of discontinued operations $ - $ 731 ========== =========== A transaction fee of $238,000 was paid in 2003 to TPG in connection with the sale. The fee was paid to TPG pursuant to a Transaction Advisory Agreement entered into in 1997 between the Company and TPG. During 2002, the Company completed the sale of six natural gas compressors in Michigan to a compression services company. The proceeds of approximately $2.0 million were used to pay down the Company's revolving credit facility. The Company also entered into an agreement to leaseback the compressors from the compression services company, which will provide full compression services including maintenance and repair on these and other compressors. Certain compressors were relocated to maximize compression efficiency. A gain on the sale of $168,000 was deferred and will be amortized as rental expense over the life of the lease. On August 1, 2002, the Company sold oil and gas properties consisting of 1,138 wells in Ohio that had approximately 10 Bcfe of proved reserves. At the time of the sale, the Company's net production from these wells was approximately 3.1 Mmcfe per day (3 Mcfe per day per well). The Company disposed of these properties due to the low production volume per well and high operating costs per well. The proceeds of approximately $8.0 million were used to pay down the Company's revolving credit facility. F-15 (5) DERIVATIVES AND HEDGING From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas or oil price volatility. The Company employs a policy of hedging gas production sold under New York Mercantile Exchange ("NYMEX") based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options. At December 31, 2003, the Company's derivative contracts consisted of natural gas swaps, collars and options. Qualifying NYMEX based derivative contracts were designated as cash flow hedges. The changes in fair value of non-qualifying derivative contracts will be initially reported in expense in the consolidated statements of operations as derivative fair value (gain) loss and will ultimately be reversed within the same line item and included in oil and gas sales over the respective contract terms. The fair value of derivative assets and liabilities represents the difference between hedged prices and market prices on hedged volumes of natural gas as of December 31, 2003. During 2003, a net loss on contract settlements of $10.3 million ($6.5 million after tax) was reclassified from accumulated other comprehensive income to earnings and the fair value of open hedges decreased by $27.1 million ($17.4 million after tax). At December 31, 2003, the estimated net losses in accumulated other comprehensive income that are expected to be reclassified into earnings within the next 12 months are approximately $14.6 million. The Company has partially hedged its exposure to the variability in future cash flows through December 2005. In March 2003, the Company entered into a collar for 4,320 Bbtu (billion British thermal units) of its natural gas production in 2004 with a ceiling price of $5.80 per Mmbtu (million British thermal units) and a floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.00 per Mmbtu on this volume of gas which was designated as a non-qualifying cash flow hedge under SFAS 133. This aggregate structure has the effect of: 1) setting a maximum price of $5.80 per Mmbtu; 2) floating at prices from $4.00 to $5.80 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.00 and $4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu above the price if the price is $3.00 or less. All prices are based on monthly NYMEX settle. In April 2003, the Company entered into a collar for 6,000 Bbtu of its natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.10 per Mmbtu on this volume of gas which was designated as a non-qualifying cash flow hedge under SFAS 133. This aggregate structure has the effect of: 1) setting a maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.10 and $4.00 per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if the price is $3.10 or less. All prices are based on monthly NYMEX settle. On January 17 and 18, 2002, the Company monetized 9,350 Bbtu (billion British thermal units) of its 2002 natural gas hedge position at a weighted average NYMEX price of $2.53 per Mmbtu (million British thermal units) and 3,840 Bbtu of its 2003 natural gas hedge position at a NYMEX price of $3.01 per Mmbtu. The Company received net proceeds of $22.7 million that are recognized as increases to natural gas sales revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss). In January 2002, the Company entered into a collar for 9,350 Bbtu of its natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a floor price of $2.25 per Mmbtu which qualified and was designated as a cash flow hedge under SFAS 133. The Company also sold a floor at $1.75 per F-16 Mmbtu on this volume of gas which was designated as a non-qualifying cash flow hedge under SFAS 133. This aggregate structure has the effect of: 1) setting a maximum price of $4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per Mmbtu; 3) locking in a price of $2.25 per Mmbtu if prices are between $1.75 and $2.25 per Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the price if the price is $1.75 or less. All prices are based on monthly NYMEX settle. The Company paid $1.0 million for the options. The Company used the net proceeds of $21.7 million from the two transactions above to pay down on its credit facility. The following table summarizes, as of December 31, 2003, the Company's net deferred gains on terminated natural gas hedges. Cash has been received and the deferred gains recorded in accumulated other comprehensive income. The deferred gains have been recognized as increases to gas sales revenues during the periods in which the underlying forecasted transactions were recognized in net income (loss). FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER TOTAL ------- -------------- ------- ------- ------- (IN THOUSANDS) 2003 $ 723 $ 865 $ 771 $ 585 $ 2,944 To manage its exposure to natural gas or oil price volatility, the Company may partially hedge its physical gas or oil sales prices by selling futures contracts on the NYMEX or by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options. The Company's financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Accordingly, the Company may modify its fixed price contract and financial hedging positions by entering into new transactions or terminating existing contracts. The following tables reflect the natural gas volumes and the weighted average prices under financial hedges (including settled hedges) at December 31, 2003:
NATURAL GAS SWAPS NATURAL GAS COLLARS FIXED PRICE CONTRACTS ----------------------------------- --------------------------------------- ------------------------- ESTIMATED NYMEX PRICE ESTIMATED ESTIMATED NYMEX PRICE WELLHEAD PER MMBTU WELLHEAD PRICE ESTIMATED WELLHEAD QUARTER ENDING BBTU PER MMBTU PRICE PER MCF BBTU FLOOR/CAP PER MCF MMCF PRICE PER MCF ------------------ ----- ----------- ------------- ----- ------------- -------------- --------- ------------- March 31, 2004 2,040 $ 3.84 $ 4.09 1,080 $ 4.00 - 5.80 $ 4.25 - 6.05 54 $ 4.10 June 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 37 4.06 September 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 -- -- December 31, 2004 2,040 3.84 4.06 1,080 4.00 - 5.80 4.22 - 6.02 -- -- ----- ----------- ------------- ----- ------------- -------------- --------- ------------- 8,160 $ 3.84 $ 4.03 4,320 $ 4.00 - 5.80 $ 4.19 - 5.99 91 $ 4.08 ===== =========== ============= ===== ============= ============== ========= ============= March 31, 2005 1,500 $ 3.84 $ 4.09 1,500 $ 4.00 - 5.37 $ 4.25 - 5.62 June 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52 September 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52 December 31, 2005 1,500 3.73 3.95 1,500 4.00 - 5.37 4.22 - 5.59 ----- ----------- ------------- ----- ------------- -------------- 6,000 $ 3.76 $ 3.95 6,000 $ 4.00 - 5.37 $ 4.19 - 5.56 ===== =========== ============= ===== ============= ==============
MCF - THOUSAND CUBIC FEET MMBTU - MILLION BRITISH THERMAL UNITS BBTU - BILLION BRITISH THERMAL UNITS F-17 (6) SEVERANCE AND OTHER NONRECURRING EXPENSE On October 10, 2002, the Company combined its Pennsylvania/New York District with its Ohio District to form a new "Appalachian District". A total of 28 positions were eliminated in the Ohio and Pennsylvania/New York Districts and in the corporate office. These actions were necessary to capitalize on operational and administrative efficiencies and bring the Company's employment level in line with anticipated future staffing. The Company recorded a nonrecurring charge of approximately $700,000 in the fourth quarter of 2002 related to severance and other costs associated with these actions. Effective April 1, 2001, certain senior management members of the Company accepted early retirements. These retirements resulted in a cash charge of approximately $760,000 and an additional non-cash charge of approximately $100,000 related to the acceleration of certain stock options. The Company recorded a net nonrecurring charge of $2.0 million in 2001 which includes a charge of $2.3 million primarily related to these retirement agreements and other retirement and severance charges incurred which included non-cash charges totaling approximately $200,000 due to the acceleration of certain related stock options. In 2001, the Company recognized approximately $300,000 in other nonrecurring gains. F-18 (7) DETAILS OF BALANCE SHEETS
DECEMBER 31, ----------------------- 2003 2002 --------- --------- (IN THOUSANDS) ACCOUNTS RECEIVABLE Accounts receivable $ 7,393 $ 7,610 Allowance for doubtful accounts (1,547) (1,588) Oil and gas production receivable 11,672 8,417 Current portion of notes receivable 79 213 --------- --------- $ 17,597 $ 14,652 ========= ========= INVENTORIES Oil $ 459 $ 665 Natural gas 33 18 Material, pipe and supplies 294 165 --------- --------- $ 786 $ 848 ========= ========= PROPERTY AND EQUIPMENT, GROSS OIL AND GAS PROPERTIES Producing properties $ 446,967 $ 406,336 Non-producing properties 8,283 14,291 Other 9,012 17,613 --------- --------- $ 464,262 $ 438,240 ========= ========= LAND, BUILDINGS, MACHINERY AND EQUIPMENT Land, buildings and improvements $ 5,443 $ 5,168 Machinery and equipment 17,664 17,580 --------- --------- $ 23,107 $ 22,748 ========= ========= ACCRUED EXPENSES Accrued expenses $ 4,185 $ 5,870 Accrued drilling and completion costs 2,583 3,480 Accrued income taxes 73 85 Ad valorem and other taxes 1,517 1,619 Compensation and related benefits 2,541 2,222 Undistributed production revenue 4,494 4,491 --------- --------- $ 15,393 $ 17,767 ========= =========
F-19 (8) LONG-TERM DEBT Long-term debt consists of the following (in thousands):
DECEMBER 31, -------------------- 2003 2002 -------- -------- Revolving credit facility $ 47,406 $ 26,764 Senior subordinated notes 225,000 225,000 Other 102 286 -------- -------- 272,508 252,050 Less current portion 5 182 -------- -------- Long-term debt $272,503 $251,868 ======== ========
On June 27, 1997, the Company completed a private placement (pursuant to Rule 144A) of $225 million of 9 7/8% Senior Subordinated Notes, Series A, which mature on June 15, 2007 ("the Notes"). The Notes were issued under an indenture which requires interest to be paid semiannually on June 15 and December 15 of each year, commencing December 15, 1997. The Notes are subordinate to the senior revolving credit agreement. In September 1997, the Company completed a registration statement on Form S-4 providing for an exchange offer under which each Series A Senior Subordinated Note would be exchanged for a Series B Senior Subordinated Note. The terms of the Series B Notes are the same in all respects as the Series A Notes except that the Series B Notes have been registered under the Securities Act of 1933 and therefore will not be subject to certain restrictions on transfer. The Notes are redeemable in whole or in part at the option of the Company, at any time on or after the dates below, at the redemption prices set forth plus, in each case, accrued and unpaid interest, if any, thereon.
June 15, 2003....................................... 103.292% June 15, 2004....................................... 101.646% June 15, 2005 and thereafter........................ 100.000%
The indenture under which the subordinated notes were issued contains certain covenants that limit the ability of the Company and its subsidiaries to incur additional indebtedness and issue stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens, and engage in mergers and consolidations. The Company has a $100 million revolving credit facility (the "Revolver") from Ableco Finance LLC and Wells Fargo Foothill, Inc. (formerly known as Foothill Capital Corporation) which matures on June 30, 2006. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At December 31, 2003, the interest rate was 6.00%. At December 31, 2003, the Company had $38.7 million of outstanding letters of credit. At December 31, 2003, the outstanding balance under the credit agreement was $47.4 million with $38.9 million of borrowing capacity available for general corporate purposes. During 2002, amendments to the Company's $100 million revolving credit facility extended the Revolver's final maturity date to December 31, 2005, from April 22, 2004, increased the letter of credit sub-limit from $30 million to $40 million and permitted the Company to enter into the transactions to sell oil and gas properties consisting of 1,138 wells in Ohio and 962 wells in New York and Pennsylvania. F-20 The Revolver was amended on March 31, 2003 to increase the letter of credit sub-limit to $55 million. On May 30, 2003, the Company amended its $100 million revolving credit facility. The amendment increased the total commitment amount from $100 million to $125 million solely to provide for a special letter of credit facility in the amount of $25 million which combined with the existing letter of credit sub-limit of $55 million would allow a total of $80 million in letters of credit. The amendment also extended the Revolver's final maturity date to June 30, 2006, from December 31, 2005 and permitted the Company to enter into transactions to sell certain oil and gas leases in Ohio in 2003. The Revolver, as amended, is subject to certain financial covenants. These include a quarterly senior debt interest coverage ratio of 3.2 to 1 extended through March 31, 2006; and a senior debt leverage ratio of 2.7 to 1 extended through March 31, 2006. The amendment extended the early termination fee, equal to .125% of the Revolver, through June 30, 2005. There is no termination fee after June 30, 2005. The Company is required to hedge, through financial instruments or fixed price contracts, at least 20% but not more than 80% of its estimated hydrocarbon production, on a Mcfe basis, for the succeeding 12 months on a rolling 12-month basis. Based on the Company's hedges currently in place and its expected production levels, the Company is in compliance with this hedging requirement through September 2005. The Revolver, as amended, also contains other financial covenants. EBITDA, as defined in the Revolver, and consolidated interest expense on senior debt in these ratios are calculated quarterly based on the financial results of the previous four quarters. In addition, the Company is required to maintain a current ratio (including available borrowing capacity in current assets, excluding current debt and accrued interest from current liabilities and excluding any effects from the application of SFAS 133 to other current assets or current liabilities) of at least 1.0 to 1 and maintain liquidity of at least $5 million (cash and cash equivalents including available borrowing capacity). As of December 31, 2003, the Company's current ratio including the above adjustments was 3.46 to 1. The Company had satisfied all financial covenants as of December 31, 2003. The Revolver is secured by security interests and mortgages against substantially all of the Company's assets and is subject to periodic borrowing base determinations. The borrowing base is the lesser of $100 million or the sum of (i) 65% of the value of the Company's proved developed producing reserves subject to a mortgage; (ii) 45% of the value of the Company's proved developed non-producing reserves subject to a mortgage; and (iii) 40% of the value of the Company's proved undeveloped reserves subject to a mortgage. The price forecast used for calculation of the future net income from proved reserves is the three-year NYMEX strip for oil and natural gas as of the date of the reserve report. Prices beyond three years are held constant. Prices are adjusted for basis differential, fixed price contracts and financial hedges in place. The weighted average price at December 31, 2003, was $4.87 per Mcfe. The present value (using a 10% discount rate) of the Company's future net income at December 31, 2003, using the borrowing base price forecast was $426 million. The present value under the borrowing base formula above, applying the stated percents of each group of reserves, was approximately $253 million for all proved reserves of the Company and $174 million for properties secured by a mortgage. 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. There were no interest rate swaps in 2003, 2002 or 2001. At December 31, 2003, the aggregate long-term debt maturing in the next five years is as follows: $5,000 (2004); $6,000 (2005); $47,412,000 (2006); $225,007,000 (2007) and $78,000 (2008 and thereafter). F-21 (9) LEASES The Company leases certain computer equipment, vehicles, natural gas compressors and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $3.3 million, $2.8 million and $2.9 million for the years ended December 31, 2003, 2002 and 2001, respectively. The Company also leases certain computer equipment accounted for as capital leases. Property and equipment includes $506,000 and $747,000 of computer equipment under capital leases at December 31, 2003 and 2002, respectively. Accumulated depreciation for such equipment includes approximately $298,000 and $523,000 at December 31, 2003 and 2002, respectively. Future minimum commitments under leasing arrangements at December 31, 2003 were as follows:
OPERATING CAPITAL YEAR ENDING DECEMBER 31, 2003 LEASES LEASES -------------------------------------------- ---------- -------- (IN THOUSANDS) 2004 $ 3,465 $ 104 2005 2,696 39 2006 2,484 36 2007 1,956 36 2008 and thereafter 183 2 ---------- -------- Total minimum rental payments $ 10,784 217 ========== Less amount representing interest 9 -------- Present value of net minimum rental payments 208 Less current portion 100 -------- Long-term capitalized lease obligations $ 108 ========
(10) STOCK OPTION PLANS 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, 2003, options to purchase 616,321 shares were outstanding under the plan. These options, except for the 100,000 options described below, become exercisable at a rate of one fourth of the shares one year from the date of grant and an additional one twelfth of the remaining shares on every calendar quarter-end thereafter. The remaining 100,000 options become exercisable at a rate of one fourth of the shares on the last day of each quarter commencing June 30, 2003. During 2002 and 2001, certain employees that retired or were previously terminated elected to put their vested stock options back to the Company. As a result, the Company paid approximately $30,000 and $772,000 to purchase and cancel 13,814 and 219,644 options during 2002 and 2001, respectively. F-22 Stock option activity consisted of the following:
WEIGHTED AVERAGE NUMBER OF EXERCISE SHARES PRICE -------- -------- BALANCE AT DECEMBER 31, 2000 869,192 $ 0.09 Granted 358,500 3.14 Forfeitures (158,594) 0.56 Exercised or put (287,492) 0.08 Reissued and repriced (227,500) 3.59 Reissued and repriced 227,500 2.14 -------- BALANCE AT DECEMBER 31, 2001 781,606 0.97 Granted 35,000 2.14 Forfeitures (52,999) 1.58 Exercised or put (79,151) 0.07 -------- BALANCE AT DECEMBER 31, 2002 684,456 1.09 Granted 77,500 2.14 Forfeitures (781) 0.30 Exercised or put (144,854) 0.83 -------- BALANCE AT DECEMBER 31, 2003 616,321 1.29 ======== OPTIONS EXERCISABLE AT DECEMBER 31, 2003 387,594 $ 0.81 ========
The weighted average fair value of options granted during 2003, 2002 and 2001 was $0.49, $0.52 and $0.79, respectively. The exercise price for the options outstanding as of December 31, 2003 ranged from $0.01 to $2.14 per share. At December 31, 2003, the weighted average remaining contractual life of the outstanding options is 6.6 years. F-23 (11) TAXES The provision (benefit) for income taxes on income from continuing operations before cumulative effect of change in accounting principle includes the following (in thousands):
YEAR ENDED DECEMBER 31, ------------------------------------ 2003 2002 2001 -------- -------- -------- CURRENT Federal $ -- $ (190) $ 114 State -- 76 -- -------- -------- -------- -- (114) 114 DEFERRED Federal (2,580) 2,140 (1,004) State 99 430 (65) -------- -------- -------- (2,481) 2,570 (1,069) -------- -------- -------- TOTAL $ (2,481) $ 2,456 $ (955) ======== ======== ========
The effective tax rate for income from continuing operations before cumulative effect of change in accounting principle differs from the U.S. federal statutory tax rate as follows:
YEAR ENDED DECEMBER 31, ------------------------- 2003 2002 2001 ---- ---- ----- 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 0.9 5.3 -- Settlement of IRS exam and other tax issues -- -- (40.9) Change in valuation allowance -- -- (14.5) Permanent differences (0.9) -- -- Other, net -- (0.7) 0.6 ---- ---- ----- Effective income tax rate for the period 35.0% 39.6% (19.8)% ==== ==== =====
During 2001, the Company concluded an IRS income tax examination of the years 1994 through 1997 and favorably settled other tax issues. A federal income tax benefit of $2.0 million was recorded as a result. Also during 2001, a federal income tax benefit was recorded for approximately $700,000 along with a corresponding reduction in the valuation allowance as a result of certain net operating loss carryforwards which the Company believes it can fully utilize. F-24 Significant components of deferred income tax liabilities and assets are as follows (in thousands):
DECEMBER 31, DECEMBER 31, 2003 2002 ------------ ------------ Deferred income tax liabilities: Property and equipment, net $ 45,302 $ 46,698 ------------ ------------ Total deferred income tax liabilities 45,302 46,698 Deferred income tax assets: Accrued expenses 1,224 2,666 Fair value of derivatives 8,254 2,449 Net operating loss carryforwards 28,605 26,012 Tax credit carryforwards 913 913 Other, net 534 514 Valuation allowance (5,388) (4,252) ------------ ------------ Total deferred income tax assets 34,142 28,302 ------------ ------------ Net deferred income tax liability $ 11,160 $ 18,396 ============ ============ Current liability $ -- $ -- Long-term liability 18,013 22,596 Current asset (6,853) (4,200) ------------ ------------ Net deferred income tax liability $ 11,160 $ 18,396 ============ ============
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, 2003 and 2002 relates principally to certain state net operating loss carryforwards which management estimates will expire before they can be utilized. At December 31, 2003, the Company had approximately $60 million of net operating loss carryforwards available for federal income tax reporting purposes. These net operating loss carryforwards, if unused, will expire in 2012 through 2023. The Company has alternative minimum tax credit carryforwards of approximately $900,000 which have no expiration date. The Company has approximately $1.0 million 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 based on attainment of performance targets. Amounts are allocated to substantially all employees based on relative compensation. The Company expensed $1.3 million, $1.1 million and $1.4 million for the years ended December 31, 2003, 2002 and 2001, respectively, for contributions to the profit sharing plan and discretionary bonuses. All amounts were paid in cash. As of December 31, 2003, the Company has a qualified defined contribution plan (a 401(k) plan) covering substantially all of the employees of the Company. Eligible employees may make voluntary contributions which the Company matches $1.00 for every $1.00 contributed up to 4% of an employee's annual compensation and a $0.50 match for every $1.00 contributed up to the next 2% of compensation. Retirement plan expense amounted to $433,000, $557,000 and $550,000 for the years ended December 31, 2003, 2002 and 2001, respectively. Prior to January 1, 2002, the Company matched $0.50 for every $1.00 contributed up to 6% of an employee's annual compensation on voluntary contributions and an amount equal to 2% of participants' F-25 compensation was contributed by the Company to the plan each year. Effective January 1, 2002, the previous contribution made by the Company in the amount equal to 2% of participants' compensation each year was eliminated. (13) COMMITMENTS AND CONTINGENCIES In April 2002, the Company was notified of a claim by an overriding royalty interest owner in Michigan alleging the underpayment of royalty resulting from disputes as to the interpretation of the terms of several farmout agreements. The Company believes there will be no material amount payable above and beyond the amount accrued as of December 31, 2003 and therefore, the result will have no material adverse effect on its financial position, results of operation or cash flows. The Company was audited by the state of West Virginia for the years 1996 through 1998. The state assessed taxes which the Company has contested and filed a petition for reassessment. In February 2003, the Company was notified by the State Tax Commissioner of West Virginia that the Company's petition for reassessment had been denied and taxes due, plus accrued interest, are now payable. The Company disagrees with the decision and has appealed. The Company believes there will be no material amount payable above and beyond the amount accrued as of December 31, 2003 and therefore, the result will have no material adverse effect on its financial position, results of operations or cash flows. In February 2000, four individuals filed a suit in Chautauqua County, New York on their own behalf and on the behalf of others similarly situated, seeking damages for the alleged difference between the amount of lease royalties actually paid and the amount of royalties that allegedly should have been paid. Other natural gas producers in New York were served with similar complaints. The Company believes the complaint is without merit and is defending the complaint vigorously. Although the outcome is still uncertain, the Company believes the action will not have a material adverse effect on its financial position, results of operations or cash flows. The Company no longer owns the wells that were subject to the suit. The Company was subject to binding arbitration on an issue regarding the valuation of shares of common stock put back to the Company in 1999 pursuant to a former executive officer's employment agreement. In March 2003, pursuant to the arbitrator's ruling, the Company repurchased 31,168 shares of common stock for $337,000 plus interest from the date of the employment agreement. The Company paid $521,000 in 2003 based on the ruling. The Company recorded the stock purchase as treasury stock in 2002 and expensed the interest in the appropriate periods. The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on the Company's financial position, results of operations or cash flows. Environmental costs, if any, are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed as incurred. Expenditures that extend the life of the related property or reduce or prevent future environmental contamination are capitalized. Liabilities related to environmental matters are only recorded when an environmental assessment and/or remediation obligation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability are fixed or reliably determinable. At December 31, 2003, no significant environmental remediation obligation exists which is expected to have a material effect on the Company's financial position, results of operations or cash flows. F-26 (14) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
YEAR ENDED DECEMBER 31, -------------------------------------------- (IN THOUSANDS) 2003 2002 2001 --------------------------------------------------------------- ------------ ------------ ------------ CASH PAID DURING THE PERIOD FOR: Interest $ 25,427 $ 23,750 $ 27,737 Income taxes, net of refunds 172 (221) 359 NON-CASH INVESTING AND FINANCING ACTIVITIES: Acquisition of assets in exchange for long-term liabilities 136 281 443 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX 2,397 -- --
(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 $222.7 million at December 31, 2003 based on quoted market prices. From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas or oil price volatility. The Company employs a policy of hedging gas production sold under NYMEX based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options. At December 31, 2003, the Company's derivative contracts consisted of natural gas swaps, collars and options. Qualifying NYMEX based derivative contracts are designated as cash flow hedges. The Company incurred a pre-tax loss on its hedging activities of $10.3 million in 2003 and pre-tax gains of $21.6 million in 2002 and $4.5 million in 2001. At December 31, 2003, the fair value of futures contracts covering 2004 and 2005 natural gas production represented an unrealized loss of $23.4 million. F-27 (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 and include both continuing and discontinued operations.
YEAR ENDED DECEMBER 31, -------------------------------------- (IN THOUSANDS) 2003 2002 2001 -------------------------------------------------- ---------- ---------- ---------- Acquisition costs: Proved properties $ 3,923 $ 1,724 $ 2,399 Unproved properties 2,135 5,364 5,574 Developmental costs 25,361 16,222 23,409 Exploratory costs 16,882 16,282 8,346 Estimated asset retirement obligations incurred (1) 639 -- --
------ (1) amounts are shown net of revisions of estimated cash flows PROVED OIL AND GAS RESERVES (UNAUDITED) The Company's proved developed and proved undeveloped reserves are all located within the United States. The Company cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made. The estimates of proved reserves as of December 31, 2003, 2002 and 2001 have been prepared by Wright & Company, Inc., independent petroleum engineers. F-28 The following table sets forth changes in estimated proved and proved developed reserves for the periods indicated:
OIL GAS (MBBL)(1) (MMCF)(2) MMCFE(3) --------- --------- -------- DECEMBER 31, 2000 8,653 373,529 425,447 Extensions and discoveries 285 13,591 15,301 Purchase of reserves in place -- 28,557 28,557 Sale of reserves in place (54) (1,129) (1,453) Revisions of previous estimates (2,651) (61,780) (77,686) Production (646) (18,541) (22,417) --------- --------- -------- DECEMBER 31, 2001 5,587 334,227 367,749 Extensions and discoveries 32 2,382 2,574 Purchase of reserves in place 13 21,300 21,378 Sale of reserves in place (741) (29,179) (33,625) Revisions of previous estimates 2,206 23,894 37,130 Production (523) (17,106) (20,244) --------- --------- -------- DECEMBER 31, 2002 6,574 335,518 374,962 Extensions and discoveries -- 6,164 6,164 Purchase of reserves in place -- 8,988 8,988 Sale of reserves in place (1) (41) (48) Revisions of previous estimates 16 (12,976) (12,880) Production (413) (14,912) (17,389) --------- --------- -------- DECEMBER 31, 2003 6,176 322,741 359,797 ========= ========= ======== PROVED DEVELOPED RESERVES December 31, 2001 4,788 218,148 246,876 ========= ========= ======== December 31, 2002 4,103 206,719 231,337 ========= ========= ======== December 31, 2003 3,809 212,494 235,348 ========= ========= ========
(1) THOUSAND BARRELS (2) MILLION CUBIC FEET (3) MILLION CUBIC FEET EQUIVALENT F-29 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, ----------------------------------------------- 2003 2002 2001 ------------- ------------- ------------- (IN THOUSANDS) Estimated future cash inflows (outflows) Revenues from the sale of oil and gas $ 2,180,423 $ 1,855,414 $ 1,075,151 Production costs (471,563) (423,643) (396,654) Development costs (168,874) (167,295) (130,723) ------------- ------------- ------------- Future net cash flows before income taxes 1,539,986 1,264,476 547,774 Future income taxes (511,160) (412,193) (133,992) ------------- ------------- ------------- Future net cash flows 1,028,826 852,283 413,782 10% timing discount (612,929) (519,464) (231,920) ------------- ------------- ------------- Standardized measure of discounted future net cash flows $ 415,897 $ 332,819 $ 181,862 ============= ============= =============
At December 31, 2003, 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 weighted average prices for the total proved reserves at December 31, 2003 were $6.19 per Mcf of natural gas and $29.78 per barrel of oil. The Company does not include its natural gas hedging financial instruments, consisting of natural gas swaps and collars, in the determination of its oil and gas reserves. F-30 The principal sources of changes in the standardized measure of future net cash flows are as follows:
YEAR ENDED DECEMBER 31, ----------------------------------------------- 2003 2002 2001 ------------- ------------- ------------- (IN THOUSANDS) Beginning of year $ 332,819 $ 181,862 $ 820,764 Sale of oil and gas, net of production costs (63,722) (73,351) (72,132) Extensions and discoveries, less related estimated future development and production costs 24,144 7,153 8,721 Purchase of reserves in place less estimated future production costs 10,193 26,385 7,924 Sale of reserves in place less estimated future production costs (60) (16,727) (3,226) Revisions of previous quantity estimates (23,296) 53,423 (63,294) Net changes in prices and production costs 153,492 239,368 (1,026,055) Change in income taxes (34,288) (103,641) 371,059 Accretion of 10% timing discount 47,959 22,499 123,495 Changes in production rates (timing) and other (31,344) (4,152) 14,606 ------------- ------------- ------------- End of year $ 415,897 $ 332,819 $ 181,862 ============= ============= =============
(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 marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. The Company's operations are conducted entirely in the United States. MAJOR CUSTOMERS During 2003 the Company had three customers that each accounted for 10% or more of consolidated revenues with sales of $19.8 million, $11.5 million and $10.8 million, respectively. One customer accounted for more than 10% of consolidated revenues during each of the years ended December 31, 2002 and 2001, sales to which amounted to $12.9 million and $21.0 million, respectively. F-31 (18) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The results of operations for the four quarters of 2003 and 2002 are shown below (in thousands).
FIRST SECOND THIRD FOURTH ------------ ------------ ------------ ------------ 2003 ---- Operating revenues $ 27,531 $ 27,262 $ 26,409 $ 27,562 Gross profit 8,198 9,556 5,451 5,282 Income (loss) from continuing operations before cumulative effect of change in accounting principle 395 1,699 (1,641) (5,063) (Loss) income from discontinued operations, net of tax (25) (86) -- -- Net income (loss) 2,768 1,612 (1,641) (5,063) 2002 ---- Operating revenues $ 28,488 $ 30,217 $ 26,561 $ 26,820 Gross profit 9,488 9,706 8,045 5,447 Income (loss) from continuing operations 1,509 2,118 1,068 (950) (Loss) income from discontinued operations, net of tax (65) 462 75 (1,752) Net income (loss) 1,444 2,580 1,143 (2,702)
During 2003, the Company recorded exploratory dry hole expense of approximately $8.5 million, of which $4.1 million and $4.2 million were incurred in the third and fourth quarters, respectively. In the fourth quarter of 2003, the Company recorded impairments of $5.2 million related to unproved properties and $572,000 related to producing properties. During the fourth quarter of 2002, the Company recorded a loss on sale of $3.2 million ($1.8 million net of tax benefit) from discontinued operations (see Note 4). Sales and gross profit for the first three quarters in 2002 were restated in the fourth quarter of 2002 to reflect the discontinued operations. During 2002, the Company recorded exploratory dry hole expense of approximately $4.6 million, of which $2.2 million was incurred in the fourth quarter. (19) SUBSEQUENT EVENT On March 9, 2004, the Company announced that it had engaged Randall & Dewey Partners, L.P., an oil and gas strategic advisory and consulting firm based in Houston, Texas, to assist the Company in evaluating its strategic alternatives. F-32