Item 1. BUSINESS --------
GENERAL
Belden & Blake Corporation, an Ohio corporation (the "Company"), is primarily engaged in producing oil and natural gas, acquiring and enhancing the economic performance of producing oil and gas properties, exploring for and developing natural gas and oil reserves and gathering and marketing natural gas. Until 1995, the Company conducted business exclusively in the Appalachian Basin where it has operated since 1942 through several predecessor entities. It is now one of the largest exploration and production companies operating in the Appalachian Basin in terms of reserves, acreage held and wells operated. In early 1995, the Company commenced operations in the Michigan Basin through the acquisition of Ward Lake Drilling, Inc., an exploration and production company, which owns and operates oil and gas properties in Michigan's lower peninsula. In September 1996, the Company entered the Illinois Basin by acquiring the Shrewsbury Field in northwestern Kentucky.
At December 31, 1996, the Company owned interests in 7,721 gross (6,462 net) productive gas and oil wells in Ohio, West Virginia, Pennsylvania, New York, Michigan and Kentucky with proved reserves totaling 288.6 Bcf (billion cubic feet) of gas and 7.4 MMBbl (million barrels) of oil. The estimated future net revenues from these reserves had a present value before income taxes of approximately $356.0 million at December 31, 1996. At that date, the Company held leases on 1,153,800 gross (1,019,100 net) acres, including 565,900 gross (504,800 net) undeveloped acres.
At December 31, 1996, the Company operated more than 7,600 wells, including wells operated for third parties. The Company owned and operated approximately 2,760 miles of gas gathering systems with access to the commercial and industrial gas markets of the northeastern United States at December 31, 1996. At December 31, 1996, the Company's net production was approximately 72 MMcf (million cubic feet) of gas and 1,850 Bbls (barrels) of oil per day. At that date, the Company was marketing approximately 137 MMcf of gas per day, consisting of its own production and gas purchased from third parties.
The Company was formed through the combination of a group of companies and assets owned by Henry S. Belden IV with Belden & Blake Energy Company, a master limited partnership listed on the American Stock Exchange, and Belden & Blake International Limited, a Bermuda corporation listed on the Luxembourg Stock Exchange. The transactions combining these entities were effected on March 31, 1992.
The Company has grown principally through the acquisition of producing properties and related gas gathering facilities and exploration and development of its own acreage. From its formation in 1992 through December 31, 1996, the Company has acquired for $129.4 million producing properties with 192.9 Bcfe (billion cubic feet of natural gas equivalent) of proved developed reserves at an average cost of $.67 per Mcfe (thousand cubic feet of natural gas equivalent) and spent $19.9 million to acquire and develop additional gas gathering facilities. During the period from 1992 through 1996, the Company drilled 547 gross (409.9 net) wells at an aggregate cost of approximately $74.6 million for the net wells. This drilling added 82.2 Bcfe to the Company's proved reserves. During 1996, the Company drilled 207 gross (160.7 net) wells at a direct cost of approximately $31.2 million for the net wells. The 1996 drilling activity added 40.4 Bcfe of proved reserves, which represents approximately 136% of 1996 production at an average cost of $.77 per Mcfe.
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.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The Company operates in two industry segments: (1) oil and gas production and distribution and (2) oilfield sales and service. Oilfield sales are generated by its wholly-owned subsidiary, Target Oilfield Pipe and Supply Company and oilfield services are provided by its Arrow Oilfield Service division. The financial information with respect to the industry segments is shown in Note 15 to the Consolidated Financial Statements.
In September 1995, the Company announced plans to sell Engine Power Systems, Inc. ("EPS"), its wholly-owned subsidiary engaged in engine, parts and service sales. The Company was unable to identify an acceptable buyer for EPS. Since September 1995, a substantial portion of the work force was eliminated and substantial assets were sold. The financial information with respect to discontinued operations is presented in Note 17 to the Consolidated Financial Statements.
DESCRIPTION OF BUSINESS
OVERVIEW
The Company, founded in 1942, is actively engaged in the acquisition, exploration, development, production, gathering and marketing of oil and gas in the Appalachian, Michigan and Illinois Basins. The Company operates principally in the Appalachian and Michigan Basins where it is now one of the largest oil and gas companies in terms of reserves, acreage held and wells operated, and it recently commenced operations in the Illinois Basin.
The Appalachian Basin is the oldest and geographically one of the largest oil and gas producing regions in the United States. Although the Appalachian Basin has sedimentary formations indicating the potential for oil and gas reservoirs to depths of 30,000 feet or more, oil and gas is currently produced primarily from shallow, highly developed blanket formations at depths of 1,000 to 5,500 feet. Drilling success rates of the Company and others drilling in these formations historically have exceeded 90% with production generally lasting longer than 20 years.
The combination of long-lived production and high drilling success rates at these shallower depths has resulted in a highly fragmented, extensively drilled, low technology operating environment in the Appalachian Basin. As of December 31, 1996, there were over 10,000 independent operators of record and approximately 180,000 producing oil and gas wells in Ohio, West Virginia, Pennsylvania and New York. There has been only limited testing or development of the formations below the existing shallow production in the Appalachian Basin. Fewer than 2,000 wells have been drilled to a depth greater than 7,500 feet, and fewer than 100 wells have been drilled to a depth greater than 12,500 feet in the entire Appalachian Basin. As a result, the Company believes that there are significant exploration and development opportunities in these less developed formations for those operators with the capital, technical expertise and ability to assemble the large acreage positions needed to justify the use of advanced exploration and production technologies.
In January 1995, the Company purchased Ward Lake Drilling, Inc. ("Ward Lake"), a privately-held exploration and production company headquartered in Gaylord, Michigan, for $15.1 million and commenced operations in the Michigan Basin. Ward Lake held production payment and working interests averaging 13.6% in approximately 500 Antrim Shale gas wells operated by Ward Lake in Michigan's lower peninsula. The purchase also included approximately 5,500 undeveloped leasehold acres that Ward Lake owned in Michigan. Through December 31, 1996, the Company purchased additional working interests averaging 24% in these wells. The Company's primary objective in acquiring Ward Lake was to allow the Company to pursue opportunities in the Michigan Basin with an established operating company that provided the critical mass to operate efficiently.
In September 1995, the Company purchased an average working interest of 78% in 24 Antrim Shale wells and a 100% working interest in undeveloped Antrim Shale locations on approximately 17,000 leasehold acres. The wells acquired had extended the Antrim Shale productive area to northwestern Michigan and the undeveloped locations were in proximity to the producing wells.
In September 1996, the Company commenced operations in the Illinois Basin by acquiring a 100% working interest in 98 natural gas wells and an extensive gas gathering system in the Shrewsbury Field located in northwestern Kentucky.
The Company's rationale for entering the Michigan and Illinois Basins was based on their geologic and operational similarities to the Appalachian Basin and their geographic proximity to the Company's operations in the Appalachian Basin. Geologically, the Michigan and Illinois Basins resemble the Appalachian Basin with shallow blanket formations and deeper formations with greater reserve potential. Operationally, economies of scale and cost containment are essential to operating profitability. The operating environment in each of these basins is also highly fragmented with substantial acquisition opportunities.
Most of the Company's production in the Michigan Basin is derived from the shallow (700 to 1,700 feet) blanket Antrim Shale formation which has not been extensively developed. Success rates for companies drilling to this formation have exceeded 90%, with production often lasting as long as 20 years. The Michigan Basin also contains deeper formations with greater reserve potential. The Company has also established production from certain of these deeper formations through its drilling operations. The Michigan Basin has approximately 100 operators of record, most of which are private companies, and more than 8,000 producing wells. Because the production rate from Antrim Shale wells is relatively low, cost containment is a crucial aspect of operations. In contrast to the shallow, highly developed blanket formations in the Appalachian Basin, the operating environment in the Antrim Shale is more capital intensive because of the low natural reservoir pressures and the high initial water content of the formation.
The Company's production in the Illinois Basin is primarily from the New Albany Shale formation, which is a stratigraphic equivalent of the Antrim Shale formation. The New Albany Shale has likewise not been widely developed. The New Albany Shale has similar operating characteristics to shale formations in the adjacent Appalachian and Michigan Basins from which the Company is currently producing.
The proximity of the Appalachian and Michigan Basins to large commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices that since 1986 have ranged from $0.31 to $1.30 per Mcf (thousand cubic feet) above national wellhead prices. The Company's
average wellhead gas price in 1996 was $0.31 per Mcf above the estimated average national wellhead price.
BUSINESS STRATEGY
The Company's primary operating objective is to utilize its sizable acreage position, technical capability and financial resources to become a dominant oil and gas producer and natural gas marketer in its operating areas. To accomplish this objective, the Company's specific business strategy is to:
- expand production and reserves through a balanced portfolio of developmental and exploratory drilling;
- make strategic acquisitions of producing oil and gas properties;
- improve profitability on the production from existing and acquired properties; and
- expand its gas gathering and marketing activities.
This strategy is intended to enable the Company to take advantage of (i) the significant exploration and development opportunities in the deeper and potentially more productive formations in the Appalachian, Michigan and Illinois Basins, (ii) the Company's technical knowledge and experience in those areas, and (iii) the availability of producing properties for sale in the Appalachian, Michigan and Illinois Basins.
ACQUISITION OF PRODUCING PROPERTIES
The Company's acquisition strategy focuses on producing properties that (i) the Company already owns an interest in and operates or that are strategically located in relation to its existing operations, (ii) can be increased in value through operating cost reductions, advanced production technology, mechanical improvements, recompleting or reworking wells and/or the use of enhanced and secondary recovery techniques, (iii) provide development drilling opportunities or enhance the Company's acreage position, (iv) have the potential for increased revenues from gas production through the Company's gas marketing capabilities or (v) are of sufficient size to allow the Company to operate efficiently in new areas. Using these criteria, the Company employs a disciplined approach to acquisition analysis that requires input and approval from all key areas of the Company. These areas include field operations, exploration and production, finance, gas marketing, land management and environmental compliance. Although the Company often reviews in excess of 50 acquisition opportunities per year, this disciplined approach can result in uneven annual spending on acquisitions. The following table sets forth information pertaining to acquisitions completed during the period 1992 through 1996.
During 1996, the Company acquired for approximately $4.1 million working interests in 323 oil and gas wells in Ohio and Kentucky. Estimated proved developed reserves associated with the wells total 6.0 Bcf of natural gas and 205,000 Bbls of oil net to the Company's interest at July 1, 1996.
SALE OF TAX CREDIT PROPERTIES
In February and March 1996, the Company sold certain interests that qualify for the nonconventional fuel source tax credit. The interests were sold in two separate transactions for approximately $750,000 and $100,000, respectively, in cash and a volumetric production payment under which 100% of the cash flow from the properties will go to the Company until approximately 11.7 Bcf and 3.4 Bcf, respectively, of gas has been produced and sold. In addition, the Company will receive quarterly incentive payments based on production from the interests. The Company has the option to repurchase the interests at a future date.
OIL AND GAS OPERATIONS AND PRODUCTION
Operations. The Company serves as the operator of substantially all of the wells in which it holds working interests. The Company seeks to maximize the value of its properties through operating efficiencies associated with economies of scale and through operating cost reductions, advanced production technology, mechanical improvements and/or the use of enhanced and secondary recovery techniques.
Through its production field offices in Ohio, West Virginia, Pennsylvania, New York, Michigan and Kentucky, the Company continuously reviews its properties, especially recently acquired properties, to determine what action can be taken to reduce operating costs and/or improve production. The Company has reduced field level costs through improved operating practices such as computerized
production scheduling and the use of hand-held computers to gather field data. On acquired properties, further efficiencies may be realized through improvements in production scheduling and reductions in oilfield labor. Actions that may be taken to improve production include modifying surface facilities and redesigning downhole equipment.
The Company may also implement enhanced and secondary recovery techniques. Secondary recovery methods typically involve all methods of oil extraction in which extrinsic energy sources are applied to extract additional reserves. The principal secondary recovery technique used by the Company is waterflooding, which the Company has used in Ohio and Pennsylvania.
Production. The following table sets forth certain information regarding oil and gas production from the Company's properties:
EXPLORATION AND DEVELOPMENT
The Company's exploration and development activities include development drilling in the highly developed or blanket formations and development and exploratory drilling in the less developed formations of the Appalachian, Michigan and Illinois Basins. The Company's strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential. The Company has an extensive inventory of acreage on which to conduct its exploration and development activities.
In 1996, the Company drilled 155 gross (128.3 net) wells to highly developed or shallow blanket formations in its six state operating area at a direct cost of approximately $22.2 million for the net wells. The Company also drilled 52 gross (32.4 net) wells to less developed and deeper formations in 1996 at a direct cost of approximately $9.0 million for the net wells. The result of this drilling activity is shown in the tables on page 10.
The Company believes that its diversified portfolio approach to its drilling activities results in more consistent and predictable economic results than might be experienced with a less diversified or higher risk drilling program profile.
Highly Developed Formations. In general, the highly developed or blanket formations found in the Appalachian, Michigan and Illinois Basins are widespread in extent and hydrocarbon accumulations are not dependent upon local stratigraphic or structural trapping. Drilling success rates exceed 90%. The principal risk of such wells is uneconomic recoverable reserves.
The highly developed formations in the Appalachian Basin are relatively tight reservoirs that produce 20% to 30% of their recoverable reserves in the first year and 40% to 50% of their total recoverable reserves in the first three years, with steady declines in subsequent years. Average well lives range from 15 years to 25 years or more.
The Antrim Shale formation, the principal highly developed or shallow blanket formation in the Michigan Basin, is characterized by high formation water production in the early years of a well's productive life, with water production decreasing over time. Antrim Shale wells typically produce at rates of 100 Mcf to 125 Mcf per day for several years, with modest declines thereafter. Gas production often increases in the early years as the producing formation becomes less water saturated. Average well lives are 20 years or more.
In the Illinois Basin, the highly developed or shallow blanket formations include the New Albany Shale formation as well as the Mississippian sandstones. Production characteristics of the New Albany Shale are very similar to the Devonian Shale from which the Company produces in West Virginia.
Certain typical characteristics of the highly developed or blanket formations drilled by the Company in 1996 are described below:
The Company plans to drill approximately 200 wells to highly developed or blanket formations in 1997.
Less Developed Formations. The Appalachian Basin has productive and potentially productive sedimentary formations to depths of 30,000 feet or more, but the combination of long-lived production and high drilling success rates in the shallow formations has curbed the development of the deeper formations in the basin. The Company believes it possesses the technological expertise and the acreage position needed to explore the deeper formations in a cost effective manner.
The less developed formations in the Appalachian Basin include the Knox sequence of sandstones and dolomites which includes the Rose Run, Beekmantown and Trempeleau productive zones, at depths ranging from 2,500 feet to 8,000 feet. The geographical boundaries of the Knox sequence, which lies approximately 2,000 feet below the highly developed Clinton Sandstone, are generally well defined in Ohio with less definition in New York. Nevertheless, the Knox group has been only lightly explored, with fewer than 2,000 wells drilled to this sequence of formations during the past 10 years.
The Company began testing the Knox sequence in 1989 by selecting certain wells that were targeted to be completed to the Clinton formation and drilling them an additional 2,000 feet to 2,500 feet to test the Knox formations. In 1991, the Company began using seismic analysis and other geophysical tools to select drilling locations specifically targeting the Knox formations. Since 1991, the Company has added substantially to its technical staff to enhance its ability to develop drilling prospects in the Knox and other less developed formations in the Appalachian Basin and the deeper formations in the Michigan Basin. The following table shows the Company's drilling results in the Knox sequence:
The Company's historical experience is that the average Knox well produces 20% to 25% of its recoverable reserves in the first year of production and approximately 50% of its recoverable reserves in the first three years with a steady decline thereafter. Wells in the Knox formations have an expected productive life ranging from 15 to 25 years.
As shown in the following table, the Company's production from Knox formation wells has increased steadily as additional wells have been drilled.
Productive Knox wells represented less than 1% of the Company's total productive wells at December 31, 1996. Production from Knox wells in 1996, however, equaled 11% of the Company's total production on an Mcfe basis.
The Company is well positioned to exploit the undeveloped potential of the Knox formations in the future. At December 31, 1996, it held leases on approximately 598,200 net acres overlying potential Knox drilling locations. The Company plans to drill or participate in joint ventures to drill 39 gross (22.1 net) wells to the Knox formations in 1997.
In addition, the Company has also tested the Niagaran Carbonate, Dundee Carbonate, Onondaga Limestone, Oriskany Sandstone and Newburg Sandstone formations. The Company plans to drill approximately 25 gross (21.7 net) wells to these formations in 1997. Certain typical characteristics of the less developed or deeper formations drilled by the Company in 1996 are described below:
Drilling Results. The following table sets forth drilling results with respect to wells drilled during the past five years:
GAS GATHERING AND MARKETING
Gas Gathering. The Company operates approximately 2,760 miles of natural gas gathering lines in Ohio, West Virginia, Pennsylvania, New York, Michigan and Kentucky which are tied directly to various interstate natural gas transmission systems. The interconnections with these interstate pipelines afford the Company potential marketing access to numerous major gas markets. The Company earned gathering revenues of $6.3 million in 1996. Direct costs associated with gas gathering in 1996 totaled approximately $2.1 million.
Gas Marketing. The major industrial centers of Akron, Buffalo, Canton, Chicago, Cleveland, Detroit and Pittsburgh are all located in close proximity to the Company's operations and provide a large potential market for direct natural gas sales. At present, the Company markets directly to approximately 200 customers in a six-state area. The Company focuses its gas marketing efforts on small to mid-sized industrial customers that require more service and have the potential to generate higher margins per Mcf than large industrial users.
The Company sells the gas it produces to its commercial and industrial customers, local distribution companies and on the spot market. In addition to its own production, the Company buys gas from other producers and third parties and resells it. At December 31, 1996, the Company marketed approximately 137 MMcf of gas per day of which approximately 53% consisted of its own production. Gas sold by the Company to end users and local distribution companies is usually sold pursuant to contracts which extend for periods of one or more years at either fixed prices or market sensitive prices. Gas sold on the spot market is generally priced on the basis of a regional index. Since late 1995, the Company has attempted to maintain a balance between gas volumes sold under fixed price contracts and volumes sold under market sensitive contracts. At December 31, 1996, approximately 50% of the gas marketed by the Company was at fixed prices and 50% was at market sensitive prices. This contract strategy is intended to reduce price volatility and place a partial floor under the price received while still maintaining the potential for gains from upward movement in market sensitive prices.
The Company has a policy which governs its ability to trade in the financial futures markets. The Company may, from time to time, partially hedge its contract prices by selling futures contracts on the New York Merchantile Exchange ("NYMEX"). At December 31, 1996, the Company did not have any open futures contracts. The Company has entered into a number of market sensitive contracts which allow it to select the price at which future months' deliveries will be sold, based on a regional index or a negotiated positive basis above the relevant NYMEX price. These "triggering" contracts allow the Company to effectively hedge contract prices without selling futures contracts and take advantage of periodic price spikes on the NYMEX.
The following table shows the type of buyer for gas marketed by the Company at December 31, 1996:
OILFIELD SALES AND SERVICE
The Company has provided its own oilfield services for more than 30 years in order to assure quality control and operational and administrative support to its exploration and production operations. In 1992, Arrow Oilfield Service Company ("Arrow"), a separate service division, was organized. Arrow provides the Company and third party customers with necessary oilfield services such as well workovers, well completions, brine hauling and disposal and oil trucking. Arrow is currently the largest oilfield service company in Ohio. In June 1995, the Company acquired the assets and assumed the operations of Antrim Services, Inc., an oilfield service company headquartered in Gaylord, Michigan, in order to provide adequate oilfield services to its expanding Michigan operations. In 1996, approximately 55% of Arrow's revenues were generated by sales to third parties.
Target Oilfield Pipe & Supply Company ("TOPS"), a wholly-owned subsidiary of the Company, operates retail sales outlets in the Appalachian and Michigan Basins from which it sells a broad range of equipment, including pipe, tanks, fittings, valves and pumping units. The Company originally entered the oilfield supply business to ensure the quality and availability of supplies for its own operations. In 1996, approximately 67% of TOPS' revenues were generated by sales to third parties.
The Company plans to expand its oilfield sales and service business through continued growth in its six-state market area.
EMPLOYEES
As of February 28, 1997, the Company had 602 full-time employees, including 236 oilfield sales and service employees, 287 oil and gas production employees, 19 petroleum engineers, 10 geologists and 2 geophysicists.
COMPETITION AND CUSTOMERS
The oil and gas industry is highly competitive. Competition is particularly intense with respect to the acquisition of producing properties and the sale of oil and gas production. There is competition among oil and gas producers as well as with other industries in supplying energy and fuel to users.
The competitors of the Company in oil and gas exploration, development, production and marketing include major integrated oil and gas companies as well as numerous independent oil and gas companies, individual proprietors, natural gas pipelines and their affiliates and natural gas marketers and brokers. Many of these competitors possess and employ financial and personnel resources substantially
in excess of those available to the Company. Such competitors may be able to pay more for desirable prospects or producing properties and to evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources of the Company will permit. The ability of the Company to add to its reserves in the future will be dependent on its ability to exploit its current developed and undeveloped lease holdings and its ability to select and acquire suitable producing properties and prospects for future exploration and development.
During the year ended December 31, 1996 there was no customer which accounted for 10% or more of the Company's consolidated revenues. The only customer which accounted for 10% or more of the Company's consolidated revenues during the year ended December 31, 1995 was The East Ohio Gas Company with purchases of $11.1 million.
The only customer which accounted for 10% or more of the Company's consolidated revenues during the year ended December 31, 1994 was Ravenswood Aluminum Corporation ("RAC"), sales to which totaled $9.6 million. The Company's contract with RAC, its principal gas purchaser in West Virginia, requires it to deliver 10 billion Btus (approximately 8.9 MMcf) of gas per day through 1998. At present, the Company is supplying this contract requirement by delivering approximately 4.9 billion Btus of its own gas production, 3.8 billion Btus of production from royalty and joint working interest owners in wells in which the Company holds an interest and 1.3 billion Btus of gas purchased from third parties.
The contract price at which gas is delivered to RAC for 1997 is $3.83 per MMBtu. The RAC contract also provides for a discount from the contract price if gas is available under the same terms and conditions from an arms-length third party at a price of less than 70% of the contract price. The discount is equal to one-half of the difference between the lower available price and the contract price and applies to volumes of gas for plant requirements in excess of 6,000 MMBtus per day. RAC unilaterally took discounts totaling $397,000, $863,000 and $897,000 in 1994, 1995 and 1996, respectively. The Company has contested RAC's interpretation of the contract and may initiate legal action to recover part or all of the discounts taken.
To protect itself against an interruption or reduction in the income stream under the RAC contract, the Company required the seller of the properties subject to the RAC contract to partially secure the delivered gas price the Company would receive under the contract with a declining letter of credit initially issued by Citibank, N.A. (Citibank, N.A. was replaced by Nationsbank, N.A. in August, 1996) and Chase Manhattan Bank, N.A. in the original amount of $10.7 million, approximately $3.3 million of which is available for drawing in 1997. The Company is entitled to draw against the letter of credit annually if it receives less than a specified minimum average delivered price on gas delivered to RAC under the contract. Consistent with the terms of the letter of credit, the Company was reimbursed directly by the seller of the RAC properties for the discounts taken by RAC in 1994 and 1995 in the amount of $165,000 and $323,000, respectively, and expects to be reimbursed for a portion of the discount taken in 1996.
Regulation
Regulation of Production. In all states in which the Company is engaged in oil and gas exploration and production, its activities are subject to regulation. Such regulations may extend to requiring drilling permits, spacing of wells, the prevention of waste and pollution, the conservation of natural gas and oil, and other matters. Such regulations may impose restrictions on the production of natural gas and oil by reducing the rate of flow from individual wells below their actual capacity to
produce which could adversely affect the amount or timing of the Company's revenues from such wells. Moreover, future changes in local, state or federal laws and regulations could adversely affect the operations of the Company.
Environmental Regulation. The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from the Company's operations. Management believes the Company is in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on the Company.
Regulation of Sales and Transportation. The Federal Energy Regulatory Commission (the "FERC") regulates the transportation and sale for resale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"). In the past, the federal government has regulated the prices at which oil and gas could be sold. Currently, sales by producers of natural gas and all sales of crude oil and condensate in natural gas liquids can be made at uncontrolled market prices.
Item 2.
Item 2. PROPERTIES ----------
OIL AND GAS RESERVES
The following table sets forth the Company's proved oil and gas reserves as of December 31, 1994, 1995 and 1996 determined in accordance with the rules and regulations of the Securities and Exchange Commission. Proved reserves are the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
See Note 14 to the Consolidated Financial Statements for more detailed information regarding the Company's oil and gas reserves. The following table sets forth the estimated future net cash flows from the proved reserves of the Company and the present value of such future net cash flows as of December 31, 1996 determined in accordance with the rules and regulations of the Securities and Exchange Commission.
Estimated future net cash flows represent estimated future gross revenues from the production and sale of proved reserves, net of estimated production costs (including production taxes, ad valorem taxes, operating costs and development costs). Estimated future net cash flows were calculated on the basis of prices and costs estimated to be in effect at December 31, 1996 without escalation, except where changes in prices were fixed and readily determinable under existing contracts. The weighted average prices for oil and gas at December 31, 1996 were $23.00 per barrel and $3.02 per Mcf, respectively.
PRODUCING WELL DATA
The following table summarizes by state the Company's productive wells at December 31, 1996:
ACREAGE DATA
The following table summarizes by state the Company's gross and net developed and undeveloped leasehold acreage at December 31, 1996:
Item 3.
Item 3. LEGAL PROCEEDINGS -----------------
On January 2, 1996, Karen J. Volgstadt, individually and as administrator of the Estate of George A. Volgstadt, filed a complaint in the Supreme Court of Chautauqua County, New York against the Company and a subsidiary of the Company seeking the recovery of $6,000,000 in compensatory damages for the death of George A. Volgstadt in an accident which occurred during the course of his employment with the subsidiary. A Stipulation of Discontinuance with prejudice has been entered by Mrs. Volgstadt with respect to claims against the subsidiary. Accordingly, the remaining claims against the Company relate to the Company's ownership of the real property where the accident occurred. The Company believes that it has valid defenses to each of the claims asserted and that any liability of the Company with respect to this action would be covered by insurance.
The Company is involved in several other lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on the Company's financial position or the results of operations.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ---------------------------------------------------
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
Executive officers of the Company as of February 28, 1997 were as follows:
All executive officers of the Company serve at the pleasure of its Board of Directors. None of the executive officers of the Company is related to any other executive officer or director, except that Henry S. Belden, IV and Dennis D. Belden are brothers. The business experience of each executive officer is summarized below.
HENRY S. BELDEN, IV has been Chairman and Chief Executive Officer of the Company since 1982. Mr. Belden has been involved in oil and gas production since 1955 and associated with Belden & Blake since 1967. Prior to joining Belden & Blake, he was employed by Ashland Oil & Refining Company and Halliburton Services, Incorporated.
Mr. Belden attended Florida State University and the University of Akron and is a member of the 25-Year Club of the Petroleum Industry and the Board of Trustees of the Ohio Oil and Gas Association. He is also a member of the Regional Advisory Board of the Independent Petroleum Association of America and a director and a member of the Executive Committee of the Pennsylvania Grade Crude Oil Association. He is a member of the Interstate Oil Compact Commission. Other professional memberships include the World Business Council and the Association of Ohio Commodores. He is a member of the board of directors of KeyBank-Canton District and Phoenix Packaging Corporation.
MAX L. MARDICK has been President and Chief Operating Officer of the Company since 1990, a director since 1992 and a director of predecessor companies from 1988 to 1992. He previously served as Executive Vice President and Chief Operating Officer from 1988 to 1990. Mr. Mardick is a Petroleum Engineer with more than 35 years of experience in domestic and international production, engineering, drilling operations and property evaluation. Prior to joining Belden & Blake, he was employed for more than 30 years by Shell Oil Company in various engineering, supervisory and senior management positions, including: Manager, Property Acquisitions and Business Development (1986-1988); Production Manager for Shell's Onshore and Eastern Divisions (1981-1986); Production Manager of Shell's Rocky Mountain Division (1980-1981); Operations Manager (1977-1980); and Engineering Manager (1975-1977).
Mr. Mardick holds a BS degree in Petroleum Engineering from the University of Kansas. He is a member of the Society of Petroleum Engineers and the Ohio Oil and Gas Association. He has served as Vice Chairman of the Alabama - - Mississippi section of the Mid-Continent Oil and Gas Association.
RONALD E. HUFF has been Senior Vice President and Chief Financial Officer of the Company since 1989, having previously served as its Senior Controller from 1986 to 1989. Mr. Huff has been a director of Belden & Blake since 1991. He is a Certified Public Accountant with nearly 20 years of experience in oil and gas finance and accounting. From 1983 to 1986, Mr. Huff served as Vice President and Chief Accounting Officer of Towner Petroleum Company. From 1980 to 1983 he worked for Sonat Exploration Company as Manager of Financial Accounting; and from 1977 to 1980 he served as Corporate Accounting Supervisor for Transco Companies, Incorporated. Mr. Huff received a BS degree in Accounting from the University of Wyoming. He is a member of the Ohio Petroleum Accountants Society and the Financial Executives Institute-Northeast Ohio Chapter.
JOSEPH M. VITALE has been Senior Vice President Legal of the Company since 1989 and has served as its General Counsel since 1974. He has been a director of the Company since 1991. Prior to joining Belden & Blake, Mr. Vitale served for four years in the Army Judge Advocate General's Corps. He holds a BS degree from John Carroll University and a JD degree from Case Western Reserve Law School. He is a member of the Ohio Oil and Gas Association, the Stark County, Ohio State and American Bar Associations, and the Interstate Oil Compact Commission. Mr. Vitale is a past Chairman of the Natural Resources Law Committee of the Ohio State Bar Association.
RONALD L. CLEMENTS has been Senior Vice President of Exploration and Production of the Company since 1993 and manages the Company's Exploration and Production Division. He joined Belden & Blake in 1990 and served as Vice President of Producing Operations until appointment to his current position in 1993. He has more than 30 years of petroleum engineering and production experience. Prior to joining Belden & Blake he served as Vice President and District Manager of TXO Production Corporation in Corpus Christi, Texas. From 1967 to 1982, Mr. Clements held various operational management positions with Shell Oil Company.
Mr. Clements received a BS degree in Electrical Engineering from the University of North Dakota and a MS degree in Petroleum Engineering from the University of Tulsa. He is a member of the Society of Petroleum Engineers and the Ohio Oil and Gas Association.
LEO A. SCHRIDER has been Senior Vice President of Technical Development since 1993. He previously served as Senior Vice President of Exploration, Drilling and Engineering for the Company since 1986. Mr. Schrider is a Petroleum Engineer with 35 years of experience in oil and gas production, principally in the Appalachian Basin. Prior to joining Belden & Blake in 1981, he served as Assistant and Deputy Director of Morgantown Energy Technology Center from 1976 to 1980. From 1973 to 1976, Mr. Schrider served as Project Manager of the Laramie Energy Research Center. He has also held various research positions with the U.S. Department of Energy in Wyoming and West Virginia.
Mr. Schrider received his BS degree from the University of Pittsburgh in 1961 and did graduate work at West Virginia University. He has published more than 35 technical papers on oil and gas production. He was an Adjunct Professor at West Virginia University and also served as a member of the International Board of Directors of the Society of Petroleum Engineers. In 1994, Mr. Schrider was elected to the Board of Directors of the Petroleum Technology Transfer Council and is chairman of the producer advisory group representing the Appalachian region.
DENNIS D. BELDEN has served as Vice President of Supply and Service for the Company since 1989 and has managed the Oilfield Supply and Service Division since 1992. He joined Belden & Blake in 1980 and served as the Company's land manager from 1980 to 1989. From 1976 to 1980 he was
employed by Wilmot Mining Company as Special Projects Manager; from 1974 to 1976 he was Treasurer and General Manager of Cabbages & Kings Restaurant of Ohio; and from 1972 to 1974 he was employed by T & M Fuel as General Supervisor. Mr. Belden attended Kent State University. He is a member of the Ohio Oil and Gas Association.
CHARLES P. FABER has been Vice President of Corporate Development for the Company since 1993. He previously served as Senior Vice President of Capital Markets from 1988 to 1993. Prior to joining Belden & Blake, Mr. Faber was employed as Senior Vice President of Marketing for Heritage Asset Management from 1986 to 1988. From 1983 to 1986 he served as President and Chief Executive Officer of Samson Properties, Incorporated. Mr. Faber holds a BA degree in Marketing and an MBA in Finance from the University of Wisconsin. He is a member of the Independent Petroleum Association of America, the National Investor Relations Institute and the Petroleum Investor Relations Association.
TOMMY L. KNOWLES has been Vice President of Production of the Company since January of 1996. He has 24 years of petroleum engineering and production experience. Prior to joining Belden & Blake, Mr. Knowles served as President of FWA Drilling Company, a subsidiary of Texas Oil & Gas Corporation. From 1982 to 1988 he worked for TXO Production Corporation in Sacramento, California, serving in various management positions including Vice President; from 1979 to 1982 he held the position of Drilling and Production Manager for Texas Oil & Gas Corporation; and, from 1973 to 1979 he held various engineering, supervisory and management positions with Exxon Corporation.
Mr. Knowles holds a BS degree in Mechanical Engineering from the University of Texas at Austin where he graduated with honors. He is a member of the Society of Petroleum Engineers, the American Petroleum Institute, and the Independent Association of Drilling Contractors.
DONALD A. RUTISHAUSER has been Vice President and Treasurer of the Company since 1989, having previously served as Senior Financial Analyst from 1987 to 1989. Prior to joining Belden & Blake, he was employed by Grace Energy Corporation as Financial Project Manager. Mr. Rutishauser received a BA degree in Economics from Dartmouth College and an MBA in Accounting and Finance from the University of Michigan.
DEAN A. SWIFT has served as Vice President, Assistant General Counsel and Assistant Secretary of the Company since 1989. He served as Assistant General Counsel of the Company from 1981 to 1989. From 1978 to 1981 he was associated with the law firm of Hahn, Loeser and Parks in Cleveland, Ohio. Mr. Swift received a BA degree from the University of the South and a JD degree from the University of Virginia. He is a member of the Stark County, Ohio State and American Bar Associations.
PART II -------
Item 5.
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED ----------------------------------------------------- STOCKHOLDER MATTERS -------------------
The Company's Common Stock trades on the Nasdaq National Market tier of The Nasdaq Stock Market under the Symbol: "BELD."
The following table sets forth the high and low sales prices for the Common Stock of the Company for the periods indicated as reported by the Nasdaq National Market:
The approximate number of record holders of the Company's equity securities at February 28, 1997 was as follows:
Number of Title of Class Record Holders - --------------------------------------- --------------------- Common Stock 1,818 Class II Serial Preferred Stock $7.50 Series A 1
Dividends
No dividends have been paid on the Company's Common Stock and none are expected to be paid in the foreseeable future. The Class II Serial Preferred Stock $7.50 Series A is entitled to cumulative quarterly dividends at the annual rate of $7.50 per share.
Item 6.
Item 6. SELECTED FINANCIAL DATA -----------------------
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL ------------------------------------------------- CONDITION AND RESULTS OF OPERATIONS -----------------------------------
The following discussion should be read in conjunction with the Company's Consolidated Financial Statements and Notes thereto and the Selected Financial Information included elsewhere in this report.
GENERAL
On March 31, 1992, the Company succeeded to the Belden Interests. The transaction was accounted for on the basis of historical cost in a manner similar to a pooling of interests. As a result,
the consolidated financial statements of the Company reflect the combined historical results of operations of only the Belden Interests prior to March 31, 1992.
Also on March 31, 1992, the Company acquired the assets and assumed the liabilities of Belden & Blake Energy Company (the "Partnership") and Belden & Blake International Limited ("BBI") in exchange for shares of common stock pursuant to the consolidation of the Partnership and BBI (the "Consolidation"). The Consolidation was accounted for as a purchase, and the results of operations of the Partnership and BBI have been included from that date.
Prior to March 31, 1992, the Company was engaged principally in managing the assets and business activities of the Partnership, BBI and non-affiliated entities and in gas gathering and marketing. Accordingly, a significant portion of the Company's income was derived from transactions with the Partnership and BBI, including well operating fees, sales of oilfield supplies and services at fixed mark-ups over cost and fees for accounting and related services. Since March 31, 1992, the Company's principal business has been the acquisition, development and production of, and exploration for, oil and gas reserves, principally in Ohio, West Virginia, Pennsylvania, Michigan, New York and Kentucky, and the gathering and marketing of natural gas. Consequently, the historical statements of operations prior to the Consolidation do not reflect the Company's current or planned business activities.
The Company utilizes the "successful efforts" method of accounting for its oil and gas properties. Under this method, property acquisition and development costs and productive exploration costs are capitalized while non-productive exploration costs, which include dry holes, expired leases and delay rentals, are expensed as incurred. Capitalized costs related to proved properties are depleted using the unit-of-production method. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.
The Company's gas gathering and marketing operations consist of purchasing gas at the wellhead and from interstate pipelines and selling gas to industrial customers and local gas distribution companies. The cost of gas purchased from the Company is the wellhead price stipulated by the well operating agreements and is included in "Cost of gas and gathering expense."
The Company provides oilfield sales and services to its own operations and to third parties. Oilfield sales and service provided to the Company's own operations are provided at cost and all intercompany revenues and expenses are eliminated in consolidation. Prior to the Consolidation, revenues from oilfield sales and service provided to the Partnership and BBI were accounted for as third-party revenues.
RESULTS OF OPERATIONS
1996 COMPARED TO 1995
OIL AND GAS SALES. Oil and gas sales increased $32.6 million (70%) in 1996 compared to 1995 due to an increase in oil and gas volumes sold and a higher average price paid for the Company's oil and gas.
Oil volumes increased 163,000 Bbls (29%) from 556,000 Bbls in 1995 to 719,000 Bbls in 1996 resulting in an increase in oil sales of approximately $2.7 million. Gas volumes increased 8.4 Bcf (50%)
from 17.0 Bcf in 1995 to 25.4 Bcf in 1996 resulting in an increase in gas sales of approximately $18.7 million. These volume increases were primarily due to production from properties acquired in 1995 and wells drilled in 1995 and 1996.
The average price paid for the Company's oil increased from $16.78 per barrel in 1995 to $20.24 per barrel in 1996 which increased oil sales by approximately $2.5 million. The average price paid for the Company's natural gas increased $.35 per Mcf to $2.56 per Mcf in 1996 compared to 1995 resulting in increased gas sales of approximately $8.9 million.
GAS MARKETING AND GATHERING REVENUE. Gas marketing and gathering revenue increased $4.1 million (10%) from $40.4 million in 1995 to $44.5 million in 1996 primarily due to an increase in the volume of gas purchased from third parties and resold and an increase in the average selling price of gas.
OILFIELD SALES AND SERVICE REVENUE. Oilfield sales and service revenue increased $5.4 million (27%) from $20.1 million in 1995 to $25.5 million in 1996. This increase was primarily due to the sales generated by the three oilfield sales and service companies acquired by the Company in 1995 and increased third party oilfield sales and service revenue.
INTEREST AND OTHER REVENUE. Interest and other revenue increased $1.0 million (36%) from $2.7 million in 1995 to $3.7 million in 1996 primarily due to the recognition of income in 1996 from incentive production payments associated with certain properties operated by Ward Lake, partially offset by the recognition in 1995 of anticipated proceeds from contract rejection claims that were filed in the bankruptcy proceedings of Columbia Gas Transmission Corporation. Amounts included in income related to the Columbia claims were $1.3 million in 1995 and $276,000 in 1996. Payment of these claims was received by the Company in January, 1997.
PRODUCTION EXPENSE. Production expense increased $6.3 million (54%) from $11.8 million in 1995 to $18.1 million in 1996. This increase was primarily due to the increased production volumes discussed above and a reduction in operating fees charged to third parties. Such fees are recorded as a reduction of production expense. The average production cost per equivalent Mcf of natural gas excluding taxes increased from $.58 per Mcfe in 1995 to $.61 per Mcfe in 1996.
PRODUCTION TAXES. Production taxes increased $1.1 million (54%) from $2.1 million in 1995 to $3.2 million in 1996. This increase was primarily due to the increased production volumes discussed above.
COST OF GAS AND GATHERING EXPENSE. Cost of gas and gathering expense increased $3.8 million (11%) from $33.8 million in 1995 to $37.6 million in 1996 due to an increase in volumes of gas purchased and an increase in the cost of gas.
OILFIELD SALES AND SERVICE EXPENSE. Oilfield sales and service expense increased $4.8 million (27%) from $18.3 million in 1995 to $23.1 million in 1996 primarily as a result of the increased cost of goods sold associated with the increased sales described above.
EXPLORATION EXPENSE. Exploration expense increased $1.2 million (23%) from $4.9 million in 1995 to $6.1 million in 1996 primarily due to higher levels of geological, geophysical and leasing activity and increases in the size of the technical staff in conjunction with increased drilling activity.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased $771,000 (20%) from $3.8 million in 1995 to $4.6 million in 1996 due to increases in employee compensation and benefits, an increase in profit sharing and bonuses and investment banking and other professional fees.
INTEREST EXPENSE. Interest expense increased $1.3 million (22%) from $6.1 million in 1995 to $7.4 million in 1996. This increase was primarily due to higher average debt balances incurred to finance the 1995 acquisitions (Note 3 - "Acquisitions").
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization increased by $10.1 million (51%) from $19.7 million in 1995 to $29.8 million in 1996. Depletion expense increased $7.9 million (53%) from $15.1 million in 1995 to $23.0 million in 1996. This increase was primarily due to additional depletion expense associated with the increased production volumes described above. Depletion per Mcfe increased from $.74 per Mcfe in 1995 to $.77 per Mcfe in 1996. This increase was primarily the result of proved reserves added through acquisitions and drilling at a higher cost per Mcfe.
FRANCHISE, PROPERTY AND OTHER TAXES. Franchise, property and other taxes increased by $511,000 (42%) from $1.2 million in 1995 to $1.7 million in 1996. Franchise taxes increased approximately $350,000 due to the increase in shareholders' equity as a result of the common stock issued in 1995 and the increase in net income retained in the business.
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES. Income from continuing operations before income taxes increased $13.4 million (159%) from $8.4 million in 1995 to $21.8 million in 1996. The oil and gas operations segment increased operating income $12.4 million (99%) from $12.4 million in 1995 to $24.8 million in 1996. The increase was attributable to the items discussed above. The oilfield sales and service segment operating income increased $290,000 (43%) from $673,000 in 1995 to $963,000 in 1996.
INCOME FROM CONTINUING OPERATIONS. Income from continuing operations increased $8.9 million (143%) from $6.3 million in 1995 to $15.2 million in 1996. This increase in income from continuing operations was primarily the result of the items discussed above. Provision for income taxes from continuing operations increased $4.4 million (205%) from $2.2 million in 1995 to $6.6 million in 1996. This increase was attributable to the increase in income from continuing operations before income taxes and an increase in the effective tax rate. The increase in the effective tax rate was primarily due to the decrease of nonconventional fuel source tax credits as a percentage of income from continuing operations. Earnings from continuing operations on a per common share basis increased from $.69 per share in 1995 to $1.34 per share in 1996. This increase was primarily the result of the factors discussed above.
LOSS FROM DISCONTINUED OPERATIONS. Loss from discontinued operations was $675,000 ($439,000 net of tax benefit or $.04 per share) in 1996 compared to $1,761,000 ($1,139,000 net of tax benefit or $.13 per share) in 1995. The losses in 1996 and 1995 include losses on assets sold, the write-down of various assets and inventories to estimated realizable value and a provision for estimated costs of asset disposals and future losses.
1995 COMPARED TO 1994
OIL AND GAS SALES. Oil and gas sales increased $14.3 million (44%) in 1995 compared to 1994 due primarily to an increase in oil and gas volumes sold and a higher average price paid for the
Company's oil. These increases more than offset a lower average price paid for the Company's natural gas.
Oil volumes increased 60,000 Bbls (12%) from 496,000 Bbls in 1994 to 556,000 Bbls in 1995 resulting in an increase in oil sales of approximately $1.0 million. Gas volumes increased 7.4 Bcf (77%) from 9.6 Bcf in 1994 to 17.0 Bcf in 1995 resulting in an increase in gas sales of approximately $19.1 million. These volume increases were primarily due to production from the Company's 1995 acquisitions and from wells drilled in 1994 and 1995. Gas volumes produced in 1995 were less than the Company's full production potential as a result of the Company's decision to curtail gas production due to low spot market gas prices. Interstate pipeline repairs and construction in Michigan and West Virginia also reduced potential production volumes.
The average price paid for the Company's oil increased from $15.98 per barrel in 1994 to $16.78 per barrel in 1995 which increased oil sales by approximately $450,000. The average price paid for the Company's natural gas decreased $.37 per Mcf to $2.21 per Mcf in 1995 compared to 1994 resulting in decreased gas sales of approximately $6.3 million.
GAS MARKETING AND GATHERING REVENUE. Gas marketing and gathering revenue increased $7.3 million (22%) from $33.1 million in 1994 to $40.4 million in 1995 primarily due to the Company's 1995 acquisitions. Increased volumes of gas purchased from third parties and resold were offset by a lower average selling price .
OILFIELD SALES AND SERVICE REVENUE. Oilfield sales and service revenue increased $6.9 million (53%) from $13.2 million in 1994 to $20.1 million in 1995. This increase was primarily due to the sales generated by the three oilfield service companies acquired by the Company in September and October of 1994 and three oilfield sales and service companies acquired in 1995.
INTEREST AND OTHER REVENUE. Interest and other revenue increased $2.1 million (383%) from $562,000 in 1994 to $2.7 million in 1995 primarily due to the recognition of $1.3 million in anticipated proceeds from contract rejection claims that have been filed in the bankruptcy proceedings of Columbia Gas Transmission Corporation and the recognition of income in 1995 from an incentive production payment associated with certain properties operated by Ward Lake.
PRODUCTION EXPENSE. Production expense increased $4.0 million (50%) from $7.8 million in 1994 to $11.8 million in 1995. This increase was primarily due to the increased production volumes discussed above. The average production cost per equivalent Mcf of natural gas excluding taxes decreased from $.62 per Mcfe in 1994 to $.58 per Mcfe in 1995.
PRODUCTION TAXES. Production taxes increased $703,000 (52%) from $1.4 million in 1994 to $2.1 million in 1995. This increase was primarily due to the increased production volumes discussed above.
COST OF GAS AND GATHERING EXPENSE. Cost of gas and gathering expense increased $4.9 million (17%) from $28.9 million in 1994 to $33.8 million in 1995 primarily due to the Company's 1995 acquisitions. Increased volumes of gas purchased from third parties and resold were offset by a lower average purchase price.
OILFIELD SALES AND SERVICE EXPENSE. Oilfield sales and service expense increased $6.1 million (50%) from $12.2 million in 1994 to $18.3 million in 1995 primarily as a result of the increased cost of goods sold associated with increased sales resulting from the acquisitions described above.
EXPLORATION EXPENSE. Exploration expense increased $2.1 million (76%) from $2.8 million in 1994 to $4.9 million in 1995 primarily due to higher levels of geological and geophysical activity and increases in the size of the technical staff.
GENERAL AND ADMINISTRATIVE EXPENSE. General and administrative expense increased $235,000 (7%) from $3.6 million in 1994 to $3.8 million in 1995 primarily due to increases in employee compensation and benefits.
INTEREST EXPENSE. Interest expense increased $2.6 million (73%) from $3.5 million in 1994 to $6.1 million in 1995. This increase was primarily due to higher average debt balances incurred to finance the 1995 acquisitions (Note 3 - "Acquisitions").
DEPRECIATION, DEPLETION AND AMORTIZATION. Depreciation, depletion and amortization increased by $7.8 million (66%) from $11.9 million in 1994 to $19.7 million in 1995. Depletion expense increased $6.0 million (66%) from $9.1 million in 1994 to $15.1 million in 1995. This increase was primarily due to additional depletion expense associated with the increased production volumes described above. Depletion per Mcfe increased from $.72 per Mcfe in 1994 to $.74 per Mcfe in 1995.
FRANCHISE, PROPERTY AND OTHER TAXES. Franchise, property and other taxes increased by $374,000 (44%) from $854,000 in 1994 to $1.2 million in 1995 primarily due to the acquisitions made in 1995 and the increase in shareholders' equity as a result of the common stock issued in 1995.
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES. Income from continuing operations before income taxes increased $1.9 million (29%) from $6.5 million in 1994 to $8.4 million in 1995. The operating income from the oil and gas operations segment increased $3.3 million (37%) from $9.1 million in 1994 to $12.4 million in 1995. The increase was attributable to the items discussed above. The operating income from the oilfield sales and service segment increased $323,000 (92%) from $350,000 in 1994 to $673,000 in 1995.
INCOME FROM CONTINUING OPERATIONS. Income from continuing operations increased $2.1 million (50%) from $4.2 million in 1994 to $6.3 million in 1995. This increase in income from continuing operations was primarily the result of the items discussed above. Provision for income taxes from continuing operations decreased $180,000 (8%) from $2.3 million in 1994 to $2.2 million in 1995. This decrease was attributable to a decrease in the effective tax rate partially offset by an increase in income from continuing operations before income taxes. The effective tax rate decreased primarily due to the utilization of nonconventional fuel source tax credits. Earnings from continuing operations on a per common share basis increased from $.57 per share in 1994 to $.69 per share in 1995. This increase was primarily the result of the factors discussed above.
LOSS FROM DISCONTINUED OPERATIONS. Loss from discontinued operations was $1,761,000 ($1,139,000 net of tax benefit or $.13 per share) in 1995 compared to $509,000 ($337,000 net of tax benefit or $.05 per share) in 1994. The loss in 1995 includes the write-down of various assets and inventories to estimated realizable value and a provision for estimated costs of asset disposals and future losses.
LIQUIDITY AND CAPITAL RESOURCES
The Company's working capital is closely related to and dependent on the current prices paid for its oil and gas.
The Company's current ratio at December 31, 1996 was 1.64 to 1.00. During 1996, working capital increased $4.7 million from $17.4 million to $22.1 million. The increase was primarily due to an increase in accounts receivable ($5.4 million) and decreases in accounts payable and accrued expenses ($4.4 million), which was partially offset by a decrease in cash ($3.7 million) and an increase in the current portion of long-term liabilities ($2.2 million) reflecting the first principal payment due in 1997 on the senior notes. The Company's operating activities provided cash flow of $46.5 million during 1996.
On May 25, 1995, the Company's bank group amended its revolving bank facility. The facility was increased to $200 million and the maturity date was extended to March 31, 1999. The borrowing base is calculated by the bank group and is based on the cash flows generated by the Company's proved developed reserves, gas gathering systems and other corporate assets. Generally, the Company can expect to have the borrowing base increased by at least 50% of the present value before income taxes (discounted at 10% per annum) of any proved developed reserves added through acquisition or drilling. At December 31, 1996 the borrowing base was $70 million. The Company believes that its reserves at December 31, 1996 could provide a borrowing base in excess of $115 million.
On February 16, 1996, the Company's bank group further amended its revolving bank facility. The maturity date was extended to March 31, 2001 and the LIBOR interest rate option was modified to decrease from LIBOR + 2% to a range of LIBOR + 1-1/4% to LIBOR + 3/4% as outstanding balances decrease in relation to the borrowing base.
Outstanding balances under the agreement incurred interest at the Company's choice of either: (i) the one, two or three-month LIBOR + 1.25% (6.81% for the three-month LIBOR interest rate option at December 31, 1996) or (2) the bank's prime rate (8.25% at December 31, 1996). At December 31, 1996, the Company had $59 million outstanding under this facility.
The amended facility will continue to restrict the sale of assets to no more than 15% of shareholders' equity in any one year and will require the Company to maintain certain levels of net worth, working capital and debt service coverage.
When market conditions are favorable, the Company may enter into interest rate swap arrangements, whereby a portion of the Company's floating rate exposure is exchanged for a fixed interest rate. The Company had no such derivative financial instruments at December 31, 1995 or 1996.
During 1993, the Company placed $35 million of 7% fixed-rate senior notes with five insurance companies in a private placement. These notes, which are interest-only for four years, mature on September 30, 2005. Equal annual principal payments of $3,888,888 will be required on each September 30 commencing in 1997.
The senior note agreement limits the Company's senior debt to 50% of the discounted present value (at 10%) of the Company's oil and gas reserves plus the net book value of its gas gathering systems. Other terms and covenants are substantially the same as those contained in the $200 million revolving credit facility.
In the fourth quarter of 1996, $1.25 million of the Company's 9.25% convertible subordinated debentures (due June 30, 2000) were converted by the holders into 62,034 shares of the Company's common stock at the current conversion price of $20.15 per share.
The Company currently expects to spend approximately $38 million during 1997 on its drilling activities and approximately $12 million for other capital expenditures. The Company's acquisition program is expected to be financed with any available cash flow over $50 million and with its available bank credit line. The Company believes that its existing sources of working capital are sufficient to satisfy all currently anticipated working capital requirements.
The level of the Company's cash flow in the future will depend on a number of factors including the demand and price levels for oil and gas, its ability to acquire additional producing properties and the scope and success of its drilling activities. The Company intends to finance such activities principally through its available cash flow, through additional borrowings and, to the extent necessary, the issuance of additional common or preferred stock.
INFLATION AND CHANGES IN PRICES
During 1994, the price paid for the Company's crude oil increased from $13.50 per barrel to a high of $18.00 per barrel, then decreased to $15.50 per barrel at year end, with an average price of $15.98 per barrel. During 1995, the price paid for the Company's crude oil increased from $15.50 per barrel to a high of $17.50 per barrel, then decreased to $16.50 per barrel at year-end, with an average price for the year of $16.78 per barrel. During 1996, the price paid for the Company's crude oil increased from a low of $16.50 per barrel at year-end 1995 to a high of $22.50 per barrel at year-end 1996, with an average price of $20.24 per barrel. The average price of the Company's natural gas decreased from $2.58 per Mcf in 1994 to $2.21 per Mcf in 1995, then increased to $2.56 per Mcf in 1996.
The price of oil and gas has a significant impact on the Company's results of operations. Oil and gas prices fluctuate based on market conditions and, accordingly, cannot be predicted. As a result of increased competition among drilling contractors and suppliers and continuing low levels of drilling activity in the Company's operating area, costs to drill, complete, and service wells have remained relatively constant in recent years.
Historically, a large portion of the Company's natural gas sales has been under long-term fixed price contracts. As a result of recent acquisitions, certain natural gas sales are currently based on indexed prices. Many of these contracts contain "trigger" clauses which allow the Company to fix the price at which deliveries in future months will be sold based on a regional index or a negotiated positive basis above the relevant NYMEX price for one or more future months. The Company may also, from time to time, enter into hedging transactions with financial institutions to reduce its exposure to variable commodity pricing.
FORWARD-LOOKING INFORMATION
The forward-looking statements regarding future operating and financial performance contained in this report involve risks and uncertainties that include, but are not limited to, the Company's future production and costs of operation, the market demand for, and prices of, oil and natural gas, results of the Company's future drilling and gas marketing activity, the uncertainties of reserve estimates, environmental risks, and other factors detailed in the Company's filings with the Securities and Exchange Commission. Actual results may differ materially from forward-looking statements made in this report.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -------------------------------------------
The Index to Consolidated Financial Statements and Schedules on page sets forth the financial statements included in this Annual Report on Form 10-K and their location herein. Schedules have been omitted as not required or not applicable because the information required to be presented is included in the financial statements and related notes.
The financial statements have been prepared by management in conformity with generally accepted accounting principles. Management is responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary to make informed estimates and judgments based on currently available information on the effects of certain events and transactions.
The Company maintains accounting and other controls which management believes provide reasonable assurance that financial records are reliable, assets are safeguarded, and that transactions are properly recorded. However, limitations exist in any system of internal control based upon the recognition that the cost of the system should not exceed benefits derived.
The Company's independent auditors, Ernst & Young LLP, are engaged to audit the financial statements and to express an opinion thereon. Their audit is conducted in accordance with generally accepted auditing standards to enable them to report whether the financial statements present fairly, in all material respects, the financial position and results of operations in accordance with generally accepted accounting principles.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ------------------------------------------------ ACCOUNTING AND FINANCIAL DISCLOSURE -----------------------------------
Not applicable.
PART III --------
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT --------------------------------------------------
The information with respect to the directors of the Company set forth under the caption "Election of Directors" in the Company's proxy statement to be filed for the Annual Meeting of Shareholders to be held on or about May 22, 1997 is incorporated herein by reference. See pages 16 through 19 of this report for information regarding executive officers.
Item 11.
Item 11. EXECUTIVE COMPENSATION ----------------------
The information with respect to executive compensation set forth under the captions "Executive Compensation" and "Information about the Board of Directors" in the Company's proxy statement to be filed for the Annual Meeting of Shareholders to be held on or about May 22, 1997 is incorporated herein by reference.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND --------------------------------------------------- MANAGEMENT ----------
The information with respect to security ownership of certain beneficial owners and management set forth under the caption "Ownership of Voting Securities" in the Company's proxy statement to be filed for the Annual Meeting of Shareholders to be held on or about May 22, 1997 is incorporated herein by reference.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ----------------------------------------------
The information set forth under the caption "Certain Transactions" in the Company's proxy statement to be filed for the Annual Meeting of Shareholders on or about May 22, 1997 is incorporated by reference.
PART IV -------
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ------------------------------------------------------- FORM 8-K --------
(a) Documents filed as a part of this report:
1. Financial Statements
The financial statements listed in the accompanying Index to Consolidated Financial Statements and Schedules are filed as part of this Annual Report on Form 10-K.
2. Financial Statement Schedules
No financial statement schedules are required to be filed as part of this Annual Report on Form 10-K.
3. Exhibits
No. Description - --- -----------
3.1 Articles of Incorporation of the Company--incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
3.2 Amended Articles of Incorporation to the Company--incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
3.2(a) Amendment to Amended Articles of Incorporation of the Company--incorporated by reference to Exhibit 4 to the Company's Current Report on Form 8-K dated December 30, 1992
3.3 Amended Code of Regulations of the Company--incorporated by reference to Exhibit 3.3 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
4.1 Amended and Restated Debenture Agreement between the Company and Petercam Securities--incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
4.2(a) Credit Agreement among the Company, The Canton Oil & Gas Company, Peake Energy, Inc., Peake Operating Company, Bank One, Texas, National Association and NBD Bank, N.A. dated November 1993--incorporated by reference to Exhibit 4.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993
4.2(b) First Amendment to Credit Agreement among the Company, The Canton Oil & Gas Company, Peake Energy, Inc., Bank One, Texas, National Association and NBD Bank, N.A., effective as of August 1, 1994--incorporated by reference to Exhibit 4.2(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995
4.2(c) Second Amendment to Credit Agreement among the Company, The Canton Oil & Gas Company, Peake Energy, Inc., Ward Lake Drilling, Inc., Bank One, Texas, National Association and NBD Bank, N.A., effective as of March 29, 1995--incorporated by reference to Exhibit 4.2(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995
4.2(d) Third Amendment to Credit Agreement among the Company, The Canton Oil & Gas Company, Ward Lake Drilling, Inc., Bank One, Texas, National Association and NBD Bank, N.A., effective as of May 25, 1995--incorporated by reference to Exhibit 4.2(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995
4.2(e) Fourth Amendment to Credit Agreement among the Company, The Canton Oil & Gas Company, Peake Energy, Inc., Ward Lake Drilling, Inc., Bank One, Texas, National Association and NBD Bank, N.A., effective as of February 15, 1996--incorporated by reference to Exhibit 4.2(e) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995
4.3 Warrant Assumption Agreement between Belden & Blake Corporation and Belden & Blake Energy Company--incorporated by reference to Exhibit 4.4 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992
4.4 Note Purchase Agreement dated as of November 15, 1993 among the Company, The Canton Oil & Gas Company, Peake Operating Company and Peake Energy, Inc. and the purchasers listed on Annex I thereto--incorporated by reference to Exhibit 4.5 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993
4.5 None of the other instruments defining the rights of holders of long-term debt of the Company or its subsidiaries involve long-term debt in an amount which exceeds ten percent of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of such other instruments to the Commission upon request.
10.1 Amended and Restated Employment Agreement between the Company and Henry S. Belden IV--incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996
10.2 Severance Agreement between the Company and Max L. Mardick-- incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996
10.3 Form of Severance Agreement between the Company and the following officers: Ronald E. Huff, Ronald L. Clements and Joseph M. Vitale-- incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996
10.4 Form of Severance Agreement between the Company and the following officers and managerial personnel: Dennis D. Belden, James C. Ewing, Charles P. Faber, Tommy L. Knowles, Donald A. Rutishauser, L. H. Sawatsky, Leo A. Schrider and Dean A. Swift--incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996
10.5 Severance Pay Plan for Key Employees of Belden & Blake Corporation-- incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996
10.6(a) Stock Option Plan of the Company--incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
10.6(b) Stock Option Plan of the Company (as amended)--incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8 (Registration No. 33-62785)
10.7 Restricted Stock Grant Plan of The Canton Oil & Gas Company (formerly known as Belden & Blake Corporation)--incorporated by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
10.8 Belden & Blake Corporation Non-employee Director Stock Option Plan--incorporated by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993
10.9 Plan and Agreement of Consolidation dated as of October 10, 1991, as amended, among Belden & Blake Energy Company, Henry S. Belden IV, Belden & Blake International Limited and the Company--incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
10.10 Amended and Restated Gas Sales and Purchase Contract between Peake Energy, Inc. and Kaiser Aluminum & Chemical Corporation dated as of August 27, 1987--incorporated by reference to Exhibit 10.11 to the Company's Registration Statement on Form S-1 (Registration No. 33-60228)
10.11(a) Stock Purchase Agreement dated January 3, 1995 among Keith Hardin Gornick, R. David Briney, William F. Rolinski, Charles Nelson and the Company-- incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K dated February 10, 1995
10.11(b) Agreement of Amendment dated January 16, 1995 among Keith Hardin Gornick, R. David Briney, William F. Rolinski, Charles Nelson and the Company-- incorporated by reference to Exhibit 2.2 to the Company's Current Report on Form 8-K dated February 10, 1995
10.11(c) Second Agreement of Amendment dated February 10, 1995 among Keith Hardin Gornick, R. David Briney, William F. Rolinski, Charles Nelson and the Company--incorporated by reference to Exhibit 2.3 to the Company's Current Report on Form 8-K dated February 10, 1995
10.12 Asset Purchase Agreement dated July 26, 1995 among Quaker State Corporation, QSE&P, Inc. and the Company--incorporated by reference to Exhibit 2 to the Company's Current Report on Form 8-K dated August 9, 1995
21* Subsidiaries of the Registrant
23* Consent of Ernst & Young LLP
27* Financial Data Schedule
*Filed herewith
(b) Reports on Form 8-K
No reports on Form 8-K were filed by the Company during the last quarter of the year covered by this report.
(c) Exhibits required by Item 601 of Regulation S-K
Exhibits required to be filed by the Company pursuant to Item 601 of Regulation S-K are contained in the Exhibits listed under Item 14(a)3.
(d) Financial Statement Schedules required by Regulation S-X
The items listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.
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 5, 1997 By: /s/ Henry S. Belden IV - -------------------------- ------------------------------- Date Henry S. Belden IV Chairman of the Board 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.
BELDEN & BLAKE CORPORATION INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
ITEM 14(A)(1) AND (2)
PAGE ----
CONSOLIDATED FINANCIAL STATEMENTS - ---------------------------------
Report of Independent Auditors......................................... Consolidated Balance Sheets as of December 31, 1996 and 1995........... Consolidated Statements of Operations for the years ended December 31, 1996, 1995 and 1994.................................... Consolidated Statements of Shareholders' Equity for the years ended December 31, 1996, 1995 and 1994............................ Consolidated Statements of Cash Flows for the years ended December 31, 1996, 1995 and 1994.................................... Notes to Consolidated Financial Statements.............................
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.
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 as of December 31, 1996 and 1995, and the related consolidated statements of operations, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Belden & Blake Corporation at December 31, 1996 and 1995, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles.
ERNST & YOUNG LLP
Cleveland, Ohio February 21, 1997
BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
See accompanying notes.
BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA)
See accompanying notes.
BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
See accompanying notes.
BELDEN & BLAKE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES BUSINESS - -------- The Company operates primarily in the oil and gas industry. The Company's principal business is the acquisition, exploration, development and production of oil and gas reserves, and the gathering and marketing of natural gas. Sales of oil are ultimately made to refineries. Sales of gas are ultimately made to gas utilities and industrial consumers in Ohio, Michigan, West Virginia, Pennsylvania, New York and Kentucky. The Company also provides oilfield services and is a distributor of a broad range of oilfield equipment and supplies. Its customers include other independent oil and gas companies, dealers and operators throughout Ohio, Michigan, West Virginia, Pennsylvania and New York. The price of oil and gas has a significant impact on the Company's working capital and results of operations.
PRINCIPLES OF CONSOLIDATION AND FINANCIAL PRESENTATION - ------------------------------------------------------ The accompanying consolidated financial statements include the financial statements of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
USE OF ESTIMATES IN THE FINANCIAL STATEMENTS - -------------------------------------------- The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts. Significant estimates used in the preparation of the Company's financial statements which could be subject to significant revision in the near term include estimated oil and gas reserves and the estimated net realizable value of the assets of discontinued operations. Although actual results could differ from these estimates, significant adjustments to these estimates historically have not been required.
CASH EQUIVALENTS - ---------------- For purposes of the statements of cash flows, cash equivalents are defined as all highly liquid debt instruments purchased with an initial maturity of three months or less.
CONCENTRATIONS OF CREDIT RISK - ----------------------------- Credit limits, ongoing credit evaluation and account monitoring procedures are utilized to minimize the risk of loss. Collateral is generally not required. Expected losses are provided for currently and actual losses have been within management's expectations.
INVENTORIES - ----------- Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural gas inventories are stated at average cost.
PROPERTY AND EQUIPMENT - ---------------------- The Company utilizes the "successful efforts" method of accounting for its oil and gas properties. Under this method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, dry holes, expired leases and delay rentals, are expensed as incurred. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors.
No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.
Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense.
Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years.
Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is charged to income as incurred, and significant renewals and betterments are capitalized.
NET INCOME PER COMMON SHARE - --------------------------- Net income per common share is computed by subtracting preferred dividends from net income and dividing the difference by the weighted average number of common and common equivalent shares outstanding. Outstanding options, convertible securities and warrants are included in the computation of net income per common share when their effect is dilutive.
REVENUE RECOGNITION - ------------------- Oil and gas production revenue is recognized as production and delivery take place. Oil and gas marketing revenues are recognized when title passes. Oilfield sales and service revenues are recognized when the goods or services have been provided.
INCOME TAXES - ------------ The Company uses the liability method of accounting for income taxes. Deferred income taxes are provided for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred income taxes also are recognized for operating losses that are available to offset future taxable income and tax credits that are available to offset future federal income taxes.
RECLASSIFICATIONS - ----------------- Certain reclassifications have been made in 1995 and 1994 to conform to the presentation in 1996.
(2) ACCOUNTING CHANGES During 1996, the Company adopted Statement of Financial Accounting Standards (SFAS) 123, "Accounting for Stock-Based Compensation." Under SFAS 123, companies may elect to adopt the fair value method of accounting for stock-based compensation or continue to use Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25) to measure expense associated with stock-based compensation. The Company has elected to continue to follow APB 25. See Note 8.
During 1996, the Company adopted SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." This statement requires impairment losses to be recognized for long-lived assets (other than unproved properties) used in continuing operations when indicators of impairment are present and the assets' carrying value is not anticipated to be recovered through future operations or sale. No impairment was required as a result of adopting SFAS 121.
(3) ACQUISITIONS The following acquisitions were accounted for as purchase business combinations. Accordingly, the results of operations of the acquired businesses are included in the Company's consolidated statements of operations from the date of the respective acquisitions.
During 1996, the Company acquired for approximately $4.1 million working interests in 323 oil and gas wells in Ohio and Kentucky. Estimated proved developed reserves associated with the wells totaled 6.0 Bcf of natural gas and 205,000 Bbls of oil net to the Company's interest at July 1, 1996.
Effective in July 1995, the Company purchased from Quaker State Corporation most of its oil and gas properties and related assets in the Appalachian Basin (the "Quaker State Properties") for approximately $50 million. The Quaker State Properties included approximately 1,460 gross (1,100 net) wells with estimated proved reserves of 2.2 MMBbl of oil and 46.8 Bcf of gas at December 31, 1994, approximately 250 miles of gas gathering systems, undeveloped oil and gas leases and fee mineral interests covering approximately 250,000 acres, an extensive geologic and geophysical database and other assets.
In January 1995, the Company purchased Ward Lake Drilling, Inc. ("Ward Lake"), a privately-held exploration and production company headquartered in Gaylord, Michigan, for $15.1 million. Ward Lake operates and holds a production payment interest and working interests averaging 13.6% in approximately 500 Antrim Shale gas wells located in Michigan's lower peninsula. The purchase also included approximately 5,500 undeveloped leasehold acres that Ward Lake owns in Michigan. At December 31, 1994, the wells had estimated proved developed natural gas reserves totaling 98 Bcf (14 Bcf net to the Company's interest). Approximately one half of the purchase price represented payment for the proved reserves, with the balance associated with other oil and gas and corporate assets. Through the end of 1996, the Company purchased additional working interests averaging 24% in the wells operated by Ward Lake for approximately $12 million. The interests acquired had estimated proved developed reserves of 16 Bcf at December 31, 1994. The production from certain interests qualify for nonconventional fuel source tax credits.
In addition, during 1995 the Company, in four separate transactions, acquired for approximately $29.2 million working interests in oil and gas wells in Michigan, Ohio, Pennsylvania and New York and drilling rights on more than 250,000 acres in Ohio. Estimated proved developed reserves associated with the wells totaled 35 Bcfe of natural gas net to the Company's interest at December 31, 1994.
In January 1994, the Company purchased substantially all of TGX Corporation's Appalachian Basin assets for $15.5 million. The assets acquired included 1,034 gross (910 net) gas and oil wells on approximately 121,000 acres located in northeastern Ohio and southwestern New York and 15,000 undeveloped acres and related inventory, real estate and oilfield equipment. At December 31, 1993, the properties acquired had estimated proved reserves of 22.0 Bcf of natural gas and 28,700 Bbls of oil.
The unaudited pro forma results of operations for the year ended December 31, 1995 as if the acquisitions above occurred at the beginning of the period were revenues of $124.9 million, net income
of $8.5 million and net income per common share of $.75. The pro forma effects of the 1996 acquisitions were not material.
(4) DETAILS OF BALANCE SHEETS
The Company has a $200 million unsecured revolving credit facility with a group of banks that matures on March 31, 2001. Outstanding balances under the facility incurred interest at the Company's choice of either: (1) the one, two, or three-month LIBOR plus 1.25% (6.81% for the three-month LIBOR interest rate option at December 31, 1996) or (2) the bank's prime rate (8.25% at December 31, 1996). At December 31, 1996, amounts payable under this facility were at the three-month LIBOR option with rates ranging from 6.78% to 6.84%. Borrowings under the credit agreement are limited to the borrowing base as established semi-annually by the bank group. The borrowing base at December 31, 1996 was $70 million. The Company believes that its oil and gas reserves at December 31, 1996 could provide a borrowing base in excess of $115 million.
When market conditions are favorable, the Company may enter into interest rate swap arrangements, whereby a portion of the Company's floating rate exposure is exchanged for a fixed interest rate. The Company had no such derivative financial instruments at December 31, 1996 or 1995.
The Company has $35 million of 7% fixed-rate senior notes outstanding with five insurance companies. These notes, which are interest-only through 1996, mature on September 30, 2005. Equal principal payments of $3,888,888 will be required on each September 30 commencing in 1997.
The convertible subordinated debentures have a fixed interest rate of 9.25% and mature on June 30, 2000. The debentures are currently convertible by the debenture holders at the rate of one share of the Company's common stock for each $20.15 of principal. During 1996, $1,250,000 of the debentures were converted by the holders into 62,034 shares of common stock.
The debt agreements contain various covenants restricting payment of dividends on common stock to $5 million plus 50% of cumulative net income, restricting sales of assets to 15% of shareholders' equity in any one year and requiring the maintenance of certain levels of net worth, working capital and other financial ratios.
At December 31, 1996, the aggregate long-term debt maturing in the next five years is as follows: $3,918,000 (1997); $3,907,000 (1998); $3,907,000 (1999); $9,457,000 (2000); $62,907,000 (2001); and $15,700,000 (2002 and thereafter).
(6) LEASES The Company leases certain computer equipment, vehicles and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to approximately $1.6 million, $1.4 million and $742,000 for the years ended December 31, 1996, 1995, and 1994, respectively. Future commitments under leasing arrangements were not significant at December 31, 1996.
(7) SHAREHOLDERS' EQUITY In December 1996 and 1995, the Company awarded 36,077 and 26,085 shares of common stock, respectively, to employees as profit sharing and bonuses. These shares were issued in each subsequent year.
In November 1996, $1,250,000 of convertible subordinated debentures were converted by the debenture holders at the rate of one share of the Company's common stock for each $20.15 of principal into 62,034 shares of common stock.
In August 1995, the Company sold 4,025,000 shares of common stock. Net proceeds, after deducting underwriting discounts and expenses, totaled approximately $55.6 million. Approximately
$50 million of the net proceeds were used to purchase the Quaker State Properties, and the remaining proceeds were used to reduce the outstanding balance under the Company's revolving credit agreement.
Outstanding warrants for the purchase of 13,801 shares of the Company's common stock at a price of $21.74 per share were exercisable by the holder in whole or part any time prior to February 15, 1997. These warrants expired unexercised on February 15, 1997.
On December 31, 1992, the Company issued 24,000 shares of Class II Serial Preferred Stock with a stated value of $100 per share. In preference to shares of common stock, each share is entitled to cumulative cash dividends of $7.50 per year, payable quarterly. The Preferred Stock is subject to redemption at $100 per share at any time by the Company and is convertible into common stock, at the holder's election, at any time after five years from the date of issuance at a conversion price of $15.00 per common share. Holders of the Preferred Stock are entitled to one vote per preferred share. In February 1997, the Company notified the preferred stockholder that it intended to redeem 100% of the preferred stock for aggregate consideration of $2.4 million in March, 1997.
At December 31, 1996, the Company had reserved a total of 449,075 shares of common stock for the conversion of the convertible subordinated debentures and the Class II Serial Preferred Stock and the exercise of the outstanding warrants referred to above.
The Company's Articles of Incorporation include certain anti-takeover provisions. The provisions grant the Board of Directors the authority to issue and fix the terms of preferred stock as well as the ability to take certain other actions that could have the effect of discouraging unsolicited takeover attempts. In addition, the Company has entered into contracts with its officers and other employees that provide for severance payments, in certain circumstances, in the event that their employment is terminated following a change in control. The senior notes may, at the noteholder's discretion, be accelerated and become due and payable upon a change in control of the Company.
(8) STOCK OPTION PLANS The Company has an employee stock option plan which is authorized to issue up to 1,070,000 shares of common stock to officers and employees. The exercise price of options may not be less than the fair market value of a share of common stock on the date of grant. Options expire on the tenth anniversary of the grant date unless cessation of employment causes earlier termination. The options become exercisable in 25% increments over a four-year period beginning one year from date of grant. As of December 31, 1996, there were 301,000 shares available for grant under the Plan.
On May 27, 1994, the shareholders approved the Non-Employee Directors Stock Option Plan authorizing the issuance of up to 120,000 shares of common stock. Options for 2,000 shares will be granted each year to each non-employee director. The exercise price of options under the Plan is equal to the fair market value on the date of grant. Options expire on the tenth anniversary of the grant date. The options become exercisable on the anniversary of the grant date at a rate of one third of the shares each year. As of December 31, 1996, there were 80,000 shares available for grant under the Plan.
The Company has elected to follow Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB 25) and related Interpretations in accounting for its employee stock options because, as discussed below, the alternative fair value accounting provided for under SFAS 123, "Accounting for Stock-Based Compensation" requires use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, no compensation expense is recognized because the exercise price of the Company's employee stock options equals the market price of the underlying stock on the date of the grant.
Pro forma information regarding net income and earnings per share is required by Statement 123, and has been determined as if the Company had accounted for its employee stock options under the fair value method of that Statement. The fair value for these stock options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for 1995 and 1996, respectively: risk-free interest rates of 6.4% and 6.5%; volatility factors of the expected market price of the Company's common stock of .36 and .36; dividend yield of zero; and a weighted-average expected life of the option of seven years.
The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its stock options.
For purposes of pro forma disclosures, the estimated fair value of the options is amortized to expense over the options' vesting period. The Company's pro forma information for grants made after January 1, 1995, follows:
1996 1995 ------------- ------------- Pro forma net income (in thousands) $ 14,286 $ 5,016 Pro forma earnings per share $ 1.25 $ .55
The effects of applying Statement 123 for providing pro forma disclosures are not indicative of future amounts until the new rules are applied to all outstanding, nonvested awards.
Stock option activity under the two plans consisted of the following:
The weighted average fair value of options granted during the years 1996 and 1995 were $10.59 and $8.27 per share, respectively. The exercise price for the options outstanding as of December 31, 1996 ranged from $10.00 to $16.38 per share. At December 31, 1996 the weighted average remaining contractual life of the outstanding options is 8.4 years.
(9) TAXES The provision for income taxes on income from continuing operations before income taxes in the Consolidated Statements of Operations includes the following:
The effective tax rate for continuing operations differs from the U.S. federal statutory tax rate, as follows:
The effect of the federal rate change, which was not material, is included in "Other".
Significant components of deferred income tax liabilities and assets are as follows:
At December 31, 1996, the Company had approximately $1,800,000 of net operating loss carryforwards available for federal income tax reporting purposes. Substantially all of the net operating loss carryforwards are limited as to their annual utilization as a result of prior ownership changes. The net operating loss carryforwards, if unused, will expire from 2002 to 2009. The Company has alternative minimum tax credit carryforwards of approximately $3,562,000 which have no expiration date.
Included in "Franchise, property and other taxes" are property taxes associated with production activities of $203,000, $163,000 and $108,000 for the years 1996, 1995 and 1994, respectively.
(10) PROFIT SHARING AND RETIREMENT PLANS The Company has a non-qualified profit sharing arrangement under which the Company contributes discretionary amounts determined by the compensation committee of its Board of Directors. Amounts are allocated to substantially all employees based on relative compensation. The Company contributed $1,256,600, $458,000 and $340,000 for the years 1996, 1995 and 1994, respectively, to the profit sharing plan of which one half was paid in cash and one half was paid in shares of the Company's common stock contributed into each eligible employee's 401(k) plan account. Additional discretionary bonuses are also made.
The Company has a qualified defined contribution plan (a 401(k) plan) covering substantially all of the employees of the Company. Under the plan, an amount equal to 2% of participants' compensation is contributed by the Company to the plan each year. Eligible employees may also make voluntary contributions which the Company matches $.25 for every $1.00 contributed up to 6% of an employee's annual compensation. Retirement plan expense for 1996, 1995 and 1994 was $457,332, $372,213 and $286,446, respectively.
The Company has non-qualified deferred compensation plans which permit certain key employees and directors to elect to defer a portion of their compensation.
(11) COMMITMENTS AND CONTINGENCIES The Company is involved in various legal actions arising in the normal course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the financial position of the Company.
(12) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(13) 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 preferred stock is redeemable at $100 per share plus unpaid dividends. The following table reflects the financial instruments for which the fair value differs from the carrying amount of such financial instrument in the Company's December 31, 1996 and 1995 balance sheets:
The fair value of the amounts receivable is based on the discounted expected future cash flows. The fair value of the senior notes is based on rates available at year-end for similar instruments. The fair value of the convertible subordinated debentures at December 31, 1996 is based on the conversion rate of $20.15 and valuing the common shares at the December 31, 1996 closing stock price of $25.50. The fair value of the convertible subordinated debentures at December 31, 1995 is based on rates available for similar instruments.
(14) 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 No. 69.
PROVED OIL AND GAS RESERVES (UNAUDITED) The Company's proved developed and proved undeveloped reserves are all located within the United States. The Company cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed, and actual prices realized and actual costs incurred may vary significantly from those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made.
The estimates of proved developed reserves have been reviewed by independent petroleum engineers. The estimates of proved undeveloped reserves were prepared by the Company's petroleum engineers.
The following table sets forth changes in estimated proved and proved developed reserves for the three years ended December 31, 1996:
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:
The principal sources of changes in the standardized measure of future net cash flows are as follows:
(15) INDUSTRY SEGMENT FINANCIAL INFORMATION The table below presents certain financial information regarding the Company's industry segments of its continuing operations. Intersegment sales are billed on an intercompany basis at prices for comparable third party goods and services.
No customer exceeded 10% of consolidated revenue during the year ended December 31, 1996. One customer exceeded 10% of consolidated revenue during each of the years ended December 31, 1995 and 1994 which amounted to $11.1 million and $9.6 million, respectively.
(16) QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The results of operations for the four quarters of 1996 and 1995 are shown below.
Income tax expense in the fourth quarter of 1995 was reduced by approximately $600,000 to record the reduction of the effective tax rate for the first nine months of 1995 as a result of the recognition of nonconventional fuel source tax credits.
(17) DISCONTINUED OPERATIONS In September 1995, the Company announced plans to sell Engine Power Systems, Inc. ("EPS"), its wholly-owned subsidiary engaged in engine, parts and service sales. The Company was unable to identify an acceptable buyer for EPS. Since September 1995, a substantial portion of the workforce was eliminated and substantial assets were sold. The Company recognized an additional charge in 1996 to reduce the remaining assets to net realizable value. Net revenues generated by EPS were approximately $3.9 million in 1996, $4.2 million in 1995 and $3.7 million in 1994. The results of operations of EPS are presented as discontinued operations in the accompanying financial statements for all periods presented.
(18) SALE OF TAX CREDIT PROPERTIES In February and March 1996, the Company sold certain interests that qualify for the nonconventional fuel source tax credit. The interests were sold in two separate transactions for approximately $750,000 and $100,000, respectively, in cash and a volumetric production payment under which 100% of the cash flow from the properties will go to the Company until approximately 11.7 Bcf and 3.4 Bcf, respectively, of gas has been produced and sold. In addition to receiving 100% of the cash flow from the properties, the Company will receive quarterly incentive payments based on production from the interests. The Company has the option to repurchase the interests at a future date.
(19) HEDGING ACTIVITIES As a result of certain 1995 acquisitions, the Company has several contracts to sell gas at indexed prices. In early 1996, the Company's Board of Directors approved a formal policy covering hedging with financial instruments. Significant provisions of this policy are that targets are pre-defined and transactions are pre-authorized by senior management; all transactions must meet the accounting definition of a hedge; basis risk must be hedged; leveraged transactions are prohibited and quarterly reports must be made to the Board of Directors on all open positions.
The Company may, from time to time, partially hedge indexed contract price exposure by selling futures contracts on the NYMEX. During 1996, the Company incurred a net $258,000 pretax loss on its hedging activities due to rapidly rising gas prices during the year. At December 31, 1996, the Company did not have any open futures contracts.
When market conditions are favorable, the Company may enter into interest rate swap arrangements, whereby a portion of the Company's floating rate exposure is exchanged for a fixed interest rate. The Company had no such derivative financial instruments at December 31, 1996 or 1995.
EXHIBIT INDEX -------------
Location in Sequentially No. Description Numbered Copy --- ----------- ------------
3.1 Articles of Incorporation of the Company--incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
3.2 Amended Articles of Incorporation to the Company-- incorporated by reference to Exhibit 3.2 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
3.2(a) Amendment to Amended Articles of Incorporation of the Company--incorporated by reference to Exhibit 4 to the Company's Current Report on Form 8-K dated December 30, 1992
3.3 Amended Code of Regulations of the Company-- incorporated by reference to Exhibit 3.3 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
4.1 Amended and Restated Debenture Agreement between the Company and Petercam Securities--incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
4.2(a) Credit Agreement among the Company, The Canton Oil & Gas Company, Peake Energy, Inc., Peake Operating Company, Bank One, Texas, National Association and NBD Bank, N.A. dated November 1993--incorporated by reference to Exhibit 4.2 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993
4.2(b) First Amendment to Credit Agreement among the Company, The Canton Oil & Gas Company, Peake Energy, Inc., Bank One, Texas, National Association and NBD Bank, N.A., effective as of August 1, 1994--incorporated by reference to Exhibit 4.2(b) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995
4.2(c) Second Amendment to Credit Agreement among the Company, The Canton Oil & Gas Company, Peake Energy, Inc., Ward Lake
Drilling, Inc., Bank One, Texas, National Association and NBD Bank, N.A., effective as of March 29, 1995--incorporated by reference to Exhibit 4.2(c) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995
4.2(d) Third Amendment to Credit Agreement among the Company, The Canton Oil & Gas Company, Ward Lake Drilling, Inc., Bank One, Texas, National Association and NBD Bank, N.A., effective as of May 25, 1995-- incorporated by reference to Exhibit 4.2(d) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995
4.2(e) Fourth Amendment to Credit Agreement among the Company, The Canton Oil & Gas Company, Peake Energy, Inc., Ward Lake Drilling, Inc., Bank One, Texas, National Association and NBD Bank, N.A., effective as of February 15, 1996--incorporated by reference to Exhibit 4.2(e) to the Company's Annual Report on Form 10-K for the year ended December 31, 1995
4.3 Warrant Assumption Agreement between Belden & Blake Corporation and Belden & Blake Energy Company-- incorporated by reference to Exhibit 4.4 to the Company's Annual Report on Form 10-K for the year ended December 31, 1992
4.4 Note Purchase Agreement dated as of November 15, 1993 among the Company, The Canton Oil & Gas Company, Peake Operating Company and Peake Energy, Inc. and the purchasers listed on Annex I thereto--incorporated by reference to Exhibit 4.5 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993
4.5 None of the other instruments defining the rights of holders of long-term debt of the Company or its subsidiaries involve long-term debt in an amount which exceeds ten percent of the total assets of the Company and its subsidiaries on a consolidated basis. The Company agrees to furnish a copy of such other instruments to the Commission upon request.
10.1 Amended and Restated Employment Agreement between the Company and Henry S. Belden IV--incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996
10.2 Severance Agreement between the Company and Max L. Mardick--incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996
10.3 Form of Severance Agreement between the Company and the following officers: Ronald E. Huff, Ronald L. Clements and Joseph M. Vitale--incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 1996
10.4 Form of Severance Agreement between the Company and the following officers and managerial personnel: Dennis D. Belden, James C. Ewing, Charles P. Faber, Tommy L. Knowles, Donald A. Rutishauser, L. H. Sawatsky, Leo A. Schrider and Dean A. Swift--incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
10.5 Severance Pay Plan for Key Employees of Belden & Blake Corporation--incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30,
10.6(a) Stock Option Plan of the Company--incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
10.6(b) Stock Option Plan of the Company (as amended)-- incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8 (Registration No. 33-62785)
10.7 Restricted Stock Grant Plan of The Canton Oil & Gas Company (formerly known as Belden & Blake Corporation)--incorporated by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
10.8 Belden & Blake Corporation Non-employee Director Stock Option Plan--incorporated by reference to Exhibit 10.6 to the Company's Annual Report on Form 10-K for the year ended December 31, 1993
10.9 Plan and Agreement of Consolidation dated as of October 10, 1991, as amended, among Belden & Blake Energy Company, Henry S. Belden IV, Belden & Blake International Limited and
the Company--incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-4 (Registration No. 33-43209)
10.10 Amended and Restated Gas Sales and Purchase Contract between Peake Energy, Inc. and Kaiser Aluminum & Chemical Corporation dated as of August 27, 1987-- incorporated by reference to Exhibit 10.11 to the Company's Registration Statement on Form S-1 (Registration No. 33-60228)
10.11(a) Stock Purchase Agreement dated January 3, 1995 among Keith Hardin Gornick, R. David Briney, William F. Rolinski, Charles Nelson and the Company--incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K dated February 10, 1995
10.11(b) Agreement of Amendment dated January 16, 1995 among Keith Hardin Gornick, R. David Briney, William F. Rolinski, Charles Nelson and the Company--incorporated by reference to Exhibit 2.2 to the Company's Current Report on Form 8-K dated February 10, 1995
10.11(c) Second Agreement of Amendment dated February 10, 1995 among Keith Hardin Gornick, R. David Briney, William F. Rolinski, Charles Nelson and the Company--incorporated by reference to Exhibit 2.3 to the Company's Current Report on Form 8-K dated February 10, 1995
10.12 Asset Purchase Agreement dated July 26, 1995 among Quaker State Corporation, QSE&P, Inc. and the Company-- incorporated by reference to Exhibit 2 to the Company's Current Report on Form 8-K dated August 9, 1995
21* Subsidiaries of the Registrant
23* Consent of Ernst & Young LLP
27* Financial Data Schedule
*Filed herewith