SEC Filing | Range Resources

1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark one) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED) For the fiscal year ended December 31, 1997 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) For the transaction period from to

Commission File Number 0-9592 LOMAK PETROLEUM, INC. (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 34-1312571 ------------------------------------ ------------------------------------ (STATE OF INCORPORATION) (I.R.S. EMPLOYER IDENTIFICATION NO.) 500 Throckmorton Street, Ft. Worth, Texas 76102 -------------------------------------------- ------------------------------------ (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)

Registrant's telephone number, including area code: (817) 870-2601 Securities registered pursuant to Section 12(b) of the Act: None Common Stock, $.01 par value ------------------------------- (Title of class) Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES [X] NO [ ]. Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]. The aggregate market value of voting stock of the Registrant held by non-affiliates (excluding voting shares held by officers and directors) was $346,825,893 on March 9, 1998. Indicate the number of shares outstanding of each of the Registrant's classes of stock on March 9, 1998: Common Stock $.01 par value: 21,167,455; Preferred Stock $1 par value: 1,149,800. DOCUMENTS INCORPORATED BY REFERENCE: Part III of this report incorporates by reference the Proxy Statement relating to the Registrant's 1998 Annual Meeting of Stockholders. 2 LOMAK PETROLEUM, INC. ANNUAL REPORT ON FORM 10-K YEAR ENDED DECEMBER 31, 1997 PART I ITEM 1. BUSINESS GENERAL Lomak Petroleum, Inc. ("Lomak" or the "Company") is an independent energy company engaged in oil and gas development, exploration and acquisition primarily in four core areas: the Permian, Midcontinent, Gulf Coast, and Appalachia regions. Over the past seven years, the Company has significantly increased its reserves and production through acquisitions and the development and exploration of its properties. At December 31, 1997, the Company had proved reserves of 753 Bcfe with a Present Value of $632 million. On an Mcfe basis, the reserves were 76% natural gas, with a reserve life index in excess of 15 years. Properties operated by the Company account for 98% of its total reserves. The Company's leasehold position contains 1.2 million gross acres. The Company also owns over 3,000 miles of gas gathering systems and a gas processing plant in proximity to its principal gas properties. DESCRIPTION OF THE BUSINESS Strategy The Company's objective is to maximize shareholder value through aggressive growth in its reserves, production, cash flow and earnings through a balanced program of development and exploratory drilling and strategic acquisitions. Management believes that the acquisitions completed since 1990 have substantially enhanced the Company's ability to increase its production and reserves through the ongoing development of the acquired properties. The Company now has over 1,600 proven recompletion and development drilling projects. With its large development inventory and expanding exploration effort, the Company believes that it can achieve significant growth in reserves, production, cash flow and earnings over the next several years, without the benefit of future acquisitions. The Company currently anticipates spending approximately $300 million during the next three years on the development and exploration activities. Consequently, while acquisitions are expected to continue to play an important role in its future growth, the Company will focus on exploiting the potential of its larger property base. The Company's leasehold now totals approximately 1.2 million gross acres (1.0 million net acres), providing significant long-term development and exploration potential. In order to most effectively implement its operating strategy, the Company has concentrated its activities in selected geographic areas. In each core area, the Company has established separate business units, each with operating, engineering, geological, land, acquisition and other personnel experienced in their respective area. The Company believes that this geographic focus provides it with a competitive advantage in sourcing and evaluating new business opportunities within these areas, as well as providing economies of scale in operating and developing its properties. Development. The Company's development activities include recompletions of existing wells, infill drilling and installation of secondary recovery projects. Development projects are generated within core operating areas where the Company has significant operational and technical experience. At December 31, 1997, over 1,600 proven development projects were in inventory. Over 360 of these projects are anticipated to be initiated in 1998 at a total cost of $77 million. Based on the projects currently in inventory, development expenditures are currently projected to total $250 million for the next three years. Exploration. Beginning in 1996, the Company began to conduct exploration activities on or near existing properties within its core operating areas. The Company currently has an inventory of 13 multi-prospect, higher risk, higher reward exploration projects. Each of the exploration projects includes multiple drilling prospects. The Company's exploration program targets deeper horizons within existing Company-operated fields, as well as establishing new fields in exploration trend areas in which Lomak's technical staff has experience. Lomak's 1 3 strategy is based upon limiting its risk by allocating no more than 10% of its cash flow to exploration activities and by participating in a variety of projects with differing characteristics. The Company projects exploratory expenditures to range between $8 million and $10 million in 1998. Acquisitions. Since 1990, 67 acquisitions have been completed for a total consideration of $751 million. These acquisitions have been made at an average cost of $0.68 per Mcfe. The Company's acquisition strategy has historically been based on: (i) Locale: focusing in core areas where the Company has operating and technical expertise; (ii) Efficiency: targeting acquisitions in which operating and cost efficiencies can be obtained; (iii) Reserve Potential: pursuing properties with the potential for reserve increases through recompletions and drilling; (iv) Incremental Purchases: seeking acquisitions where opportunities for purchasing additional interests in the same or adjoining properties exist; and (v) Complexity: pursuing more complex but less competitive corporate acquisitions. DEVELOPMENT AND EXPLORATION ACTIVITIES Development and exploration activities accelerated in 1997 as Lomak spent $58.8 million versus $14.6 million in 1996. Of this total, the Company expended $49.5 million in the Southwest region, and $9.3 million in Appalachia. These expenditures funded 75 recompletions of existing wells, 193 new development wells and 20 exploratory wells, as well as leasehold and seismic acquisition. As a result of these activities, 65 Bcfe of proved reserves were added representing 133% of 1997 production. Additionally, a number of unproved drilling locations and exploration prospects were generated which are expected to be drilled in 1998 and 1999. Development The Company's development activities include recompletions of existing wells, infill drilling and to a lesser extent, installation of secondary recovery projects. Development projects are located within core operating areas where the Company has established operational and technical expertise. Currently, as described below, the Company has 1,620 proven development projects in inventory. Those projects are geographically diverse, target a mix of oil and gas and are generally less than 8,000 feet in depth. Approximately 90% of the development projects are concentrated in ten fields, allowing multi-year drilling programs. The following table sets forth information pertaining to the Company's proven development inventory at December 31, 1997.
NUMBER OF PROJECTS --------------------------------- DRILLING RECOMPLETIONS LOCATIONS TOTAL ------------- --------- ----- Southwest Permian....................................... 312 479 791 Midcontinent.................................. 80 44 124 Gulf Coast.................................... 82 21 103 --- ----- ----- Subtotal................................... 474 544 1,018 Appalachia...................................... 20 582 602 --- ----- ----- Total................................. 494 1,126 1,620 === ===== =====
In addition to its inventory of proven development projects, the Company has identified over 500 projects within its existing leasehold, which at December 31, 1997 were not classified as proven. A portion of these projects are included in each year's development program. These projects include field extension drilling and recompletions to formations not extensively under production. Lomak completed 268 development projects in 1997, comprising 193 wells drilled and 75 recompletions of existing wells. This level of activity was 271% higher than in 1996. The 1997 development expenditures of $56.4 million exceeded those in 1996 by 350%, reflecting increased activity and a higher average working interest. In the Permian business unit, the Company recompleted 34 wells and drilled an additional 115 wells. Additional development activity in the Southwest region was comprised of the drilling of 10 wells and the recompletion of 41 others in the Midcontinent, while 18 wells were drilled in the Gulf Coast. In Appalachia, the Company spent $6.8 million to drill 50 wells. 2 4 The Company currently anticipates that it will initiate 378 development projects in 1998 at an estimated cost of $77 million. The Permian business unit has budgeted $48 million to drill 172 wells and recomplete 27 others. The Midcontinent unit plans to drill 15 wells and recomplete 43 others for a total cost of $10 million, while the Company expects to drill 12 development wells in the Gulf Coast for $6 million. The Appalachian business unit anticipates spending $13 million to drill 109 development wells. At the current rate, the Company has over five years of projects in inventory. Based on its existing property base, Lomak anticipates spending approximately $250 million over the next three years on development activities. Exploration Activities The Company's exploration activities include the acquisition and processing of seismic data, the leasing of acreage and the drilling of wells on that acreage. The Company currently has an inventory of 13 multi-prospect, higher risk, higher reward exploration projects. Each of these 13 exploration projects includes multiple drilling prospects. If successful, these projects would require several hundred additional wells to be fully exploited. The exploration projects are targeting formations ranging from 7,000 feet to 14,500 feet in depth and in most cases will employ the use of 3-D seismic, horizontal drilling or enhanced completion techniques. The projects currently comprise 370,000 acres under lease, while the Company anticipates acquiring an additional 27,000 acres in 1998 with regard to its existing projects. In 1997, the Company spent $3.1 million to acquire leasehold acreage, shoot and process seismic data and drill 20 wells. Of the 20 wells drilled, 12 were productive and 8 were plugged and abandoned. Acreage acquired was located primarily in the Permian and Gulf Coast areas. In 1998, Lomak anticipates spending approximately $8 to $10 million on exploratory acreage, seismic and drilling. Acquisition Activities The following table sets forth information pertaining to acquisitions completed during the period January 1, 1991 through December 31, 1997.
NUMBER OF PURCHASE PRICE(1) MMCFE COST PER PERIOD TRANSACTIONS (IN THOUSANDS) ACQUIRED MCFE(2) ------ ------------ ----------------- -------- -------- 1991.................................. 9 $ 11,189 14,602 $0.75 1992.................................. 7 6,884 12,513 0.41 1993.................................. 12 40,527 64,552 0.59 1994.................................. 17 63,354 92,851 0.67 1995.................................. 9 71,074 103,849 0.61 1996.................................. 8 56,812 107,480 0.53 1997.................................. 5 501,657 450,693 0.76 -- -------- ------- ----- Total....................... 67 $751,497 846,540 $0.68 == ======== ======= =====
- --------------- (1) Includes purchase price for proved reserves as well as other acquired assets, including gas gathering and processing systems, undeveloped leasehold and field service assets. The 1997 acquisition costs have been reduced by $36.3 million for the sale of a net profits interest on properties acquired during the year. (2) Includes purchase price for proved reserves only. For the Cometra Acquisition, the purchase price for proved reserves includes the amount attributable to the above-market gas contract. If the cost per Mcfe was adjusted for the above-market gas contract, the 1997 cost per Mcfe would be reduced from $0.76 to $0.68 and the total cost per Mcfe would be reduced from $0.68 to $0.64. Recent Significant Acquisitions In 1997, Lomak completed acquisitions totaling $519 million in consideration. The significant acquisitions are described below. 3 5 Cometra Acquisition. In the first quarter of 1997, the Company acquired oil and gas properties located in west Texas, south Texas and the Gulf of Mexico (the "Cometra Properties") from American Cometra, Inc. for a purchase price of $385 million (the "Cometra Acquisition"). The Cometra Acquisition increased the Company's proforma proved reserves at December 31, 1996 by 68% and increased its Present Value by 98%. The Cometra Properties, located primarily in the Company's core operating areas, included 515 producing wells, 401 proven development projects and substantial additional development and exploration potential on approximately 150,000 gross acres (90,000 net acres). In addition, the Cometra Properties included 265 miles of gas pipelines, a 25,000 Mcf/d gas processing plant and an above-market gas contract. Meadville Acquisition. In September 1997, the Company completed the acquisition of certain natural gas properties located in the Company's Meadville area gas field in Appalachia (the "Meadville Properties") for a purchase price of $92.5 million. The Meadville Properties included 912 producing wells, 800 miles of gas gathering lines and leasehold acreage covering approximately 153,000 gross acres (146,000 net acres). On a Present Value basis, the acquired reserves were 80% developed and 95% operated. At the date of acquisition, the Meadville Properties were producing nearly 14,500 Mcf of gas equivalents per day. The Meadville Properties have access to a number of major interstate pipelines and industrial end-users. The Meadville Properties contained over 300 drilling locations, as well as exploration potential in deeper zones. The Company believes that the Meadville Properties, combined with its adjacent properties, constitute one of the largest producing areas in Appalachia operated by a single company, a region not generally known for this type of large reserve concentration. Fuhrman-Mascho Acquisition. In December 1997, the Company completed the acquisition of certain oil properties located in the Fuhrman-Mascho field in west Texas (the "Fuhrman-Mascho Properties") for a purchase price of $40 million. Additionally, the Company recorded approximately $12 million of deferred income taxes in connection with the acquisition. The Fuhrman-Mascho Properties included 160 producing wells and leasehold acreage covering approximately 13,600 gross acres (12,100 net acres). On a Present Value basis, the acquired reserves were 40% developed and greater than 95% operated. Production Production revenue is generated through the sale of oil, natural gas liquids and gas from properties held directly and through partnerships and joint ventures. Additional revenue is received from royalties. While production is sold to a limited number of purchasers, only one accounts for more than 10% of oil and gas revenues. Management believes that the loss of any one customer would not have a material adverse effect on the business. Proximity to local markets, availability of competitive fuels and overall supply and demand are factors affecting the ability to market production. While the Company anticipates an upward trend in energy prices, factors outside its control such as political developments in the Middle East, overall energy supply, weather conditions and economic growth rates have had, and will continue to have, an effect on energy prices. The following table sets forth historical revenue and expense information for the periods indicated (in thousands, except average sales price and operating cost data). 4 6
YEAR ENDED DECEMBER 31, ---------------------------------------------------- 1993 1994 1995 1996 1997 ------- ------- ------- ------- -------- Production Oil and NGL (Bbl)..................... 318 640 913 1,068 1,794 Gas (Mcf)............................. 2,590 6,996 12,471 21,231 38,409 Total (Mcfe) (a)...................... 4,498 10,836 17,949 27,641 49,170 Revenues Oil and NGL........................... $ 5,118 $ 9,743 $15,133 $20,425 $ 28,800 Gas................................... 6,014 14,718 22,284 47,629 101,217 ------- ------- ------- ------- -------- Total................................. $11,132 $24,461 $37,417 $68,054 $130,017 ======= ======= ======= ======= ======== Average Sales Price Oil (Bbl)............................. $ 16.07 $ 15.23 $ 16.57 $ 19.56 $ 18.22 NGL (Bbl)............................. -- -- -- $ 10.22 $ 9.06 Gas (Mcf)............................. $ 2.32 $ 2.10 $ 1.79 $ 2.24 $ 2.64 Mcfe (a).............................. $ 2.47 $ 2.26 $ 2.08 $ 2.46 $ 2.64 Average Operating Cost Per Mcfe (a).......................... $ 0.71 $ 0.75 $ 0.63 $ 0.75 $ 0.64
- --------------- (a) Oil is converted to Mcfe at a rate of 6 Mcf per barrel. On a Mcfe basis, approximately 78% of 1997 production was natural gas. Gas production was sold to utilities, brokers or directly to industrial users. Gas sales are made pursuant to various arrangements ranging from month-to-month contracts, one year contracts at fixed or variable prices and contracts at fixed prices for the life of the well. All contracts other than the fixed price contracts contain provisions for price adjustment, termination and other terms customary in the industry. A number of the Appalachian gas contracts hold favorable sales prices when compared to spot market prices. Oil is sold on a basis such that the purchaser can be changed on 30 days notice. The price received is generally equal to a posted price set by the major purchasers in the area. Oil purchasers are selected on the basis of price and service. In 1997, revenues from gas sales totaled $101.2 million or 78% of total oil and gas revenues while revenues from oil and natural gas liquids production amounted to $28.8 million, representing 22% of total oil and gas revenues. Oil and gas revenues for 1997 increased 91% over 1996. Gas Transportation, Processing and Marketing The gas transportation, processing and marketing revenues are comprised of fees for the transportation of production through gathering lines and fees from gas processing as well as, income from marketing of oil and gas. Transportation, processing and marketing revenues increased 110% to $11.7 million versus $5.6 million in 1996 principally due to production growth. Transportation, processing and marketing expenses increased 134% to $3.9 million versus $1.7 million in 1996. The increase in expenses was due to production growth and higher administrative costs associated with increased marketing activities. The Company's natural gas transportation and processing assets are primarily comprised of (i) approximately 2,700 miles of gas transportation and gathering pipelines in Appalachia and (ii) nearly 300 miles of gathering lines in the Sterling area of the Permian Basin. The Appalachian gas gathering systems serve to transport a majority of the Company's Appalachian gas production as well as third party gas to major trunklines and directly to industrial end-users. This affords the Company considerable control and flexibility in marketing its Appalachian production. Third parties who transport their gas through the systems are charged a gathering fee based on throughput. The Company's Sterling gas processing plant is a refrigerated turbo-expander cryogenic gas plant that was placed in service in early 1995. The plant, designed for approximately 25,000 Mcf/d, is currently operating at 72% of capacity. The Company estimates that the plant's capacity can be increased to 35,000 Mcf/d for approximately $4.0 million in additional capital expenditures. 5 7 In order to maximize the price and better control credit risk, the Company began to market its own gas production in 1993. The Company is currently marketing 161 Mmcf/d for its own account as well as for third party producers. The Company's gas production is sold primarily to utilities and directly to industrial users. The Company has managed the impact of potential price declines by developing a balanced portfolio of fixed price and market sensitive contracts and commodity hedging. Approximately 38% of average gas production at December 31, 1997 was sold subject to fixed price sales contracts. These fixed price contracts are at prices ranging from $2.10 to $4.34 per Mcf. The fixed price contracts with terms of less than one year, between one and five years and greater than five years constitute approximately 51%, 42% and 7%, respectively, of the volume sold under fixed price contracts. From time to time, the Company enters into oil and natural gas price hedges to reduce its exposure to commodity price fluctuations. At December 31, 1997 approximately 12% of the Company's existing market sensitive production was fixed under hedging agreements which expire in 1998. Subsequent to December 31, 1997, the Company entered into additional hedging agreements which increased the percentage of the Company's existing market sensitive production covered by hedging arrangements to 28%. In the future, the Company may hedge a larger percentage of its production, however, it currently anticipates that such percentage would not exceed 70%. Although these hedging activities provide the Company some protection against falling prices, these activities also reduce the potential benefits to the Company of price increases above the levels of the hedges. As part of the Cometra Acquisition, the Company acquired an above market gas contract with a major Texas gas utility company, which expires June 30, 2000. The contract represents 16% of the Company's 1997 gas production on an Mcf basis. The price paid pursuant to the contract converts to a price of $3.73 per Mcf ($3.33 per Mmbtu) at December 31, 1997. The gas contract provides for a price escalation of $0.05 per Mcf on July 1 of each year. No other purchaser of the Company's oil or gas during 1997 exceeded 10% of the Company's total revenues. In July 1997 the gas utility filed an action in state district court regarding the gas contract. See "Item 3 Legal Proceedings". Interest and Other The Company earns interest on its cash and investment accounts, as well as on various notes receivable. Other income in 1997 was comprised principally of gains on sales of marketable equity securities and gains on sales of non-strategic properties. The Company expects to continue to sell properties that are marginal or are not strategic. Interest and other income in 1997 amounted to $7.6 million, representing 5% of total revenues. COMPETITION The Company encounters substantial competition in acquiring oil and gas leases and properties, marketing oil and gas, securing personnel and conducting its drilling and field operations. Many competitors have financial and other resources which substantially exceed those of the Company. The competitors in development, exploration, acquisitions and production include the major oil companies in addition to numerous independents, individual proprietors and others. Therefore, competitors may be able to pay more for desirable leases and to evaluate, bid for and purchase a greater number of properties or prospects than the financial or personnel resources of the Company permit. The ability of the Company to replace and expand its reserve base in the future will be dependent upon its ability to select and acquire suitable producing properties and prospects for future drilling. The Company's acquisitions have been partially financed through issuances of equity and debt securities and internally generated cash flow. There is competition for capital to finance oil and gas acquisitions and drilling. The ability of the Company to obtain such financing is uncertain and can be affected by numerous factors beyond its control. The inability of the Company to raise capital in the future could have an adverse effect on certain areas of its business. GOVERNMENTAL REGULATION The Company's operations are affected from time to time in varying degrees by political developments and federal, state and local laws and regulations. In particular, oil and natural gas production and related operations 6 8 are or have been subject to price controls, taxes and other laws and regulations relating to the oil and gas industry. Failure to comply with such laws and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the Company's cost of doing business and affects its profitability. Although the Company believes it is in substantial compliance with all applicable laws and regulations, because such laws and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such laws and regulations. ENVIRONMENTAL MATTERS The Company's oil and natural gas exploration, development, production and pipeline gathering operations are subject to stringent federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments such as the Environmental Protection Agency ("EPA") issue regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and pipeline gathering activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, frontier and other protected areas, require some form of remedial action to prevent pollution from former operations such as plugging abandoned wells, and impose substantial liabilities for pollution resulting from the Company's operations. In addition, these laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects its profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, disposal or clean-up requirements could adversely affect the Company's operations and financial position, as well as the oil and gas industry in general. While management believes that the Company is in substantial compliance with current applicable environmental laws and regulations and the Company has not experienced any material adverse effect from compliance with these environmental requirements, there is no assurance that this will continue in the future. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damages allegedly caused by the release of hazardous substances or other pollutants into the environment. Furthermore, although petroleum, including crude oil and natural gas, is exempt from CERCLA, at least two courts have ruled that certain wastes associated with the production of crude oil may be classified as "hazardous substances" under CERCLA and thus such wastes may become subject to liability and regulation under CERCLA. State initiatives to further regulate the disposal of oil and natural gas wastes are also pending in certain states, and these various initiatives could have a similar impact on the Company. Stricter standards in environmental legislation may be imposed in the oil and gas industry in the future. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and natural gas exploration and production wastes as "hazardous wastes" and make the reclassified wastes subject to more stringent handling, disposal and clean-up restrictions. If such legislation were to be enacted, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Compliance with environmental requirements generally could have a material adverse effect upon the capital expenditures, earnings or competitive position of the Company. Although the Company has not experienced any material adverse effect from compliance with environmental requirements, no assurance may be given that this will continue in the future. 7 9 The Federal Water Pollution Control Act ("FWPCA") imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. State water discharge regulations and the federal (NPDES) permits prohibit or are expected to prohibit within the next year the discharge of produced water and sand, and some other substances related to the oil and gas industry, to coastal waters. Although the costs to comply with zero discharge mandated under federal or state law may be significant, the entire industry will experience similar costs and the Company believes that these costs will not have a material adverse impact on the Company's financial condition and results of operations. Some oil and gas exploration and production facilities are required to obtain permits for their storm water discharges. Costs may be incurred in connection with treatment of wastewater or developing storm water pollution prevention plans. The Resources Conservation and Recovery Act ("RCRA"), as amended, generally does not regulate most wastes generated by the exploration and production of oil and natural gas. RCRA specifically excludes from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy." However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing solid hazardous waste may be significant, the Company does not expect to experience more burdensome costs than similarly situated companies involved in oil and gas exploration and production. In addition, the U.S. Oil Pollution Act ("OPA") requires owners and operators of facilities that could be the source of an oil spill into "waters of the United States" (a term defined to include rivers, creeks, wetlands and coastal waters) to adopt and implement plans and procedures to prevent any spill of oil into any waters of the United States. OPA also requires affected facility owners and operators to demonstrate that they have at least $35 million in financial resources to pay for the costs of cleaning up an oil spill and compensating any parties damaged by an oil spill. Substantial civil and criminal fines and penalties can be imposed for violations of OPA and other environmental statutes. EMPLOYEES As of December 31, 1997, the Company had 367 full time employees, of whom 211 were field personnel. None are covered by a collective bargaining agreement and management believes that its relationship with its employees is good. 8 10 ITEM 2. PROPERTIES On December 31, 1997, the Company held working interests in 8,394 gross (6,512 net) productive oil and gas wells and royalty interests in 349 additional wells. The properties contained, net to the Company's interest, estimated proved reserves of 574 Bcf of gas and 30 million barrels of oil and natural gas liquids or a total of 753 Bcfe. PROVED RESERVES The following table sets forth estimated proved reserves for each year in the five year period ended December 31, 1997.
1993 1994 1995 1996 1997 ------- ------- ------- ------- ------- Natural gas (Mmcf) Developed...................... 38,373 97,251 174,958 207,601 369,786 Undeveloped.................... 36,190 52,119 57,929 87,993 204,632 ------- ------- ------- ------- ------- Total....................... 74,563 149,370 232,887 295,594 574,418 ------- ------- ------- ------- ------- Oil and NGL (Mbbls) Developed...................... 3,344 6,431 8,880 10,703 14,971 Undeveloped.................... 1,195 2,018 1,983 3,972 14,803 ------- ------- ------- ------- ------- Total....................... 4,539 8,449 10,863 14,675 29,774 ------- ------- ------- ------- ------- Total (Mmcfe).................... 101,797 200,064 298,065 383,644 753,062 ======= ======= ======= ======= =======
In connection with the evaluation of its reserves, the Company has engaged the following independent petroleum consultants: Netherland, Sewell & Associates, Inc. (Permian and Gulf Coast), H.J. Gruy and Associates, Inc. (Midcontinent and Gulf Coast), Huddleston & Co., Inc. (Midcontinent), Wright & Company, Inc. (Appalachia), and Clay, Holt & Klammer (Appalachia). These engineers have been employed primarily based on geographic expertise as well as their history in engineering certain of the acquired properties. At December 31, 1997, approximately 91% of the proved reserves set forth above were evaluated by independent petroleum consultants, while the remainder were evaluated by the Company's engineering staff. All estimates of oil and gas reserves are subject to significant uncertainty. The following table sets forth as of December 31, for the periods presented, the estimated future net cash flow from and the Present Value of the proved reserves in millions. Future net cash flow represents future gross cash flow from the production and sale of proved reserves, net of production costs (including production taxes, ad valorem taxes and operating expenses) and future development costs. Such calculations, which are prepared in accordance with the Statement of Financial Accounting Standards No. 69 "Disclosures about Oil and Gas Producing Activities" are based on cost and price factors at December 31, 1997. Average product prices in effect at December 31, 1997 were $16.17 per barrel of oil and $2.58 per Mcf of gas. There can be no assurance that the proved reserves will be developed within the periods indicated or that prices and costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information and different reservoir engineers often arrive at different estimates for the same properties. No estimates of reserves have been filed with or included in reports to another federal authority or agency since December 31, 1997.
1993 1994 1995 1996 1997 ------ ------ ------ ------ ------ Future net cash flow.................. $ 141 $ 271 $ 413 $ 941 $1,276 Present value Pre-tax............................. 65 151 229 492 632 After tax........................... 54 120 174 351 511
SIGNIFICANT PROPERTIES The Company's reserves at December 31, 1997 were grouped into two regions, Southwest and Appalachia. Properties in the Southwest region are divided into three business units, the Permian, Midcontinent and Gulf Coast units. At December 31, 1997, the Company's properties included working interests in 8,394 gross (6,512 9 11 net) productive oil and gas wells and royalty interests in 349 additional wells. The Company also held interests in 473,000 gross (359,500 net) undeveloped acres. The following table sets forth summary information with respect to the Company's estimated proved oil and gas reserves at December 31, 1997.
PRESENT VALUE --------------------- NATURAL AMOUNT OIL & NGL GAS TOTAL (IN THOUSANDS) % (MBBLS) (MMCF) (MMCFE) -------------- --- --------- ----------- ------- Southwest Permian..................... $218,223 35% 20,254 174,980 296,505 Midcontinent................ 91,969 14 4,717 74,042 102,344 Gulf Coast.................. 69,386 11 3,867 31,036 54,237 -------- --- ------ ------- ------- Subtotal................. 379,578 60 28,838 280,058 453,086 Appalachia.................... 252,758 40 936 294,360 299,976 -------- --- ------ ------- ------- Total.................... $632,336 100% 29,774 574,418 753,062 ======== === ====== ======= =======
SOUTHWEST REGION The Company's Southwestern properties are situated in the Permian Basin and Val Verde Basins of west Texas, the Anadarko Basin of western Oklahoma, the Texas panhandle, the Rio Grande Embayment of south Texas, the East Texas Basin, the San Juan Basin of New Mexico and southwestern Louisiana. Reserves in these basins represent 60% of total Present Value at December 31, 1997. Southwestern proved reserves totaled 453 Bcfe, of which approximately 62% were natural gas. At December 31, 1997, the Southwest Region properties had a development inventory of 1,018 proven drilling locations and recompletions. Permian. The Permian business unit properties, located in the Permian and Val Verde Basins of west Texas, contained 297 Bcfe of proved reserves, or 35% of total Present Value. Net daily production averages 2,600 barrels of oil and NGL and 38 Mmcf of gas. Producing wells total 1,437 (1,154 net), of which the Company operates 98% on a total reserve basis. Major producing properties include the Sonora area, Sterling area, Big Lake area, and Fuhrman-Mascho fields. The Oakridge and Frances Hill fields in the Sonora area produce from multiple deltaic channel Canyon sandstones at depths of 2,600 to 6,000 feet. At Sterling, gas production is derived from Canyon/Cisco sub-marine sand deposits at 4,000 to 8,000 foot depths, while oil production comes from Silurian Fusselman carbonates. Sterling area gas production is liquids-rich and is transported to the Company's 25,000 Mcf/d gas plant, which processes gas from the Company's operated properties, as well as gas produced by third parties. The Big Lake and Fuhrman-Mascho properties produce primarily oil from the San Andres/Grayburg formations at depths ranging from 2,500 feet to 4,600 feet. At December 31, 1997, the Permian properties contained a development inventory of 312 recompletions and 479 infill drilling locations. Midcontinent. The Midcontinent business unit properties, located in the Anadarko Basin of western Oklahoma and the Texas panhandle, as well as the San Juan Basin of New Mexico, held proved reserves of 102 Bcfe. These reserves, representing 14% of the total Present Value, were 72% natural gas. Of 480 gross (339 net) wells, the Company operates 96%. The unit's largest property is in the Okeene Field, including over 250 operated wells. At December 31, the Midcontinent properties produce an average of 300 barrels of oil and 14 Mmcf of gas per day. The properties produce from a variety of sands and carbonates in both structural and stratigraphic traps on the Hunton, Red Fork, Simpson and Morrow formations at 6,000 to 12,000 foot depths. The Midcontinent development inventory includes 80 recompletions and 44 drilling locations. In February 1998, the Company sold all of its properties in the San Juan Basin. Gulf Coast. The Gulf Coast business unit properties contained 54 Bcfe of proved reserves at December 31, 1997, or 11% of the total Present Value. The reserves were 57% natural gas. At December 31, 1997 daily production from the Gulf Coast properties averages 1,500 barrels of oil and 15 Mmcf of gas. The properties are located primarily onshore, from deep south Texas to the East Texas basin and southwest Louisiana. Major fields onshore include Hagist Ranch, Laura LaVelle, Alta Mesa, Riverside, Keeran/Welder and Moses Bayou. These fields produce from the Wilcox, Frio, Yegua, Vicksburg, Miocene, Cotton Valley and Taylor formations at depths ranging from 1,000 to 15,000 feet. In total, the onshore properties include 325 wells (257 net), of which 10 12 95% are Company operated. The offshore properties in the Gulf of Mexico include seven platforms offshore in water depths ranging from 50 to 220 feet. All 15 offshore wells (4 net) are operated by experienced third parties. The entire Gulf Coast region is characterized by relatively complex geology, multiple producing horizons and substantial exploitation and exploration potential. At December 31, 1997, the Gulf Coast properties had a proven development inventory of 82 recompletions and 21 drilling locations. APPALACHIAN REGION At December 31, 1997, the Appalachian properties contained 300 Bcfe of proved reserves, representing 40% of the Company's total Present Value. The reserves are attributable to 6,152 gross wells (4,752 net wells) located in Pennsylvania, Ohio, West Virginia and New York. The Company operates 93% of these wells. The reserves, which on an Mcfe basis are 98% natural gas, produce principally from the Medina, Clinton and Knox sequence of formations at depths ranging from 2,500 to 7,000 feet. Net daily production currently totals 400 barrels of oil and 52 Mmcf of gas. After initial flush production, these properties are characterized by gradual decline rates. Gas production is transported through over 2,700 miles of Company owned gas gathering systems and is sold primarily to utilities and industrial end-users. PRODUCTION The following table sets forth production information for the preceding five years (in thousands, except average sales price and operating cost data).
YEAR ENDED DECEMBER 31, ---------------------------------------------------- 1993 1994 1995 1996 1997 ------- ------- ------- ------- -------- Production Oil and NGL (Bbl)..................... 318 640 913 1,068 1,794 Gas (Mcf)............................. 2,590 6,996 12,471 21,231 38,409 Total (Mcfe) (a)...................... 4,498 10,836 17,949 27,641 49,170 Revenues Oil................................... $ 5,118 $ 9,743 $15,133 $20,425 $ 28,800 Gas................................... 6,014 14,718 22,284 47,629 101,217 ------- ------- ------- ------- -------- Total................................. $11,132 $24,461 $37,417 $68,054 $130,017 Direct operating expenses (b)........... 3,184 8,130 11,302 20,676 31,481 ------- ------- ------- ------- -------- Gross margin............................ $ 7,948 $16,331 $26,115 $47,378 $ 98,536 ======= ======= ======= ======= ======== Average sales price Oil (Bbl)............................. $ 16.07 $ 15.23 $ 16.57 $ 19.56 $ 18.22 NGL (Bbl)............................. -- -- -- $ 10.22 $ 9.06 Gas (Mcf)............................. $ 2.32 $ 2.10 $ 1.79 $ 2.24 $ 2.64 Mcfe (a).............................. $ 2.47 $ 2.26 $ 2.08 $ 2.46 $ 2.64 Average operating expense per Mcfe.............................. $ 0.71 $ 0.75 $ 0.63 $ 0.75 $ 0.64
- --------------- (a) Oil is converted to Mcfe at a rate of 6 Mcf per barrel. (b) Includes severance and production taxes. PRODUCING WELLS The following table sets forth information relating to productive wells at December 31, 1997. The Company owns royalty interests in an additional 349 wells. Wells are classified as oil or gas according to their predominant production stream. 11 13
AVERAGE GROSS NET WORKING WELLS WELLS INTEREST ----- ----- --------- Crude oil................................................ 1,735 1,069 62% Natural gas.............................................. 6,659 5,443 82% ----- ----- Total.................................................. 8,394 6,512 78% ===== =====
ACREAGE The following table sets forth the developed and undeveloped acreage held at December 31, 1997.
AVERAGE WORKING GROSS NET INTEREST --------- ------- -------- Developed........................................... 759,700 601,500 79% Undeveloped......................................... 473,000 359,500 76% --------- ------- Total............................................. 1,232,700 961,000 78% ========= =======
DRILLING RESULTS The following table summarizes drilling activities for the three years ended December 31, 1997.
YEAR ENDED DECEMBER 31, ------------------------------------------------ 1995 1996 1997 ------------- ------------- -------------- GROSS NET GROSS NET GROSS NET ----- ---- ----- ---- ----- ----- Exploratory wells: Productive.................................. 5.0 0.4 7.0 3.4 12.0 2.8 Dry......................................... 2.0 0.2 4.0 1.1 8.0 2.0 Development wells: Productive.................................. 53.0 38.8 49.0 45.2 186.0 164.1 Dry......................................... 2.0 0.2 3.0 2.2 7.0 5.4 Total Wells: Productive.................................. 58.0 39.2 56.0 48.6 198.0 166.9 Dry......................................... 4.0 0.4 7.0 3.3 15.0 7.4 ---- ---- ---- ---- ----- ----- Total.................................... 62.0 39.6 63.0 51.9 213.0 174.3 ==== ==== ==== ==== ===== =====
REAL PROPERTY The Company owns a 24,000 square foot facility located on seven acres in Ohio. The Company leases approximately 33,000 square feet in Texas and Oklahoma under standard office lease arrangements that expire at various times through March 2004. All facilities are adequate to meet the Company's existing needs and can be expanded with minimal expense. The Company owns various rolling stock and other equipment which is used in its field operations. Such equipment is believed to be in good repair and, while such equipment is important to its operations, it can be readily replaced as necessary. ITEM 3. LEGAL PROCEEDINGS The Company is involved in various legal actions and claims arising in the ordinary course of business. In the opinion of management, such litigation and claims will be resolved without a material adverse effect on the Company's financial position. In April 1997, an action was filed by an individual in United States District Court in the Western District of Oklahoma seeking $550,000 in cash plus 100,000 shares of Red Eagle Resources Corporation Common Stock 12 14 (approximately 87,000 shares of the Company's Common Stock). The individual claims he is entitled to fees from the Company based upon a Yemeni oil concession that he claims Red Eagle Resources Corporation received or had the opportunity to receive in 1992, which was prior to the acquisition of Red Eagle by the Company. Based upon the Company's examination of the available documentation relevant to such claim, the Company believes that the claim is without merit because the oil concession was never obtained and Red Eagle Resources Corporation did not have a duty to obtain a concession. The Company is vigorously defending this action, and as stated above, believes the action is without merit. A separate claim for approximately $2.0 million with respect to the alleged Yemeni oil concession was received in January 1997. Since that date, no further action has been taken and the Company believes the claim is without merit. In July 1997, a gas utility filed an action in the state district court in Tarrant County, Texas. In the lawsuit, the gas utility has asserted a breach of contract claim arising out of a gas purchase contract, in which it is buyer and the Company is seller. The gas utility seeks damages in the amount of approximately $2 million as of January 1998, which amount the utility alleges will increase by the time of the trial. The Company has counterclaimed and seeks damages for breach of contract and for repudiation of the contract. The Company seeks past and future damages of approximately $17 million which sum will also increase by the time of the trial. The Company is also seeking a declaratory judgement that under the contract, the gas utility has a minimum purchase obligation. The case is currently scheduled for a June 1, 1998 trial. Discovery is underway and cross motions for summary judgment on the contract issues are currently pending. The Company believes strongly in its interpretation of the contract and intends to prosecute the case vigorously, but is not in the position to predict with any level of certainty what the outcome of the trial will be. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None. PART II ITEM 5. MARKET FOR THE COMMON STOCK AND RELATED MATTERS The Company's Common Stock is listed on New York Stock Exchange ("NYSE") under the symbol "LOM". Prior to listing on the NYSE in October 1996, the Common Stock was listed on the Nasdaq National Market. During 1997, trading volume averaged 159,400 shares per day. On March 9, 1998, the closing price of the Common Stock was $16.38. The following table sets forth the high and low sales prices as reported on the NYSE Composite transaction tape or the Nasdaq National Market, as applicable, on a quarterly basis for the periods indicated.
COMMON AVERAGE DAILY HIGH LOW DIVIDENDS VOLUME ------- ------- --------- -------------- (SHARES) 1997 First Quarter.......................... $23.625 $16.000 $ .02 216,000 Second Quarter......................... 19.375 16.000 .02 111,600 Third Quarter.......................... 20.125 14.750 .03 179,400 Fourth Quarter......................... 19.750 15.813 .03 133,300 1996 First Quarter.......................... 12.125 9.560 .01 133,800 Second Quarter......................... 15.500 11.625 .01 92,400 Third Quarter.......................... 14.875 12.750 .02 97,400 Fourth Quarter......................... 17.375 13.125 .02 102,100
13 15 DIVIDENDS Dividends on the Common Stock were initiated in late 1995 and have been paid in each quarter since that time. The Convertible Preferred Stock is entitled to receive cumulative quarterly dividends at the annual rate of $2.03 per share. If there is any arrearage in dividends on preferred stock, the Company may not pay dividends on the Common Stock. The Company has never been in arrears in the payment of preferred dividends. The payment of dividends is subject to declaration by the Board of Directors and may depend on earnings, capital expenditures and market factors existing from time to time. The bank credit facility and the indenture for the 6% Convertible Subordinated Debenture and 8.75% Senior Subordinated Notes contain restrictions on the Company's ability to pay dividends on capital stock. Under the most restrictive of these provisions, the Company could have paid $629,000 of dividends as of December 31, 1997. HOLDERS OF RECORD At March 9, 1998, the number of holders of record of the Common Stock and Convertible Preferred Stock were approximately 3,900 and 1, respectively. ITEM 6. SELECTED FINANCIAL DATA The following table presents selected financial information covering the preceding five years.
AS OF OR FOR THE YEAR ENDED DECEMBER 31, --------------------------------------------------- 1993 1994 1995 1996 1997 ------- -------- -------- -------- -------- (IN THOUSANDS, EXCEPT PER SHARE DATA) OPERATIONS Revenues............................. $12,109 $ 27,127 $ 42,018 $ 77,015 $149,338 Net income........................... 1,391 2,619 4,390 12,615 (23,332) Earnings (loss) per share............ .19 .25 .31 .71 (1.31) Earnings (loss) per share -- dilutive.................. .18 .25 .31 .69 (1.31) BALANCE SHEET Working capital...................... $ 1,350 $ 1,002 $ 4,563 $ 12,896 $ (5,167) Oil and gas properties, net.......... 55,310 112,964 176,702 229,417 629,187 Total assets......................... 76,333 141,768 214,788 282,547 764,213 Long-term debt....................... 30,689 61,885 83,035 116,780 366,712 Trust convertible preferred securities......................... -- -- -- -- 120,000 Stockholders' equity................. 32,263 43,248 99,367 117,529 196,950
The following table sets forth summary unaudited financial information on a quarterly basis for the past two years (in thousands, except per share data).
1996 -------------------------------------------- MAR. 31 JUNE 30 SEPT. 30 DEC. 31 -------- -------- -------- -------- Revenues.............................. $ 17,213 $ 19,228 $ 18,674 $ 21,900 Net income............................ 2,603 2,780 2,719 4,513 Earnings per share.................... .14 .15 .15 .27 Earnings per share -- dilutive........ .14 .15 .14 .25 Total assets.......................... 232,207 274,041 284,152 282,547 Long-term debt........................ 95,090 119,380 121,905 116,780 Stockholders' equity.................. 101,146 110,762 112,866 117,529
14 16
1997 -------------------------------------------- MAR. 31 JUNE 30 SEPT. 30 DEC. 31 -------- -------- -------- -------- Revenues.............................. $ 37,750 $ 32,781 $ 36,118 $ 42,689 Net income (loss)(a).................. 6,562 2,369 2,809 (35,072) Earnings (loss) per share(a).......... .35 .09 .11 (1.73) Earnings (loss) per share -- dilutive(a)................ .32 .09 .11 (1.73) Total assets.......................... 667,522 674,835 780,620 764,213 Long-term debt........................ 390,230 386,711 489,007 366,712 Trust convertible preferred securities.......................... -- -- -- 120,000 Stockholders' equity.................. 218,146 219,769 223,961 196,950
- --------------- (a) Includes a $58.7 million provision for impairment ($38.7 million after tax) recorded in the fourth quarter. The total of the earnings per share for each quarter does not equal the earnings per share for the full year, either because the calculations are based on the weighted average shares outstanding during each of the individual periods, or due to rounding. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FACTORS EFFECTING FINANCIAL CONDITION AND LIQUIDITY LIQUIDITY AND CAPITAL RESOURCES General The following discussion compares the Company's financial condition at December 31, 1997 to its financial condition at December 31, 1996. The Company was able to maintain a solid financial condition in 1997 despite spending over $597 million on acquisition, development and exploration activities. At December 31, 1997, the Company had $9.7 million in cash and total assets of $764.2 million. During 1997, long-term debt rose from $116.8 million to $366.7 million. At December 31, 1997, long term debt to total book capitalization was 53.6%. Securities Offerings In March 1997, the Company completed offerings of 4,060,000 shares of Common Stock for gross proceeds of $69 million and $125 million of 8.75% Senior Subordinated Notes due 2007(the "8.75% Notes"). The 8.75% Notes are unconditionally guaranteed on an unsecured, senior subordinated basis, by each of the Company's Restricted Subsidiaries (as defined in the Indenture for the 8.75% Notes), provided that such guarantees will terminate under certain circumstances. The Indenture for the 8.75% Notes contains certain covenants, including, but not limited to, covenants with respect to the following matters: (i) limitation on restricted payments; (ii) limitation on the incurrence of indebtedness and issuance of Disqualified Stock (as defined in the Indenture for the 8.75% Notes); (iii) limitation on liens; (iv) limitation on disposition of proceeds of asset sales; (v) limitation on transactions with affiliates; (vi) limitation on dividends and other payment restrictions affecting restricted subsidiaries; (vii) restrictions on mergers, consolidations and transfers of assets; and (viii) limitation on "layering" indebtedness. In October 1997, a subsidiary of the Company completed a private placement of 2,400,000 trust preferred securities for $120 million to certain "qualified institutional buyers" (as defined in Rule 144A under the Securities Act) and to institutional "accredited investors" (as defined in Rule 501 (a)(1),(2),(5) or (7) under the Securities Act). The trust preferred securities carry a 5.75% coupon and are convertible into Common Stock at a conversion price of $23.50 per share. The securities have sold without registration under the Securities Act in reliance on Section 4(2) of the Securities Act. The proceeds from the three offerings of $314 million were used to repay a portion of its bank credit facility ("the Bank Facility"). 15 17 In December 1997, the Company issued 554,101 shares of Common Stock to Arrow Operating Company as part of the purchase price for certain Texas oil properties. The Securities were sold without registration under the Securities Act in reliance on Section 4(2) of the Securities Act. See "Business -- Recent Significant Acquisitions -- Fuhrman-Mascho Acquisition." Cash Flow The Company's principal operating sources of cash include sales of oil and gas and revenues from transportation, processing and marketing. The Company's cash flow is highly dependent upon oil and gas prices. Decreases in the market price of oil or gas could result in reductions of both cash flow and the borrowing base under the Bank Facility which would result in decreased funds available, including funds intended for planned capital expenditures. The Company's net cash provided by operations for the years ended December 31, 1995, 1996 and 1997 was $16.6 million, $38.4 million and $82.4 million, respectively. The increases in the Company's cash flow from operations are attributed to higher production volumes achieved primarily through acquisition, development and exploration activities. The Company's net cash used in investing for the years ended December 31, 1995, 1996 and 1997 was $76.1 million, $69.7 million and $506.5 million, respectively. Investing activities for these periods are comprised primarily of additions to oil and gas properties through acquisitions and development and, to a lesser extent, exploration and additions of field service assets. These uses of cash have historically been partially offset through the Company's policy of divesting those properties that it deems to be marginal or non-strategic. The Company's activities have been financed through a combination of operating cash flow, bank borrowings and capital raised through securities offerings. The Company's net cash provided by financing for the years ended December 31, 1995, 1996 and 1997 was $57.7 million, $36.8 million and $425.2 million, respectively. Sources of financing used by the Company have been primarily borrowings under its Bank Facility and capital raised through securities offerings. Capital Requirements In 1997, $58.8 million of capital was expended on development and exploration activities. Although these expenditures are principally discretionary, the Company is currently anticipating that it will spend approximately $300 million on development and exploration activities over the next three years. The development and exploration expenditures are currently expected to consume a large portion of internally generated cash flow. The remaining cash flow will be available for debt repayment, acquisitions, or other capital expenditures. See "Business -- Development and Exploration Activities." Bank Facility In connection with the Cometra Acquisition, the Company and its subsidiaries expanded its existing bank credit facility. The Bank Facility permits the Company to obtain revolving credit loans and to issue letters of credit for the account of the Company from time to time in an aggregate amount not to exceed $400 million. The borrowing base is currently $325 million and is subject to semi-annual determination and certain other redeterminations based upon a variety of factors, including the discounted present value of estimated future net cash flow from oil and gas production. At December 31, 1997, the Company had $138 million of availability under the Bank Facility. At the Company's option, loans may be prepaid, and revolving credit commitments may be reduced, in whole or in part at any time in certain minimum amounts. At the Company's option, the applicable interest rate per annum is the LIBOR plus a margin ranging from 0.625% to 1.125%. The facility contains other alternative rate options which have never been utilized by the Company. Based on levels of debt outstanding as of December 31, 1997, the margin was 0.875%. Hedging Activities Periodically, the Company enters into futures, option and swap contracts to reduce the effects of fluctuations in crude oil and natural gas prices. At December 31, 1997, the Company had open contracts for gas price swaps 16 18 of 3.3 Bcf. The swap contracts are designed to set average prices ranging from $2.10 to $3.57 per Mcf. While these transactions have no carrying value, the Company's mark-to-market exposure under these contracts at December 31, 1997 was a net gain of approximately $1.1 million. These contracts expire monthly through March 1998. The gains or losses on the Company's hedging transactions are determined as the difference between the contract price and a reference price, generally closing prices on the NYMEX. The resulting transaction gains and losses are determined monthly and are included in the period the hedged production or inventory is sold. Net gains or losses relating to these derivatives for the years ended December 31, 1995, 1996 and 1997 approximated $217,000, $(724,000) and $(882,000), respectively. INFLATION AND CHANGES IN PRICES The Company's revenues and the value of its oil and gas properties have been and will be affected by changes in oil and gas prices. The Company's ability to maintain current borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent on oil and gas prices. Oil and gas prices are subject to significant seasonal and other fluctuations that are beyond the Company's ability to control or predict. During 1997, the Company received an average of $18.22 per barrel of oil and $2.64 per Mcf of gas. Although certain of the Company's costs and expenses are affected by the level of inflation, inflation did not have a significant effect in 1997. Should conditions in the industry improve, inflationary cost pressures may resume. RESULTS OF OPERATIONS Comparison of 1997 to 1996 The Company reported a net loss for the year ended December 31, 1997 of $23.3 million, as compared to $12.6 million net income for 1996. During the fourth quarter, the Company recorded a provision for impairment with regard to certain of its oil and gas properties amounting to $58.7 million ($38.7 million after tax). Excluding the effects of the non-cash impairment charge, net income would have risen 22% to $15.4 million. The increase is principally the result of (i) higher production volumes, (ii) lower per unit operating and overhead costs and (iii) higher average product prices. During the year, oil and gas production volumes increased 78% to 49.2 Bcfe, an average of 134.7 Mmcfe per day. The increased revenues recognized from production volumes were aided by a 7% increase in the average price received per Mcfe of production to $2.64. The average oil price decreased 7% to $18.22 per barrel while average gas prices increased 18% to $2.64 per Mcf. As a result of the Company's larger base of producing properties and production, oil and gas production expenses increased 52% to $31.5 million in 1997 versus $20.7 million in 1996. The average operating cost per Mcfe produced decreased 15% from $0.75 in 1996 to $0.64 in 1997. Transportation, processing and marketing revenues increased 110% to $11.7 million versus $5.6 million in 1996 principally due to production growth. Transportation, processing and marketing expenses increased 134% to $3.9 million versus $1.7 million in 1996. The increase in expenses was due to production growth and higher administrative costs associated with increased gas marketing activities. Exploration expense increased 73% to $2.5 million due to the Company's increased involvement in seismic and exploratory drilling activity. General and administrative expenses increased 33% from $4.0 million in 1996 to $5.3 million in 1997. As a percentage of revenues, general and administrative expenses were 4% in 1997 as compared to 5% in 1996. This decreasing trend reflects the spreading of administrative costs over a growing asset base. Interest and other income rose 124% to $7.6 million primarily due to $3.2 million on gains from sales of marketable securities (which were not related to hedging activities), and $4.1 million from the gain on the sale of non-strategic assets. Interest expense increased 263% to $27.2 million as compared to $7.5 million in 1996. This was primarily a result of the higher average outstanding debt balance during the year due to the financing of acquisitions and drilling activities. The average outstanding balances on the Bank Facility were $107.2 million and $192.1 million for 1996 and 1997, respectively. The weighted average interest rate on these borrowings were 6.7% and 7.3% for the years ended December 31, 1996 and 1997, respectively. 17 19 Depletion, depreciation and amortization increased 148% compared to 1996 as a result of increased production volumes and increased depletion rates per volume. The Company-wide depletion rate was $0.73 per Mcfe in 1996 and $1.03 per Mcfe in 1997. Comparison of 1996 to 1995 The Company reported net income for the year ended December 31, 1996 of $12.6 million, a 187% increase over 1995. The increase is the result of (i) higher production volumes, over 60% of which is attributable to acquisitions and the remainder of which is attributable to development activities; (ii) increased prices received from the sale of oil and gas products and (iii) gains from asset sales. During the year, oil and gas production volumes increased 54% to 27.6 Bcfe, an average of 76 Mmcfe/d. The increased revenues recognized from production volumes were aided by an 18% increase in the average price received per Mcfe of production to $2.46. The average oil price increased 18% to $19.56 per barrel while average gas prices increased 25% to $2.24 per Mcf. As a result of the Company's larger base of producing properties and production, oil and gas production expenses increased 83% to $20.7 million in 1996 versus $11.3 million in 1995. The average operating cost per Mcfe produced increased 19% from $0.63 in 1995 to $0.75 in 1996 due to unsuccessful recompletion costs and increases in personnel costs. Gas transportation and marketing revenues increased 70% to $5.6 million versus $3.3 million in 1995 principally due to production growth. Gas transportation and marketing expenses increased 97% to $1.7 million versus $0.8 million in 1995. The increase in expenses was due to production growth, higher administrative costs associated with the growth and lower overall margins on gas marketing activities. Exploration expense increased 185% to $1.5 million due to the Company's increased involvement in seismic and exploratory drilling. The Company participated in 11 exploratory wells in 1996 versus 7 exploratory wells in 1995. General and administrative expenses increased 45% from $2.7 million in 1995 to $4.0 million in 1996. As a percentage of revenues, general and administrative expenses were 5% in 1996 as compared to 7% in 1995. This decreasing trend reflects the spreading of administrative costs over a growing asset base. Interest and other income rose 157% to $3.4 million primarily due to $1.4 million on gains from sales of marketable securities (which were not related to hedging activities), and $1.2 million from the gain on the sale of the Oklahoma well servicing assets. Interest expense increased 34% to $7.5 million as compared to $5.6 million in 1995. This was primarily as a result of the higher average outstanding debt balance during the year due to the financing of capital expenditures. The average outstanding balances on the Bank Facility were $73.3 million and $107.2 million for 1995 and 1996, respectively. The weighted average interest rate on these borrowings were 7.3% and 6.7% for the years ended December 31, 1995 and 1996, respectively. Depletion, depreciation and amortization increased 50% compared to 1995 as a result of increased production volumes during the year. The Company-wide depletion rate was $0.73 per Mcfe in 1995 and 1996. Comparison of 1995 to 1994 The Company reported net income for the year ended December 31, 1995 of $4.4 million, a 68% increase over 1994. This increase is the result of higher production volumes attributable to acquisition and development activities. During the year, oil and gas production volumes increased 66% to 17.9 Bcfe, an average of 49.2 Mmcfe/d. The increased revenues recognized from production volumes were partially offset by an 8% decrease in the average price received per Mcfe of production to $2.08. The average oil price increased 9% to $16.57 per barrel while average gas prices dropped 15% to $1.79 per Mcf. As a result of the Company's larger base of producing properties and production, oil and gas production expenses increased 39% to $11.3 million in 1995 versus $8.1 million in 1994. The average operating cost per Mcfe produced decreased 16% from $0.75 in 1994 to $0.63 in 1995. 18 20 Gas transportation and marketing revenues increased 50% to $3.3 million versus $2.2 million in 1994. Coupled with this increase in gas transportation and marketing revenues was a 73% increase in associated expenses for the year. These increases were due primarily to the acquisition of several pipeline systems, as well as the expansion of the gas marketing efforts. Exploration expense increased 43% to $0.5 million due to the Company's increased involvement in exploration projects. These costs include delay rentals, seismic and exploratory drilling activities. General and administrative expenses increased 10% from $2.5 million in 1994 to $2.7 million in 1995. As a percentage of revenues, general and administrative expenses were 7% in 1995 as compared to 9% in 1994. This improvement reflects the spreading of administrative costs over a growing asset base. Interest and other income rose 180% primarily due to higher sales of non-strategic properties. Interest expense increased 99% to $5.6 million as compared to $2.8 million in 1994. This was primarily as a result of the higher average outstanding debt balance during the year due to the financing of capital expenditures. The average outstanding balances on the Bank Facility were $42.0 million and $73.3 million for 1994 and 1995, respectively. The weighted average interest rate on these borrowings was 6.3% and 7.3% for the years ended December 31, 1994 and 1995, respectively. Depletion, depreciation and amortization increased 47% compared to 1994 as a result of increased production volumes during the year. The increased depletion of oil and gas properties was partially offset by the reduction of depreciation of field services assets due to the 1994 sale of field service assets. The Company-wide depletion rate for 1995 was $0.73 per Mcfe versus $0.74 per Mcfe in 1994 due to the addition of properties at lower than historical Mcfe costs. YEAR 2000 The Company has developed an action plan and identified the resources needed to convert the majority of its computer systems and software applications to achieve a year 2000 date conversion with no effect on customers or disruption to business operations. Implementation of the plan has begun and the Company anticipates completion of testing of critical systems by the end of 1998. The Company estimates that the cost to complete these efforts, which primarily includes the purchase of software upgrades under normal maintenance agreements with third party vendors, will not be material and will be expended primarily in 1998. In addition, the Company has discussed with its vendors and customers the need to be year 2000 compliant. Although the Company has no reason to believe that its vendors and customers will not be compliant by the year 2000, the Company is unable to determine the extent to which year 2000 issues will effect its vendors and customers, and the Company continues to discuss with its vendors and customers the need for implementing procedures to address this issue. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Reference is made to the Index to Financial Statements on page 28 for a listing of the Company's financial statements and notes thereto and for supplementary schedules. Schedules I, III, IV, V, VI, VII, VIII, IX, X, XI, XII and XIII have been omitted as not required or not applicable or because the information required to be presented is included in the financial statements and related notes. MANAGEMENT RESPONSIBILITY FOR FINANCIAL STATEMENTS 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. 19 21 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, Arthur Andersen 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. CHANGE IN ACCOUNTANTS AND DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE COMPANY The current executive officers and directors of the Company are listed below, together with a description of their experience and certain other information. Each of the directors was elected for a one-year term at the Company's 1997 annual meeting of stockholders. Executive officers are appointed by the Board of Directors.
HELD NAME AGE OFFICE SINCE POSITION WITH COMPANY - ---- --- ------------ --------------------- Thomas J. Edelman.................... 47 1988 Chairman and Chairman of the Board John H. Pinkerton.................... 44 1988 President, Chief Executive Officer and Director Robert E. Aikman..................... 66 1990 Director Anthony V. Dub....................... 48 1995 Director Allen Finkelson...................... 51 1994 Director Ben A. Guill......................... 47 1995 Director C. Rand Michaels..................... 60 1976 Vice Chairman and Director Steven L. Grose...................... 49 1980 Senior Vice President -- Appalachia Region Chad L. Stephens..................... 42 1990 Senior Vice President -- Southwest Region Thomas W. Stoelk..................... 42 1994 Senior Vice President -- Finance and Administration Paul F. Blanchard.................... 37 1997 Vice President -- Midcontinent Division Jeffery A. Bynum..................... 43 1985 Vice President -- Land John R. Frank........................ 42 1990 Vice President -- Information Management Danny M. Sowell...................... 47 1996 Vice President -- Energy Services George A. Teer....................... 50 1997 Vice President -- Permian Division Geoffrey T. Doke..................... 31 1996 Controller
Thomas J. Edelman, holds the office of Chairman and is Chairman of the Board of Directors. Mr. Edelman joined the Company in 1988 and served as its Chief Executive Officer until 1992. From 1981 to 1997, Mr. Edelman served as a director and President of Snyder Oil Corporation ("SOCO"), an independent, publicly traded oil and gas company. In 1996, Mr. Edelman was appointed Chairman, President and Chief Executive Officer of Patina Oil & Gas Corporation. Prior to 1981, Mr. Edelman was a Vice President of The First Boston Corporation. From 1975 through 1980, Mr. Edelman was with Lehman Brothers Kuhn Loeb Incorporated. Mr. Edelman received his Bachelor of Arts Degree from Princeton University and his Masters Degree in Finance from Harvard University's Graduate School of Business Administration. Mr. Edelman serves as a director of Petroleum Heat & Power Co., Inc., a Connecticut-based fuel oil distributor, Star Gas Corporation, a private 20 22 company, which is the general partner of Star Gas Partners, L.P., a publicly-traded master limited partnership, which distributes propane gas, as well as, Paradise Music & Entertainment, Inc., and Weatherford Enterra, Inc. John H. Pinkerton, President, Chief Executive Officer and a Director, joined the Company in 1988. He was appointed President in 1990 and Chief Executive Officer in 1992. Previously, Mr. Pinkerton was a Senior Vice President-Acquisitions of SOCO. Prior to joining SOCO in 1980, Mr. Pinkerton was with Arthur Andersen & Co. Mr. Pinkerton received his Bachelor of Arts Degree in Business Administration from Texas Christian University and his Master of Arts Degree in Business Administration from the University of Texas. Mr. Pinkerton is also director of North Coast Energy, Inc. ("North Coast"), and Venus Exploration, Inc. publicly traded exploration and production companies in which Lomak owned 24% and 21%, respectively, at December 31, 1997. Robert E. Aikman, a Director, joined the Company in 1990. Mr. Aikman has more than 40 years experience in petroleum and natural gas exploration and production throughout the United States and Canada. From 1984 to 1994 he was Chairman of the Board of Energy Resources Corporation. From 1979 through 1984, he was the President and principal shareholder of Aikman Petroleum, Inc. From 1971 to 1977, he was President of Dorchester Exploration Inc. and from 1971 to 1980, he was a Director and a member of the Executive Committee of Dorchester Gas Corporation. Mr. Aikman is also Chairman of Provident Trade Company, President of EROG, Inc., and President of The Hawthorne Company, an entity which organizes joint ventures and provides advisory services for the acquisition of oil and gas properties, including the financial restructuring, reorganization and sale of companies. He was President of Enertec Corporation which was reorganized under Chapter 11 of the Bankruptcy Code in December 1994. In addition, Mr. Aikman is a director of the Panhandle Producers and Royalty Owners Association and a member of the Independent Petroleum Association of America, Texas Independent Producers and Royalty Owners Association and American Association of Petroleum Landmen. Mr. Aikman graduated from the University of Oklahoma in 1952. Anthony V. Dub, was elected to serve as a Director of the Company in 1995. Mr. Dub is Chairman of Indigo Capital, LLC, a financial advisory firm based in New York City. Prior to forming Indigo Capital in 1997, he served as an officer of Credit Suisse First Boston, an investment banking firm. Mr. Dub joined Credit Suisse First Boston in 1971 and was named a Managing Director in 1981. Mr. Dub also serves as a Director of Nimbus CD International Inc. Mr. Dub received his Bachelor of Arts Degree from Princeton University in 1971. Allen Finkelson, was appointed a Director in 1994. Mr. Finkelson has been a partner at Cravath, Swaine & Moore since 1977, with the exception of the period from September 1983 through August 1985, when he was a managing director of Lehman Brothers Kuhn Loeb Incorporated. Mr. Finkelson was first employed by Cravath, Swaine & Moore as an associate in 1971. Mr. Finkelson received his Bachelor of Arts Degree from St. Lawrence University and his Doctor of Laws Degree from Columbia University School of Law. Ben A. Guill, was elected to serve as a Director of the Company in 1995. Mr. Guill is a Partner and Managing Director of Simmons & Company International, an investment banking firm located in Houston, Texas focused exclusively on the oil service and equipment industry. Mr. Guill has been with Simmons & Company since 1980. Prior to joining Simmons & Company, Mr. Guill was with Blyth Eastman Dillon & Company from 1978 to 1980. Mr. Guill received his Bachelor of Arts Degree from Princeton University and his Masters Degree in Finance from the Wharton Graduate School of Business at the University of Pennsylvania. C. Rand Michaels, who holds the office of Vice Chairman and is a Director, served as President and Chief Executive Officer of the Company from 1976 through 1988 and Chairman of the Board from 1984 through 1988, when he became Vice Chairman. Mr. Michaels received his Bachelor of Science Degree from Auburn University and his Master of Business Administration Degree from the University of Denver. Mr. Michaels is also a director of American Business Computers Corporation, a public company serving the beverage dispensing and fast food industries, and North Coast. Steven L. Grose, Senior Vice President -- Appalachia Region, joined the Company in 1980. Previously, Mr. Grose was employed by Halliburton Services, Inc. as a Field Engineer from 1971 until 1974. In 1974, he was promoted to District Engineer and in 1978, was named Assistant District Superintendent based in Pennsylvania. Mr. Grose is a member of the Society of Petroleum Engineers and a trustee of The Ohio Oil and Gas Association. 21 23 Mr. Grose received his Bachelor of Science Degree in Petroleum Engineering from Marietta College. Mr. Grose is also a director of North Coast. Chad L. Stephens, Senior Vice President -- Southwest Region, joined the Company in 1990. Previously, Mr. Stephens was with Duer Wagner & Co., an independent oil and gas producer, since 1988. Prior thereto, Mr. Stephens was an independent oil operator in Midland, Texas for four years. From 1979 to 1984, Mr. Stephens was with Cities Service Company and HNG Oil Company. Mr. Stephens received his Bachelor of Arts Degree in Finance and Land Management from the University of Texas. Thomas W. Stoelk, Senior Vice President -- Finance and Administration, joined the Company in 1994. Mr. Stoelk is a Certified Public Accountant and was a Senior Manager with Ernst & Young LLP. Prior to rejoining Ernst & Young LLP in 1986 he was with Partners Petroleum, Inc. Mr. Stoelk received his Bachelor of Science Degree in Industrial Administration from Iowa State University. Paul F. Blanchard, Vice President -- Midcontinent Division, joined the Company in March 1997. Previously Mr. Blanchard was operations manager for the Oklahoma Division of Enron Oil & Gas Company, where he was employed from 1991 to 1997. From 1990 to 1991, Mr. Blanchard was with Louisiana Land and Exploration Company. Prior to that, Mr. Blanchard was with Texas Oil & Gas Company. Mr. Blanchard received his Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma. Jeffery A. Bynum, Vice President -- Land and Secretary, joined the Company in 1985. Previously, Mr. Bynum was employed by Crystal Oil Company and Kinnebrew Energy Group. Mr. Bynum holds a Professional Certification with American Association of Petroleum Landmen and attended Louisiana State University in Baton Rouge, Louisiana and Centenary College in Shreveport, Louisiana. John R. Frank, Vice President -- Information Management, joined the Company in 1990. Prior to being appointed Vice President, he served as Controller. Previously Mr. Frank was with Appalachian Exploration, Inc. from 1977 to 1990, with the last portion being Vice President, Finance. Mr. Frank received his Bachelor of Arts Degree in Accounting and Management from Walsh College and attended graduate studies at the University of Akron. Danny M. Sowell, Vice President -- Energy Services, joined the Company in 1996. Previously, Mr. Sowell was President and Chief Executive Officer of Jay Gas Marketing, which Lomak acquired in 1996. Prior to founding Jay Gas, Mr. Sowell was Director of Marketing for a subsidiary of Oklahoma Gas & Electric Company. Mr. Sowell received his Master and Bachelor of Science Degrees in Mathematics from Lamar University. George A. Teer, Vice President -- Permian Division, joined the Company in 1994. Previously Mr. Teer was with Bass Enterprises from 1974 to 1994, with the last portion being Manager of their West Texas Division. Mr. Teer received his Bachelor of Science Degree in Petroleum Engineering from Texas A&M University. Geoffrey T. Doke, Controller, joined the Company in 1991. He was appointed Treasurer in 1996 and Controller in 1997. Previously, Mr. Doke served in the accounting department of Edisto Resources Corporation. Mr. Doke received his Bachelor of Business Administration Degree in Finance and International Business from Baylor University and his Master of Business Administration Degree from Case Western Reserve University. The Lomak Board has established three committees to assist in the discharge of its responsibilities. AUDIT COMMITTEE. The Audit Committee reviews the professional services provided by Lomak's independent public accountants and the independence of such accountants from management of Lomak. This Committee also reviews the scope of the audit coverage, the annual financial statements of Lomak and such other matters with respect to the accounting, auditing and financial reporting practices and procedures of Lomak as it may find appropriate or as have been brought to its attention. Messrs. Aikman, Dub and Guill are the members of the Audit Committee. COMPENSATION COMMITTEE. The Compensation Committee reviews and approves executive salaries and administers bonus, incentive compensation and stock option plans of Lomak. This Committee advises and consults with management regarding pensions and other benefits and significant compensation policies and 22 24 practices of Lomak. This Committee also considers nominations of candidates for corporate officer positions. The members of the Compensation committee are Messrs. Aikman, Guill and Finkelson. EXECUTIVE COMMITTEE. The Executive Committee reviews and authorizes actions required in the management of the business and affairs of Lomak, which would otherwise be determined by the Board, where it is not practicable to convene the full Board. One of the principal responsibilities of the Executive Committee will be to review and approve smaller acquisitions. The members of the Executive Committee are Messrs. Edelman, Finkelson and Pinkerton. ITEM 11. COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS Information with respect to executive compensation is incorporated herein by reference to the Company's Proxy Statement for its 1998 annual meeting of stockholders. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information with respect to security ownership of certain beneficial owners and management is incorporated herein by reference to the Company's Proxy Statement for its 1998 annual meeting of stockholders. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information with respect to certain relationships and related transactions is incorporated herein by reference to the Company's Proxy Statement for its 1998 annual meeting of stockholders. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENTS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. and 2. Financial Statements and Financial Statement Schedules. The items listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K. 3. Exhibits. The items listed on the accompanying index to exhibits are filed as part of this Annual Report on Form 10-K. (b) Reports on Form 8-K. The Company's Current Report on Form 8-K, dated February 26, 1997, as amended by Form 8-K/A, dated March 14, 1997. (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 Exhibits listed in response to Item 14 (a)3, and are incorporated herein by reference. (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. 23 25 SIGNATURES PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934, THE COMPANY HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED. Dated: March 20, 1998 LOMAK PETROLEUM, INC. By: /s/ John H. Pinkerton ---------------------------------- John H. Pinkerton President PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE PERSONS ON BEHALF OF THE COMPANY AND IN THE CAPACITIES AND ON THE DATES INDICATED. /s/ Thomas J. Edelman Thomas J. Edelman, - ----------------------------------------------------- Chairman and Chairman of the Board March 20, 1998 /s/ John H. Pinkerton John H. Pinkerton, - ----------------------------------------------------- Chief Executive Officer, President and Director March 20, 1998 /s/ Thomas W. Stoelk Thomas W. Stoelk, - ----------------------------------------------------- Chief Financial Officer and Senior Vice March 20, 1998 President -- Finance & Administration /s/ Geoffrey T. Doke Geoffrey T. Doke, - ----------------------------------------------------- Chief Accounting Officer and Controller March 20, 1998 /s/ Robert E. Aikman Robert E. Aikman, Director - ----------------------------------------------------- March 20, 1998 /s/ Allen Finkelson Allen Finkelson, Director - ----------------------------------------------------- March 20, 1998 /s/ Anthony V. Dub Anthony V. Dub, Director - ----------------------------------------------------- March 20, 1998 /s/ Ben A. Guill Ben A. Guill, Director - ----------------------------------------------------- March 20, 1998 /s/ C. Rand Michaels C. Rand Michaels, - ----------------------------------------------------- Vice Chairman and Director March 20, 1998

24 26 LOMAK PETROLEUM, INC. INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES (ITEM 14[a], [d])
PAGE NUMBER ------ Reports of Independent Public Accountants................... 26 Consolidated balance sheets at December 31, 1996 and 1997... 27 Consolidated statements of income for the years ended December 31, 1995, 1996 and 1997.......................... 28 Consolidated statements of stockholders' equity for the years ended December 31, 1995, 1996, and 1997............. 29 Consolidated statements of cash flows for the years ended December 31, 1995, 1996 and 1997.......................... 30 Notes to consolidated financial statements.................. 31
EXHIBITS All other 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 or footnotes. 25 27 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS TO THE BOARD OF DIRECTORS AND STOCKHOLDERS LOMAK PETROLEUM, INC.: We have audited the accompanying consolidated balance sheets of Lomak Petroleum, Inc. (a Delaware corporation) as of December 31, 1996 and 1997, and the related consolidated statements of income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1997. 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 financial position of Lomak Petroleum, Inc. as of December 31, 1996 and 1997, and the results of its operations and its cash flows for the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Cleveland, Ohio, February 16, 1998. 26 28 LOMAK PETROLEUM, INC. CONSOLIDATED BALANCE SHEETS
DECEMBER 31, ---------------------- 1996 1997 --------- --------- (IN THOUSANDS, EXCEPT PER SHARE DATA) ASSETS Current assets Cash and equivalents...................................... $ 8,625 $ 9,725 Accounts receivable....................................... 18,121 29,200 Marketable securities..................................... 7,658 8,041 Inventory and other....................................... 799 2,779 -------- -------- 35,203 49,745 -------- -------- Oil and gas properties, successful efforts method........... 282,519 790,603 Accumulated depletion and impairment...................... (53,102) (161,416) -------- -------- 229,417 629,187 -------- -------- Transportation, processing and field assets................. 21,139 85,904 Accumulated depreciation and impairment................... (4,997) (9,730) -------- -------- 16,142 76,174 -------- -------- Other....................................................... 1,785 9,107 -------- -------- $282,547 $764,213 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable.......................................... $ 14,433 $ 32,258 Accrued liabilities....................................... 4,603 19,046 Accrued payroll and benefit costs......................... 3,245 3,195 Current portion of debt (Note 4).......................... 26 413 -------- -------- 22,307 54,912 -------- -------- Senior debt (Note 4)........................................ 61,780 186,712 Senior subordinated notes (Note 4).......................... -- 125,000 Convertible subordinated debentures (Note 4)................ 55,000 55,000 Deferred taxes (Note 10).................................. 25,931 25,639 Company-obligated preferred securities of subsidiary trust (Note 7).................................................. -- 120,000 Commitments and contingencies (Note 6) Stockholders' equity (Notes 7 and 8) Preferred stock, $1 Par, 10,000,000 shares authorized, $2.03 convertible preferred, 1,150,000 and 1,149,840 issued and outstanding (liquidation preference $28,746,000)........................................... 1,150 1,150 Common stock, $.01 par, 50,000,000 shares authorized, 14,750,537 and 21,058,442 issued....................... 148 211 Capital in excess of par value............................ 110,248 217,631 Retained earnings (deficit)............................... 5,291 (22,412) Unrealized gain on marketable securities.................. 692 370 -------- -------- 117,529 196,950 -------- -------- $282,547 $764,213 ======== ========
See accompanying notes. 27 29 LOMAK PETROLEUM, INC. CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, ---------------------------- 1995 1996 1997 ------- ------- -------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Revenues Oil and gas sales......................................... $37,417 $68,054 $130,017 Transportation, processing and marketing.................. 3,284 5,575 11,727 Interest and other........................................ 1,317 3,386 7,594 ------- ------- -------- 42,018 77,015 149,338 ------- ------- -------- Expenses Direct operating.......................................... 11,302 20,676 31,481 Transportation, processing and marketing.................. 849 1,674 3,921 Exploration............................................... 512 1,460 2,527 General and administrative................................ 2,736 3,966 5,290 Interest.................................................. 5,584 7,487 27,175 Depletion, depreciation and amortization.................. 14,863 22,303 55,407 Provision for impairment.................................. -- -- 58,700 ------- ------- -------- 35,846 57,566 184,501 ------- ------- -------- Income (loss) before taxes.................................. 6,172 19,449 (35,163) Income taxes Current................................................... 86 729 684 Deferred.................................................. 1,696 6,105 (12,515) ------- ------- -------- 1,782 6,834 (11,831) ------- ------- -------- Net income (loss)........................................... $ 4,390 $12,615 $(23,332) ======= ======= ======== Earnings (loss) per common share (Note 11).................. $ 0.31 $ 0.71 $ (1.31) ======= ======= ======== Earnings (loss) per common share -- assuming dilution (Note 11)....................................................... $ 0.31 $ 0.69 $ (1.31) ======= ======= ========
See accompanying notes. 28 30 LOMAK PETROLEUM, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
PREFERRED STOCK COMMON STOCK --------------- -------------- CAPITAL IN RETAINED PAR PAR EXCESS OF EARNINGS SHARES VALUE SHARES VALUE PAR VALUE (DEFICIT) ------ ------ ------ ----- ---------- --------- (IN THOUSANDS) Balance, December 31, 1994.............. 200 $ 200 9,754 $ 97 $ 50,495 $ (7,544) Preferred dividends................... -- -- -- -- -- (731) Common dividends...................... -- -- -- -- -- (128) Common issued......................... -- -- 3,609 36 24,953 -- Common repurchased.................... -- -- (40) -- (332) -- $2.03 preferred issued................ 1,150 1,150 -- -- 26,657 -- Net income............................ -- -- -- -- -- 4,390 ----- ------ ------ ---- -------- -------- Balance, December 31, 1995.............. 1,350 1,350 13,323 133 101,773 (4,013) Preferred dividends................... -- -- -- -- -- (2,454) Common dividends...................... -- -- -- -- -- (857) Common issued......................... -- -- 887 9 8,687 -- Common repurchased.................... -- -- (36) -- (406) -- Conversion of 7 1/2 preferred......... (200) (200) 577 6 194 -- Net income............................ -- -- -- -- -- 12,615 ----- ------ ------ ---- -------- -------- Balance, December 31, 1996.............. 1,150 1,150 14,751 148 110,248 5,291 Preferred dividends................... -- -- -- -- -- (2,334) Common dividends...................... -- -- -- -- -- (2,037) Common issued......................... -- -- 6,307 63 107,293 -- Common repurchased.................... -- -- -- -- (107) -- Compensation in connection with stock options............................ -- -- -- -- 197 -- Net loss.............................. -- -- -- -- -- (23,332) ----- ------ ------ ---- -------- -------- Balance, December 31, 1997.............. 1,150 $1,150 21,058 $211 $217,631 $(22,412) ===== ====== ====== ==== ======== ========
See accompanying notes. 29 31 LOMAK PETROLEUM, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, -------------------------------- 1995 1996 1997 -------- -------- -------- (IN THOUSANDS) Cash flows from operations: Net income (loss)......................................... $ 4,390 $ 12,615 $(23,332) Adjustments to reconcile net income (loss) to net cash provided by operations: Depletion, depreciation and amortization............... 14,863 22,303 55,407 Provision for impairment............................... -- -- 58,700 Amortization of deferred offering costs................ -- -- 999 Deferred income taxes.................................. 1,335 6,105 (12,541) Changes in working capital net of effects of businesses: Accounts receivable.................................. (5,247) (494) (11,079) Marketable securities................................ (296) (5,264) (7,964) Inventory and other.................................. 278 137 (1,981) Accounts payable..................................... 663 5,385 17,825 Accrued liabilities and payroll and benefit costs.... 1,778 781 14,566 Gain on sale of assets and other....................... (1,203) (3,123) (8,154) -------- -------- -------- Net cash provided by operations............................. 16,561 38,445 82,446 Cash flows from investing: Acquisition of businesses, net of cash.................... -- (13,950) -- Oil and gas properties.................................... (69,992) (59,137) (497,639) Additions to property and equipment....................... (9,102) (1,250) (64,945) Proceeds on sale of assets................................ 2,981 4,671 56,070 -------- -------- -------- Net cash used in investing.................................. (76,113) (69,666) (506,514) Cash flows from financing: Proceeds from indebtedness................................ 21,304 85,201 246,025 Repayments of indebtedness................................ (808) (53,268) (26) Preferred stock dividends................................. (731) (2,454) (2,334) Common stock dividends.................................... (128) (857) (2,037) Proceeds from trust preferred securities issuance, net.... -- -- 115,999 Proceeds from common stock issuance, net.................. 10,590 8,315 67,648 Repurchase of common stock................................ (332) (138) (107) Proceeds from preferred stock issuance.................... 27,807 -- -- -------- -------- -------- Net cash provided by financing.............................. 57,702 36,799 425,168 -------- -------- -------- Change in cash.............................................. (1,850) 5,578 1,100 Cash and equivalents at beginning of period................. 4,897 3,047 8,625 -------- -------- -------- Cash and equivalents at end of period....................... $ 3,047 $ 8,625 $ 9,725 ======== ======== ======== Supplemental disclosures of non-cash investing and financing activities Purchase of property and equipment financed with common stock......................................... $ 14,299 $ -- $ 39,537 Common stock issued in connection with benefit plans...... 100 381 398
See accompanying notes. 30 32 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) ORGANIZATION AND NATURE OF BUSINESS Lomak Petroleum, Inc. ("Lomak" or the "Company") is an independent oil and gas company engaged in development, exploration and acquisition primarily in four core areas: Permian, Midcontinent, Gulf Coast and Appalachia. Historically, the Company has increased its reserves and production through acquisitions, development and exploration of its properties. At December 31, 1997, proved reserves totaled 753 Bcfe, having a pre-tax present value at constant prices on that date of $632 million and a reserve life index of 15.3 years. Lomak's objective is to maximize shareholder value through growth in its reserves, production, cashflow and earnings through a balanced program of exploration and development drilling and strategic acquisitions. In order to effectively pursue its operating strategy, the Company has concentrated its activities in selected geographic areas. In each core area, the Company has established separate acquisition, engineering, geological, operating and other technical expertise. The Company believes that this geographic focus provides it with a competitive advantage in sourcing and evaluating new business opportunities within these areas, as well as providing economies of scale in developing and operating its properties. (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION The accompanying financial statements include the accounts of the Company, all majority owned subsidiaries and its pro rata share of the assets, liabilities, income and expenses of certain oil and gas partnerships and joint ventures. Highly liquid temporary investments with an initial maturity of ninety days or less are considered cash equivalents. MARKETABLE SECURITIES The Company has adopted Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities." Under Statement No. 115, debt and marketable equity securities are required to be classified in one of three categories: trading, available-for-sale, or held to maturity. The Company's equity securities qualify under the provisions of Statement No. 115 as available-for-sale. Such securities are recorded at fair value, and unrealized holding gains and losses, net of the related tax effect, are reflected as a separate component of stockholders' equity. A decline in the market value of an available-for-sale security below cost that is deemed other than temporary is charged to earnings and results in the establishment of a new cost basis for the security. Realized gains and losses are determined on the specific identification method and are reflected in income. OIL AND GAS PROPERTIES The Company follows the successful efforts method of accounting for oil and gas properties. Exploratory costs which result in the discovery of reserves and the cost of development wells are capitalized. Geological and geophysical costs, delay rentals and costs to drill unsuccessful exploratory wells are expensed. Depletion is provided on the unit-of-production method. Oil is converted to Mcfe at the rate of 6 Mcf per barrel. The depletion rates per Mcfe were $.73, $.73 and $1.03 in 1995, 1996 and 1997, respectively. Approximately $12.2 million, $22.8 million and $111.2 million of oil and gas properties were not subject to amortization as of December 31, 1995, 1996 and 1997, respectively. The Company has adopted Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," which establishes accounting standards for the impairment of long-lived assets, certain identifiable intangibles and goodwill. SFAS No. 121 requires a review for impairment whenever circumstances indicate that the carrying amount of an asset may not be recoverable. Impairment is recognized only if the carrying amount of an asset is greater than its expected future cash flows. The amount of the impairment is based on the estimated fair value of the asset. 31 33 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In performing the review for long-lived asset recoverability during 1997, the Company recorded a $58.7 million provision for impairment which wrote down certain oil and gas properties to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the oil and gas assets, discounted at a market rate of interest. TRANSPORTATION, PROCESSING AND FIELD ASSETS The Company owns and operates approximately 3,000 miles of gas gathering systems and a gas processing plant in proximity to its principal gas properties. Depreciation is calculated on the straight-line method based on estimated useful lives ranging from four to twenty years. The Company receives fees for providing field related services. These fees are recognized as earned. Depreciation is calculated on the straight-line method based on estimated useful lives ranging from one to five years, except buildings which are being depreciated over ten to twenty-five year periods. DEBT ISSUANCE COSTS Expenses associated with the issuance of the Convertible Subordinated Debentures, Senior Subordinated Notes and Trust Convertible Preferred Securities are included in Other Assets in the accompanying balance sheets and are being amortized on the interest method over the term of the indebtedness. At December 31, 1997 the Company had $9.1 million of unamortized debt issuance costs. GAS IMBALANCES The Company uses the sales method to account for gas imbalances. Under the sales method, revenue is recognized based on cash received rather than the proportionate share of gas produced. Gas imbalances at year end 1996 and 1997 were not material. EARNINGS PER COMMON SHARE In February 1997, the Financial Accounting Standards Board issued SFAS No. 128 "Earnings per Share." Statement 128 replaced the calculation of primary and fully diluted earnings per share. Unlike primary earnings per share, basic earnings per share excludes any dilutive effects of options, warrants and convertible securities. Diluted earnings per share is very similar to the previously reported fully diluted earnings per share. All earnings per share amounts for all periods have been presented, and where appropriate, restated to conform to Statement 128 requirements. USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. NATURE OF BUSINESS The Company operates in an environment with many financial and operating risks, including, but not limited to, the ability to acquire additional economically recoverable oil and gas reserves, the inherent risks of the search for, development of and production of oil and gas, the ability to sell oil and gas at prices which will provide attractive rates of return, and the highly competitive nature of the industry and worldwide economic conditions. The Company's ability to expand its reserve base and diversify its operations is also dependent upon obtaining the necessary capital through operating cash flow, borrowings or the issuance of additional equity. 32 34 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) RECLASSIFICATIONS Certain reclassifications have been made to prior periods presentation to conform with current period classifications. (3) ACQUISITIONS All of the Company's acquisitions have been accounted for as purchases. The purchase prices were allocated to the assets acquired based on the fair value of such assets and liabilities at the respective acquisition dates. The acquisitions were funded by operating cash flow, advances under the Bank Facility and the issuance of securities. In the first quarter of 1997, the Company acquired oil and gas properties located in West Texas, South Texas and the Gulf of Mexico (the "Cometra Properties") from American Cometra, Inc. for $385 million. The Cometra Properties, located primarily in the Company's core operating areas, include 515 producing wells and additional development and exploration potential on approximately 150,000 gross acres (90,000 net acres). In addition, the Cometra Properties included 265 miles of gas pipelines, a 25,000 Mcf/d gas processing plant and an above-market gas contract with a gas utility. A gas utility filed an action concerning the above-market gas contract which is discussed in Note 6 Commitments and Contingencies. In September 1997, the Company acquired properties in Appalachia for a purchase price of $92.5 million. The Appalachia properties are located in certain of the Company's core operating areas and include 912 producing wells, 800 miles of gas gathering lines and leasehold acreage covering 153,000 gross acres (146,000 net acres). The acquired reserves were 80% developed and 95% operated on a pre-tax present value basis as of December 31, 1996. The properties have access to a number of major interstate pipelines and industrial end-users. In December 1997, the Company sold a net profits interest in the properties for $36.3 million. In December 1997, the Company completed the acquisition of certain oil properties located in the Fuhrman-Mascho field in west Texas (the "Fuhrman-Mascho Properties") for a purchase price of $40 million, with an economic effective date of October 1, 1997. Additionally, the Company recorded approximately $12 million of deferred income taxes in connection with the acquisition. The Fuhrman-Mascho Properties included 160 producing wells and leasehold acreage covering approximately 13,600 gross acres. On a Present Value basis, the acquired reserves were 40% developed and greater than 95% operated. In addition to the above mentioned acquisitions, the Company acquired other properties for an aggregate consideration of $26.1 million during the year ended December 31, 1997. UNAUDITED PRO FORMA FINANCIAL INFORMATION The following table presents unaudited pro forma operating results as if certain transactions had occurred at the beginning of each period presented. The pro forma operating results include the following transactions: (i) the purchase by the Company of the Cometra Properties and certain other properties, (ii) the conversion of the 7 1/2% Convertible Exchangeable Preferred Stock into Lomak Common Stock, (iii) the private placements of 600,000 shares of Lomak Common Stock and $55 million of 6% Convertible Subordinated Debentures and the application of the net proceeds therefrom, (iv) the sale of approximately 4 million shares of Common Stock and the application of the net proceeds therefrom, (v) the sale of $125 million of 8.75% Senior Subordinated Notes and the application of the net proceeds therefrom and (vi) the sale of $120 million of 5 3/4% Trust Convertible Preferred Securities and the application of the net proceeds therefrom. All acquisitions were accounted for as purchase transactions. 33 35 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDED DECEMBER 31, ------------------------ 1996 1997 ---------- ---------- (IN THOUSANDS EXCEPT PER SHARE DATA) Revenues............................................... $174,608 $159,441 Net income............................................. 22,109 (22,015) Earnings per share..................................... 0.99 (1.15) Earnings per share -- dilutive......................... 0.97 (1.15) Total assets........................................... 764,697 764,213 Stockholders' equity................................... 211,629 196,950
The pro forma operating results have been prepared for comparative purposes only. They do not purport to present actual operating results that would have been achieved had the acquisitions and financings been made at the beginning of each period presented or to necessarily be indicative of future results of operations. (4) INDEBTEDNESS The Company had the following debt outstanding as of the dates shown. Interest rates at December 31, 1997 are shown parenthetically (in thousands):
DECEMBER 31, ------------------- 1996 1997 ------- -------- Bank Facility (6.6%).................................... $61,355 $186,700 Other ( 5.9%)........................................... 451 425 ------- -------- 61,806 187,125 Less amounts due within one year........................ 26 413 ------- -------- Senior debt, net........................................ $61,780 $186,712 ======= ======== 8.75% Senior Subordinated Notes due 2007.............. $ -- $125,000 6% Convertible Subordinated Debentures due 2007....... 55,000 55,000 ------- -------- Subordinated debt, net.................................. $55,000 $180,000 ======= ========
The Company maintains a $400 million revolving bank facility (the "Bank Facility"). The Bank Facility provides for a borrowing base which is subject to semi-annual redeterminations. At December 31, 1997, the borrowing base on the Bank Facility was $325 million of which $138 million was available to be drawn. The Bank Facility bears interest at prime rate or LIBOR plus 0.625% to 1.125% depending upon the percentage of the borrowing base drawn. Interest is payable quarterly and the loan matures in February 2002. A commitment fee is paid quarterly on the undrawn balance at a rate of .25% to .375% depending upon the percentage of the borrowing base not drawn. It is the Company's policy to extend the term period of the Bank Facility annually. The weighted average interest rates on these borrowings were 6.7% and 7.3% for the years ended December 31, 1996 and 1997, respectively. The 8.75% Senior Subordinated Notes due 2007 (the "8.75% Notes") are not redeemable prior to January 15, 2002. Thereafter, the 8.75% Notes will be subject to redemption at the option of the Company, in whole or in part, at redemption prices beginning at 104.375% of the principal amount and declining to 100% in 2005. The 8.75% Notes are unsecured general obligations of the Company and are subordinated to all senior debt (as defined) of the Company which includes borrowings under the Bank Facility. The 8.75% Notes are guaranteed on a senior subordinated basis by all of the subsidiaries of the Company and each guarantor is a wholly owned subsidiary of the Company. The guarantees are full, unconditional and joint and several. Separate 34 36 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) financial statements of each guarantor are not presented because they are included in the consolidated financial statements of the Company and management has concluded that their disclosure provides no additional benefits. The 6% Convertible Subordinated Debentures Due 2007 (the "Debentures") are convertible into shares of the Company's Common Stock at the option of the holder at any time prior to maturity. The Debentures are convertible at a conversion price of $19.25 per share, subject to adjustment in certain events. Interest is payable semi-annually. The Debentures will mature in 2007 and are not redeemable prior to February 1, 2000. The Debentures are unsecured general obligations of the Company subordinated to all senior indebtedness (as defined) of the Company, which includes the 8.75% Notes and the Bank Facility. The debt agreements contain various covenants relating to net worth, working capital maintenance and financial ratio requirements. The Company is in compliance with these various covenants as of December 31, 1997. Interest paid during the years ended December 31, 1995, 1996 and 1997 totaled $4.9 million, $7.5 million and $18.2 million, respectively. Maturities of indebtedness as of December 31, 1997 were as follows (in thousands): 1998............................................. $ 413 1999............................................. 12 2000............................................. -- 2001............................................. -- 2002............................................. 186,700 Remainder........................................ 180,000 -------- $367,125 ========

(5) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES: The Company's financial instruments include cash and equivalents, accounts receivable, accounts payable, debt obligations, commodity and interest rate futures, options, and swaps. The book value of cash and equivalents, accounts receivable and payable and short term debt are considered to be representative of fair value because of the short maturity of these instruments. The Company believes that the carrying value of its borrowings under its bank credit facility approximates their fair value as they bear interest at rates indexed to LIBOR. The Company's accounts receivable are concentrated in the oil and gas industry. The Company does not view such a concentration as an unusual credit risk. The Company had recorded an allowance for doubtful accounts of $450,000 and $539,000 at December 31, 1996 and 1997, respectively. A portion of the Company's crude oil and natural gas sales are periodically hedged against price risks through the use of futures, option or swap contracts. The gains and losses on these instruments are included in the valuation of the production being hedged in the contract month and are included as an adjustment to oil and gas revenue. The Company also manages interest rate risk on its credit facility through the use of interest rate swap agreements. Gains and losses on interest rate swap agreements are included as an adjustment to interest expense. The following table sets forth the book value and estimated fair values of the Company's financial instruments: 35 37 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31, DECEMBER 31, 1996 1997 ---------------------- ---------------------- (IN THOUSANDS) BOOK FAIR BOOK FAIR VALUE VALUE VALUE VALUE --------- --------- --------- --------- Cash and equivalents................. $ 8,625 $ 8,625 $ 9,725 $ 9,725 Marketable securities................ 6,966 7,658 7,671 8,041 Long-term debt....................... (116,806) (116,806) (367,125) (367,125) Commodity swaps...................... -- (1,051) -- 1,071 Interest rate swaps.................. -- 81 -- 73
At December 31, 1997, the Company had open contracts for gas price swaps of 3.3 Bcf. The swap contracts are designed to set average prices ranging from $2.10 to $3.57 per Mcf. While these transactions have no carrying value, their fair value, represented by the estimated amount that would be required to terminate the contracts, was a net gain of approximately $1.1 million at December 31, 1997. These contracts expire monthly through March 1998. In addition, at December 31, 1997 the Company had settled several of the swap contracts for February 1998 and March 1998 that resulted in a deferred gain of $132,000 and $101,000 respectively. Lomak has no risk associated with these contracts. The gains or losses on the Company's hedging transactions are determined as the difference between the contract price and the reference price, generally closing prices on the New York Mercantile Exchange. The resulting transaction gains and losses are determined monthly and are included in net income in the period the hedged production or inventory is sold. Net gains or (losses) relating to these derivatives for the years ended December 31, 1995, 1996 and 1997 approximated $217,000, $(724,000) and $(882,000), respectively. Interest rate swap agreements, which are used by the Company in the management of interest rate exposure, are accounted for on the accrual basis. Income and expense resulting from these agreements are recorded in the same category as expense arising from the related liability. Amounts to be paid or received under interest rate swap agreements are recognized as an adjustment to expense in the periods in which they accrue. At December 31, 1997, the Company had $60 million of borrowings subject to three interest rate swap agreements at rates of 5.64%, 5.71% and 5.59% through October 1998, September 1999 and October 1999, respectively. The interest rate swaps may be extended at the counterparties' option for two years. The agreements require that the Company pay the counterparty interest at the above fixed swap rates and requires the counterparty to pay the Company interest at the 30-day LIBOR rate. The closing 30-day LIBOR rate on December 31, 1997 was 5.72%. The fair value of the interest rate swap agreements at December 31, 1997, is based upon current quotes for equivalent agreements. These hedging activities are conducted with major financial or commodities trading institutions which management believes entail acceptable levels of market and credit risks. At times such risks may be concentrated with certain counterparties or groups of counterparties. The credit worthiness of counterparties is subject to continuing review and full performance is anticipated. (6) COMMITMENTS AND CONTINGENCIES The Company is involved in various legal actions and claims arising in the ordinary course of business. In the opinion of management, such litigation and claims are likely to be resolved without material adverse effect on the Company's financial position. In April 1997, an action was filed by an individual in United States District Court in the Western District of Oklahoma seeking $550,000 in cash plus 100,000 shares of Red Eagle Resources Corporation Common Stock (approximately 87,000 shares of the Company's Common Stock). The individual claims he is entitled to fees from the Company based upon a Yemeni oil concession that he claims Red Eagle Resources Corporation received or had the opportunity to receive in 1992, which was prior to the acquisition of Red Eagle by the Company. 36 38 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Based upon the Company's examination of the available documentation relevant to such claim, the Company believes that the claim is without merit because the oil concession was never obtained and Red Eagle Resources Corporation did not have a duty to obtain a concession. The Company is vigorously defending this action, and as stated above, believes the action is without merit. A separate claim for approximately $2.0 million with respect to the alleged Yemeni oil concession was received in January 1997. Since that date, no further action has been taken and the Company believes the claim is without merit. In July 1997, a gas utility filed an action in the state district court in Tarrant County, Texas. In the lawsuit, the gas utility has asserted a breach of contract claim arising out of a gas purchase contract, in which it is buyer and the Company is seller. The gas utility seeks damages in the amount of approximately $2,000,000 as of January 1998, which amount the utility alleges will increase by the time of the trial. The Company has counterclaimed and seeks damages for breach of contract and for repudiation of the contract. The Company seeks past and future damages of approximately $17,000,000, which sum will also increase by the time of the trial. The Company is also seeking a declaratory judgment that under the contract, the gas utility has a minimum purchase obligation. The case is currently scheduled for a June 1, 1998 trial. Discovery is underway and cross motions for summary judgment on the contract issues are currently pending. The Company believes strongly in its interpretation of the contract and intends to prosecute the case vigorously, but is not in the position to predict with any level of certainty what the outcome of the trial will be. The Company leases certain office space and equipment under cancelable and non-cancelable leases, most of which expire within 10 years and may be renewed by the Company. Rent expense under such arrangements totaled $335,000, $406,000 and $628,000 in 1995, 1996 and 1997, respectively. Future minimum rental commitments under non-cancelable leases are as follows (in thousands): 1998............................................... $ 510 1999............................................... 417 2000............................................... 311 2001............................................... 267 2002............................................... 215 2003 and thereafter................................ 195 ------ $1,915 ======

(7) EQUITY SECURITIES AND CONVERTIBLE PREFERRED SECURITIES On October 16, 1997, Lomak, through a newly-formed affiliate Lomak Financing Trust (the "Trust"), completed the issuance of $120 million of 5 3/4% trust convertible preferred securities (the "Convertible Preferred Securities"). The Trust issued 2,400,000 shares of the Convertible Preferred Securities at $50 per share. Each Convertible Preferred Security is convertible at the holder's option into 2.1277 shares of Common Stock, representing a conversion price of $23.50 per share. The Trust invested the $120 million of proceeds in 5 3/4% convertible junior subordinated debentures issued by Lomak (the "Junior Debentures"). In turn, Lomak used the net proceeds from the issuance of the Junior Convertible Debentures to repay a portion of its credit facility. The sole assets of the Trust are the Junior Debentures. The Junior Debentures and the related Convertible Preferred Securities mature on November 1, 2027. Lomak and Lomak Financing Trust may redeem the Junior Debentures and the Convertible Preferred Securities, respectively, in whole or in part, on or after November 4, 2000. For the first twelve months thereafter, redemptions may be made at 104.025% of the principal amount. This premium declines proportionally every twelve months until November 1, 2007, when the redemption price becomes fixed at 100% of the principal amount. If Lomak redeems any Junior Debentures prior to the scheduled maturity date, the Trust must redeem Convertible Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Debentures so redeemed. 37 39 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Lomak has guaranteed the payments of distributions and other payments on the Convertible Preferred Securities only if and to the extent that the Trust has funds available. Such guarantee, when taken together with Lomak's obligations under the Junior Debentures and related indenture and declaration of trust, provide a full and unconditional guarantee of amounts due on the Convertible Preferred Securities. Lomak owns all the common securities of the Trust. As such, the accounts of the Trust have been included in Lomak's consolidated financial statements after appropriate eliminations of intercompany balances. The distributions on the Convertible Preferred Securities have been recorded as a charge to interest expense on Lomak's consolidated statements of income, and such distributions are deductible by Lomak for income tax purposes. In March 1997, the Company sold 4 million shares of common stock in a public offering for $69 million. Warrants to acquire 20,000 shares of common stock at a price of $12.88 per share were exercised in May 1997. At December 31, 1997 the Company had no outstanding warrants. In November 1995, the Company issued 1,150,000 shares of $2.03 convertible exchangeable preferred stock (the "$2.03 Preferred Stock") for $28.8 million. The $2.03 Preferred Stock is convertible into the Company's common stock at a conversion price of $9.50 per share, subject to adjustment in certain events. The $2.03 Preferred Stock is redeemable, at the option of the Company, at any time on or after November 1, 1998, at redemption prices beginning at 105%. At the option of the Company, the $2.03 Preferred Stock is exchangeable for the Company's 8 1/8% Convertible Subordinated Notes due 2005. The notes would be subject to the same redemption and conversion terms as the $2.03 Preferred Stock. In 1993, $5,000,000 of 7 1/2% cumulative convertible exchangeable preferred stock (the "7 1/2% Preferred Stock") was privately placed. In 1996, the Company exercised its option and converted the 7 1/2% Preferred stock into 576,945 shares of Common Stock. (8) STOCK OPTION AND PURCHASE PLAN The Company maintains a Stock Option Plan which authorizes the grant of options of up to 3 million shares of Common Stock. However, no new options may be granted which would result in their being outstanding aggregate options exceeding 10% of the Company's common shares outstanding plus those shares issuable under convertible securities. Under the plan, incentive and non-qualified options may be issued to officers, key employees and consultants. The plan is administered by the Compensation Committee of the Board. All options issued under the plan vest 30% after one year, 60% after two years and 100% after three years. The following is a summary of stock option activity:
NUMBER OF OPTIONS EXERCISE --------------------------------- PRICE RANGE 1995 1996 1997 PER SHARE ------- --------- --------- ------------ Outstanding at beginning of year............. 680,483 977,149 1,232,449 $3.38-$13.88 Granted...................................... 342,000 378,500 501,750 16.88-18.00 Canceled..................................... (12,000) (7,950) (19,490) 7.00-17.50 Exercised.................................... (33,334) (115,250) (107,017) 5.12-10.50 ------- --------- --------- ------------ Outstanding at end of year................... 977,149 1,232,449 1,607,692 $3.38-$18.00 ======= ========= ========= ============
In 1994, the stockholders approved the 1994 Outside Directors Stock Option Plan (the "Directors Plan"). Only Directors who are not employees of the Company are eligible under the Directors Plan. The Directors Plan covers a maximum of 200,000 shares. At December 31, 1997, 108,000 options were outstanding under the Directors Plan of which 40,800 were exercisable as of that date. The exercise price of the options ranges from $7.75 to $16.88 per share. 38 40 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In June 1997, the stockholders approved the 1997 Stock Purchase Plan (the "1997 Plan") which authorizes the sale of up to 500,000 shares of common stock to officers, directors, key employees and consultants. Under the Plan, the right to purchase shares at prices ranging from 50% to 85% of market value may be granted. The Company previously had stock purchase plans which covered 833,333 shares. The previous stock purchase plans have been terminated. The plans are administered by the Compensation Committee of the Board. During the year ended December 31, 1997, officers, key employees and outside directors purchased 113,400 unregistered common shares from the Company for total consideration of $1.4 million. From inception through December 31, 1997, a total of 453,000 unregistered shares had been sold through stock purchase plans, for a total consideration of approximately $3.7 million. The Company has adopted the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock Based Compensation." Accordingly, no compensation cost has been recognized for the stock option plans. Had compensation cost for the Corporation's two stock option plans been determined based on the fair value at the grant date for awards in 1996 and 1997 consistent with the provisions of SFAS No. 123, the Company's net earnings and earnings per share would have been reduced to the pro forma amounts indicated below:
1995 1996 1997 ------ ------- -------- (IN THOUSANDS, EXCEPT PER SHARE DATA) Net earnings (loss) -- as reported.......................... $4,390 $12,615 $(23,332) Earnings (loss) per share -- as reported.................... $ 0.31 $ 0.71 $ (1.31) Earnings (loss) per share dilutive -- as reported........... $ 0.31 $ 0.69 $ (1.31) Net earnings (loss) -- pro forma............................ $4,266 $12,262 $(24,563) Earnings (loss) per share -- pro forma...................... $ 0.30 $ 0.68 $ (1.37) Earnings (loss) per share dilutive -- pro forma............. $ 0.30 $ 0.66 $ (1.37)
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions used for 1995, 1996 and 1997, respectively: dividend yields of $.01, $.06 and $.10 per share; expected volatility factors of .37, .41 and .46; risk-free interest rates of 6.9%, 6.0% and 6.5%; and a weighted average expected life of 3 years. (9) BENEFIT PLAN The Company maintains a 401(K) Plan for the benefit of its employees. The Plan permits employees to make contributions on a pre-tax salary reduction basis. The Company makes discretionary contributions to the Plan. Company contributions for 1995, 1996 and 1997 were $346,000, $548,000 and $701,000 respectively. The 1997 contribution was made with Lomak common stock, which was valued at fair market value on the issuance date. The Company has no other employee benefit plans. (10) INCOME TAXES Federal income tax provision (benefit) was $1.8 million, $6.8 million and $(11.8) million for the years 1995, 1996 and 1997, respectively. The current portion of the income tax provision represents state income tax currently payable. A reconciliation between the statutory federal income tax rate and the Company's effective federal income tax rate is as follows: 39 41 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1995 1996 1997 ------- -------- ---------- Statutory tax rate...................................... 34% 34% (34)% Realization of valuation allowance...................... (5) -- -- Other................................................... -- 1 -- ------- -------- ---------- Effective tax rate...................................... 29% 35% (34)% ======= ======== ========== Income taxes paid....................................... $60,000 $590,000 $1,216,000 ======= ======== ==========
The Company follows FASB Statement No. 109, "Accounting for Income Taxes". Under Statement 109, the liability method is used in accounting for income taxes. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Significant components of the Company's deferred tax liabilities and assets are as follows (in thousands):
DECEMBER 31, ------------------ 1996 1997 ------- ------- Deferred tax liabilities: Depreciation....................................... $31,726 $38,305 ======= ======= Deferred tax assets: Net operating loss carryforward.................... 2,625 9,268 Percentage depletion carryforward.................. 2,589 2,753 AMT credits and other.............................. 621 685 ------- ------- Total deferred tax assets.......................... 5,835 12,706 Valuation allowance for deferred tax assets........ (40) (40) ------- ------- Net deferred tax assets.............................. $ 5,795 $12,666 ======= ======= Net deferred tax liabilities......................... $25,931 $25,639 ======= =======
In 1995, income taxes were reduced from the statutory rate of 34% by approximately $0.3 million through realization of a portion of the valuation allowance, resulting in $40,000 of the allowance remaining at each of December 31, 1996 and 1997. The Company has entered into several business combinations accounted for as purchases. In connection with these transactions, deferred tax assets and liabilities of $7.7 million and $23.8 million respectively, were recorded. In 1996 the Company acquired Eastern Petroleum Company in a taxable business combination accounted for as a purchase. A net deferred tax liability of $2.1 million was recorded in the transaction. In 1997 the Company acquired Arrow Operating Company accounted for as a tax free business combination accounted for as a purchase. A net deferred tax liability of $12.4 million was recorded in the transaction. As a result of the Company's issuance of equity and convertible debt securities, it experienced a change in control during 1988 as defined by Section 382 of the Internal Revenue Code. The change in control placed limitations to the utilization of net operating loss carryovers. At December 31, 1997, the Company had available for federal income tax reporting purposes net operating loss carryovers of approximately $26 million which are subject to annual limitations as to their utilization and otherwise expire between 1998 and 2012, if unused. The Company has alternative minimum tax net operating loss carryovers of $21 million which are subject to annual limitations as to their utilization and otherwise expire from 1998 to 2012 if unused. The Company has statutory depletion carryover of approximately $3.8 million and an alternative minimum tax credit carryover of approximately $800,000. The statutory depletion carryover and alternative minimum tax credit carryover are not subject to limitation or expiration. 40 42 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (11) EARNINGS PER COMMON SHARE The following table sets forth the computation of earnings per common share and earnings per common share -- assuming dilution (in thousands):
1995 1996 1997 ------- ------- -------- Numerator: Net Income................................................ $ 4,390 $12,615 $(23,332) Preferred stock dividends................................. (731) (2,454) (2,334) ------- ------- -------- Numerator for earnings per common share................... 3,659 10,161 (25,666) Effect of dilutive securities: Preferred stock dividends.............................. -- -- -- ------- ------- -------- Numerator for earnings per common share -- assuming dilution............................................. $ 3,659 $10,161 $(25,666) ======= ======= ======== Denominator: Denominator for earnings per common share -- weighted average shares 11,673 14,334 19,641 Effect of dilutive securities: Employee stock options................................. 164 464 -- Warrants............................................... 4 14 -- ------- ------- -------- Dilutive potential common shares.......................... 168 478 -- ------- ------- -------- Denominator for diluted earnings per share adjusted weighted-average shares and assumed conversions...... 11,841 14,812 19,641 ======= ======= ======== Earnings per common share................................... $ .31 $ .71 $ (1.31) ======= ======= ======== Earnings per common share -- assuming dilution.............. $ .31 $ .69 $ (1.31) ======= ======= ========
For additional disclosure regarding the Company's Debentures, the 7 1/2% Preferred Stock and the $2.03 Preferred Stock, see Notes 4, 7 and 8 respectively. The Debentures were outstanding during 1996 and 1997 but were not included in the computation of diluted earnings per share because the conversion price was greater than the average market price of common shares and, therefore, the effect would be antidilutive. The 7 1/2% Preferred Stock was outstanding during 1995 and convertible into additional shares of common stock during 1996. The 576,945 additional shares were not included in the computation of diluted earnings per share because the effect was antidilutive. The $2.03 Preferred Stock was outstanding during 1996 and 1997 and was convertible into 3,026,316 of additional shares of common stock. The 3,026,316 additional shares were not included in the computation of diluted earnings per share because the conversion price was greater than the average market price of common shares and, therefore, the effect would be antidilutive. There were employee stock options outstanding during 1997 which were exercisable, resulting in 642,720 additional shares under the treasury method of accounting for common stock equivalents. These additional shares were not included in the 1997 computation of diluted earnings per share because the effect was antidilutive. (12) MAJOR CUSTOMERS The Company markets its oil and gas production on a competitive basis. The type of contract under which gas production is sold varies but can generally be grouped into three categories: (a) life-of-the-well; (b) long-term (1 year or longer); and (c) short-term contracts which may have a primary term of one year, but which are cancelable at either party's discretion in 30-120 days. Approximately 54% of the Company's gas production is currently sold under market sensitive contracts which do not contain floor price provisions. For the year ended December 31, 1997, one customer accounted for 13% of the Company's total oil and gas revenues. Management believes that the loss of any one customer would not have a material adverse effect on the operations of the Company. Oil is sold on a basis such that the purchaser can be changed on 30 days notice. The price received is 41 43 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) generally equal to a posted price set by the major purchasers in the area. The Company sells to oil purchasers on a basis of price and service. (13) OIL AND GAS ACTIVITIES The following summarizes selected information with respect to oil and gas producing activities:
YEAR ENDED DECEMBER 31, ------------------------------- 1995 1996 1997 -------- -------- --------- (IN THOUSANDS) Oil and gas properties: Subject to depletion...................................... $197,826 $259,681 $ 679,447 Not subject to depletion.................................. 12,247 22,838 111,156 -------- -------- --------- Total.................................................. 210,073 282,519 790,603 Accumulated depletion..................................... (33,371) (53,102) (161,416) -------- -------- --------- Net oil and gas properties............................. $176,702 $229,417 $ 629,187 ======== ======== ========= Costs incurred: Acquisition............................................... $ 69,244 $ 63,579 $ 448,822 Development............................................... 9,968 12,536 56,430 Exploration............................................... 216 2,025 2,375 -------- -------- --------- Total costs incurred................................... $ 79,428 $ 78,140 $ 507,627 ======== ======== =========
The acquisition costs incurred for 1997 include $282.5 million for proved reserves, $115.7 million for unproved reserves and $50.6 million for an above market gas contract and deferred income taxes. The unproved reserve amounts are primarily attributable to the acquisition of the Cometra Properties. (14) UNAUDITED SUPPLEMENTAL RESERVE INFORMATION The Company's proved oil and gas reserves are located in the United States. Proved reserves are those quantities of crude oil and natural gas which, upon analysis of geological and engineering data, can with reasonable certainty be recovered in the future from known oil and gas reservoirs. Proved developed reserves are those proved reserves which can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage. 42 44 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) QUANTITIES OF PROVED RESERVES
CRUDE OIL NATURAL GAS --------- ----------- ~~(BBLS) (MCF)~~ (IN THOUSANDS) Balance, December 31, 1994.................................. 8,449 149,370 Revisions................................................. 255 (3,513) Extensions, discoveries and additions..................... 475 10,076 Purchases................................................. 2,618 90,575 Sales..................................................... (21) (1,150) Production................................................ (913) (12,471) --------- ----------- Balance, December 31, 1995.................................. 10,863 232,887 Revisions................................................. 280 (7,545) Extensions, discoveries and additions..................... 952 16,696 Purchases................................................. 3,884 86,022 Sales..................................................... (236) (11,235) Production................................................ (1,068) (21,231) --------- ----------- Balance, December 31, 1996.................................. 14,675 295,594 Revisions................................................. (2,603) (70,763) Extensions, discoveries and additions..................... 1,664 55,324 Purchases................................................. 18,541 339,447 Sales..................................................... (709) (6,775) Production................................................ (1,794) (38,409) --------- ----------- Balance, December 31, 1997.................................. 29,774 574,418 ========= =========== PROVED DEVELOPED RESERVES December 31, 1995........................................... 8,880 174,958 ========= =========== December 31, 1996........................................... 10,703 207,601 ========= =========== December 31, 1997........................................... 14,971 369,786 ========= ===========
The revisions which occurred during 1997 include 1,819 Mbbl of oil and 29,662 Mmcf of gas which became uneconomic due to lower commodity prices at December 31, 1997 as compared to December 31, 1996. The commodity prices used to estimate the December 31, 1997 reserve information were $16.00 per barrel for oil, $10.27 per barrel for natural gas liquids and $2.79 per Mcf for gas. The average prices at December 31, 1996 were $25.37 per barrel for oil, $11.03 per barrel for natural gas liquids and $3.54 per Mcf for gas. The "Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves" (Standardized Measure) is a disclosure requirement under Statement of Financial Accounting Standards No. 69 "Disclosures about Oil and Gas Producing Activities". The Standardized Measure does not purport to present the fair market value of proved oil and gas reserves. This would require consideration of expected future economic and operating conditions, which are not taken into account in calculating the Standardized Measure. Future cash inflows were estimated by applying year end prices to the estimated future production less estimated future production costs based on year end costs. Future net cash inflows were discounted using a 10% annual discount rate to arrive at the Standardized Measure. 43 45 LOMAK PETROLEUM, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) STANDARDIZED MEASURE
AS OF DECEMBER 31 ------------------------------------ 1995 1996 1997 -------- ----------- ----------- (IN THOUSANDS) Future cash inflows..................................... $729,566 $ 1,393,338 $ 2,037,357 Future costs: Production............................................ (256,374) (365,753) (512,657) Development........................................... (60,554) (86,192) (248,553) -------- ----------- ----------- Future net cash flows................................... 412,638 941,393 1,276,147 Income taxes............................................ (102,108) (271,023) (280,189) -------- ----------- ----------- Total undiscounted future net cash flows................ 310,530 670,370 995,958 10% discount factor..................................... (136,480) (319,481) (485,258) -------- ----------- ----------- Standardized measure.................................... $174,050 $ 350,889 $ 510,700 ======== =========== ===========
CHANGES IN STANDARDIZED MEASURE
FOR THE YEAR ENDED DECEMBER 31 -------------------------------- 1995 1996 1997 -------- --------- --------- (IN THOUSANDS) Standardized measure, beginning of year.................... $119,549 $ 174,050 $ 350,889 Revisions: Prices................................................... (4,100) 151,508 (210,429) Quantities............................................... 2,267 (6,762) (29,409) Estimated future development cost........................ (5,238) (2,971) (37,788) Accretion of discount.................................... 15,054 22,924 49,217 Income taxes............................................. (24,200) (86,095) 10,360 -------- --------- --------- Net revisions............................................ (16,217) 78,604 (218,049) Purchases.................................................. 87,741 125,871 460,753 Extensions, discoveries and additions...................... 7,419 22,816 55,751 Production................................................. (22,487) (43,598) (93,865) Sales...................................................... (1,955) (6,854) (14,406) Changes in timing and other................................ -- -- (30,373) -------- --------- --------- Standardized measure, end of year.......................... $174,050 $ 350,889 $ 510,700 ======== ========= =========
44 46 LOMAK PETROLEUM, INC. INDEX TO EXHIBITS (Item 14[a 3])
EXHIBIT NO. DESCRIPTION - ----------- ----------- 3.1(a) Certificate of Incorporation of Lomak dated March 24, 1980 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 3.1(b) Certificate of Amendment of Certificate of Incorporation dated July 22, 1981 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 3.1(c) Certificate of Amendment of Certificate of Incorporation dated September 8, 1982 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 3.1(d) Certificate of Amendment of Certificate of Incorporation dated December 28, 1988 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 3.1(e) Certificate of Amendment of Certificate of Incorporation dated August 31, 1989 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 3.1(f) Certificate of Amendment of Certificate of Incorporation dated May 30, 1991 (incorporated by reference to the Company's Registration Statement (No. 333-20259)). 3.1(g) Certificate of Amendment of Certificate of Incorporation dated November 20, 1992 (incorporated by reference to the Company's Registration Statement (No. 333-20257)). 3.1(h) Certificate of Amendment of Certificate of Incorporation dated May 24, 1996 (incorporated by reference to the Company's Registration Statement (No. 333-20257)). 3.1(i) Certificate of Amendment of Certificate of Incorporation dated October 2, 1996 (incorporated by reference to the Company's Registration Statement (No. 333-20257)). 3.1(j) Restated Certificate of Incorporation as required by Item 102 of Regulation S-T (incorporated by reference to the Company's Registration Statement (No. 333-20257)). 3.2 By-Laws of the Company (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 4 Specimen certificate of Lomak Petroleum, Inc. Common Stock (incorporated by reference to the Company's registration statement (No. 333-20257)). 4.4 Certificate of Trust of Lomak Financing Trust (incorporated by reference to the Company's Registration Statement (No. 333-43823)). 4.5 Amended and Restated Declaration of Trust of Lomak Financing Trust dated as of October 22, 1997 by The Bank of New York (Delaware) and the Bank of New York as Trustees and Lomak Petroleum, Inc. as Sponsor (incorporated by reference to the Company's Registration Statement (No. 333-43823)). 4.6 Indenture dated as of October 22, 1997, between Lomak Petroleum, Inc. and The Bank of New York (incorporated by reference to the Company's Registration Statement (No. 333-43823)). 4.7 First Supplemental Indenture dated as of October 22, 1997, between Lomak Petroleum, Inc. and The Bank of New York (incorporated by reference to the Company's Registration Statement (No. 333-43823)). 4.8 Form of 5 3/4% Preferred Convertible Securities (included in Exhibit 4.5 above). 4.9 Form of 5 3/4% Convertible Junior Subordinated Debentures (included in Exhibit 4.7 above). 4.10 Convertible Preferred Securities Guarantee Agreement dated October 22, 1997, between Lomak Petroleum, Inc., as Guarantor, and The Bank of New York as Preferred Guarantee Trustee (incorporated by reference to the Company's Registration Statement (No. 333-43823)).
45 47 LOMAK PETROLEUM, INC. INDEX TO EXHIBITS -- (CONTINUED)
EXHIBIT NO. DESCRIPTION - ----------- ----------- 4.11 Common Securities Guarantee Agreement dated October 22, 1997, between Lomak Petroleum, Inc., as Guarantor, and The Bank of New York as Common Guarantee Trustee.(incorporated by reference to the Company's Registration Statement No. 333-43823)). 4.12 Purchase and Sale Agreement between Cometra Energy, L.P. and Cometra Production Company, L.P., as seller, and Lomak Petroleum, Inc., as buyer, dated December 31, 1996, including First Amendment to Purchase and Sale Agreement, dated January 10, 1997 (incorporated by reference to the Company's Registration Statement (No. 333-20257)). 4.13 Purchase and Sale Agreement between Rockland, L.P., as seller, and Lomak Petroleum, Inc., as buyer, dated December 31, 1996 (incorporated by reference on the Company's Registration Statement (No. 333-20257)). 4.14 Form of Trust Indenture relating to the Senior Subordinated Notes due 2007 between Lomak Petroleum, Inc., and Fleet National Bank as trustee (incorporated on the Company's Registration Statement (No. 333-20257)). 4.15* Purchase and Sale Agreement dated as of September 8, 1997 by and among Cabot Oil & Gas Corporation, Cranberry Pipeline Corporation, Big Sandy Gas Company, and Lomak Petroleum, Inc. 4.16 Agreement and Plan of Reorganization dated December 5, 1997 between Arrow Operating Company, Kelly W. Hoffman and L. S. Decker and Lomak Petroleum, Inc. (incorporated by reference to the Company's Registration Statement (No. 333-43823)). 10.1(a) Incentive and Non-Qualified Stock Option Plan dated March 13, 1989 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 10.1(b) Advisory Agreement dated September 29, 1988 between Lomak and SOCO (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 10.1(c) 401(k) Plan Document and Trust Agreement effective January 1, 1989 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 10.1(d) 1989 Stock Purchase Plan (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 10.1(e) Form of Directors Indemnification Agreement (incorporated by reference to the Company's Registration Statement (No. 333-47544)). 10.1(f) 1994 Outside Directors Stock Option Plan (incorporated by reference to the Company's Registration Statement (No. 33-47544)). 10.1(g) 1994 Stock Option Plan (incorporated by reference to the Company's Registration Statement (No. 33-47544)). 10.1(h) $400,000,000 Credit Agreement Among Lomak Petroleum, Inc., as Borrower, and the Several Lenders from Time to Time parties Hereto, including Bank One, Texas, N.A. as Administrative Agent, The Chase Manhattan Bank, as Syndication Agent, and Nationsbank of Texas, N.A., as Documentation Agent. 10.1(i) Registration Rights Agreement dated October 22, 1997, by and among Lomak Petroleum, Inc., Lomak Financing Trust, Morgan Stanley & Co. Incorporated, Credit Suisse First Boston, Forum Capital markets L.P. and McDonald Company Securities, Inc., (incorporated by reference to the Company's Registration Statement (No. 333-43823)). 10.1(j) Amendment to the Lomak Petroleum, Inc., 1989 Stock Purchase Plan, as amended (incorporated by reference to the Company's Registration Statement (No. 333-44821)). 10.1(k) 1997 Stock Purchase Plan (incorporated by reference to the Company's Registration Statement (No. 333-44821)).
46 48 LOMAK PETROLEUM, INC. INDEX TO EXHIBITS -- (CONTINUED)
EXHIBIT NO. DESCRIPTION - ----------- ----------- 10.1(l)* 1997 Stock Purchase Plan, as amended (incorporated by reference to the Company's Registration Statement (No. 333-44821)). 22 * Subsidiaries of the Registrant. 23.1* Consent of Independent Public Accountants. 27 * Financial Data Schedule.
- --------------- * Filed herewith. 47

1 EXHIBIT 4.15 PURCHASE AND SALE AGREEMENT This PURCHASE AND SALE AGREEMENT (this "Agreement") dated as of September 8, 1997 by and among CABOT OIL & GAS CORPORATION, a Delaware Corporation, CRANBERRY PIPELINE CORPORATION, a Delaware Corporation and BIG SANDY GAS COMPANY, a Delaware Corporation (hereinafter jointly referred to as "Seller") and LOMAK PETROLEUM, INC., a Delaware Corporation, (hereinafter referred to as "Purchaser"). W I T N E S S E T H: WHEREAS, Seller desires to sell to Purchaser certain producing oil and gas leasehold assets and related equipment and to transfer the liabilities and obligations relating to and corresponding with such assets and equipment, and Purchaser desires to acquire from Seller such producing oil and gas leasehold assets and related equipment and will accept and assume the related and corresponding liabilities and obligations under the terms and conditions herein set forth. NOW, THEREFORE, in consideration of the premises and of the respective representations, warranties, covenants, agreements, assumptions of liabilities and obligations, and conditions contained herein, the parties hereto hereby agree as follows: ARTICLE I Definitions As used in this Agreement, terms shall have the following respective meanings: Adjustment Estimate: As defined in Section 2.05(A). Affiliate: Any Person that, directly or indirectly, or through one or more intermediaries, controls, is controlled by or is under common control with a party to this Agreement. Agreed Interest Rate: Seven percent (7%) per year. Assets: As defined in Section 2.01. Books and Records: Seller's existing leasehold files, land files, mineral rights files (where applicable), field equipment files, oil and gas interest files, contract files, rights of way files, abstracts (if any), well files, title opinions, curative information, land maps, electric logs, prospect maps, engineering research files and records, core data, digital well records, digital maps, geologic maps, production balancing agreements, and accounts directly (and only) related to the Assets including any and all electronic data files related thereto. Closing: The closing of the purchase and sale transaction contemplated by this Agreement. Closing Date: The date of the Closing. Deductible Amount: An amount equal to ONE MILLION FIVE HUNDRED THOUSAND AND NO/100 DOLLARS ($1,500,000.00). Designated Title Defects: As defined in Section 7.04. Effective Time: As defined in Section 2.01. 2 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 2 Encumbrances: Any mortgage, lien, security interest, pledge, charge, encumbrance, claim, limitation, irregularity, burden or defect. Environmental Condition: Any existing condition to the soil, subsurface, surface waters, groundwaters, atmosphere or other environmental medium, whether or not yet discovered, which could result in any damage, loss, cost, expense, claim, demand, investigation, lien or liability relating to the Assets under any Environmental Statute. Environmental Deductible Amount: An amount equal to ONE MILLION AND NO/100 DOLLARS ($1,000,000.00). Environmental Statute: The Resource Conservation and Recovery Act of 1976, as amended prior to the Closing Date, 42 U.S.C. Sections 6901 et seq. ("RCRA"), the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 as amended prior to the Closing Date, 42 U.S.C. Sections 9601 et seq. ("CERCLA"), and all regulations issued thereunder prior to the Closing Date, and all other Legal Requirements relating to air or water quality, hazardous or solid wastes, hazardous substances or any other environmental matters. Final Settlement Statement: As defined in Section 2.05(B). Gas Balancing Arrangement: Any circumstance pursuant to which a Person (including Seller) that owns an interest in the Leaseholds or Mineral Properties or any unit or joint operating agreement in which the Leaseholds or Mineral Properties are included or any pipeline purchaser has taken or received, or failed to have received, any amount of Hydrocarbons under any gas balancing agreements, Oil and Gas Contracts, or under any other circumstances, including any rights at law or in equity, that permit any other Person later to "balance" (whether in kind, in cash or otherwise) by taking for the account of such other person or pipeline purchaser any disproportionate allocation of Hydrocarbons or their sale proceeds. Hancock Letter Agreement: As defined in Section 13.02(I). Hancock Properties: As defined in Section 13.02(I). Hydrocarbons: Crude oil, natural gas, natural gas liquids and other gaseous and liquid hydrocarbons or any combination thereof. Lease Burdens: All royalty interests, overriding royalty interests, production payments, net profits interests or other similar interests that constitute a burden on, are measured by or are payable out of the production of, Hydrocarbons or the proceeds realized from the sale or other disposition thereof. Leaseholds: As defined in Section 2.01. Legal Requirements: Any law, statute, ordinance, decree, requirement, order, judgment, rule or regulation of, including the terms of any license, permit, certificate, or abandonment approval issued by, any governmental authority in existence prior to, at the time of, or after the Closing Date. Like-Kind Exchange: As defined in Section 11.04. Mineral Properties: As defined in Section 2.01. Net Revenue Interest: An interest (expressed as a percentage) in and to Hydrocarbons produced and saved from or allocated to a Leasehold after deducting all applicable Lease Burdens. 3 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 3 Oil and Gas Contracts: Any contracts that affect or relate to the Leaseholds or the Hydrocarbons covered thereby including amendments to and claims under oil and gas contracts. "Oil and Gas Contracts" includes acreage contribution agreements, advance payment agreements, bottom hole agreements, division orders, drilling contracts, dry hole agreements, exploration agreements, farmin and farmout agreements, gas balancing agreements (including claims to recover natural gas or money under gas balancing agreements for Seller's underproduction before the Effective Time), natural gas and oil sales, exchange, treating and processing contracts, operating agreements, participation agreements, storage agreements, support agreements, transfer orders, transportation agreements, and water rights agreements. Operating Agreements: Joint operating agreements covering the Assets or joint operating agreements to which the Assets are subject. Option Agreement: As defined in Section 13.02(J). Option Purchase Price: As defined in Section 13.02(J). Overriding Royalty Interest: An interest in oil, gas and other minerals produced at the surface, free of the expense of production (but not transportation or marketing) and in addition to the usual landowner's royalty reserved to the lessor in an oil and gas lease. Performance Deposit: As defined in Section 2.03. Permitted Encumbrances: Those encumbrances described in the Assignment, Bill of Sale, and Conveyance attached as Exhibit "B" to this Agreement and the following items, (i) Encumbrances that arise under Oil and Gas Contracts of a type and nature customary in the oil and gas industry to secure the payment of amounts that are not yet delinquent or, if delinquent, are being contested in good faith in the ordinary course of business; (ii) Encumbrances that arise as a result of pooling and unitization agreements, declarations, farmouts/farmins, pooling designations, orders or laws; (iii) Encumbrances securing payments to mechanics and materialmen, and Encumbrances securing payment of taxes or assessments that are, in either case, not yet delinquent or, if delinquent, are being contested in good faith in the normal course of business; (iv) consents to assignment by governmental authorities (a) that have been obtained on or prior to the Closing Date or (b) that are customarily obtained after the delivery of the conveyance of the nature contemplated by this Agreement; (v) conventional rights of reassignment obligating Seller to reassign its interest in any portion of the Assets to a third party in the event it intends to release or abandon such interest prior to the expiration of the primary term or other termination of such interest; (vi) easements, rights of way, servitudes, permits, surface leases, surface use restrictions and other surface uses and impediments, on, over or in respect to any of the Assets that are not such as to interfere materially with the operation, value or use of the Assets, taken as a whole; 4 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 4 (vii) such Title Defects as Purchaser expressly waives in writing or which are waived by Closing or operation of Section 7.04; (viii) rights reserved to or vested in any governmental authority to control or regulate any of the Assets in any manner, and all applicable Legal Requirements; (ix) matters described in any schedule to this Agreement; and (x) any Encumbrance the enforcement of which is barred under applicable statute of limitations. Person: An individual, group, partnership, corporation, trust or other entity. Pipeline: As defined in Section 2.01 Purchase Price: As defined in Section 2.03. Purchaser: As defined in the preamble to this Agreement. Purchaser Indemnified Loss: Any loss, damage or expense (including reasonable attorneys' fees, expert witness fees and court costs) sustained by Purchaser arising out of or resulting from any inaccuracy in or breach of any of the representations, warranties or covenants made by Seller in this Agreement; provided "Purchaser Indemnified Loss" shall not refer to or include any remedy under Article VII. Seller: As defined in the preamble to this Agreement. Seller Employees: As defined in Section 12.01. Seller Indemnified Loss: Any loss, damage or expense (including reasonable attorneys' fees, expert witness fees and court costs) sustained by Seller arising out of or resulting from (i) any inaccuracy in or breach of any of the representations, warranties or covenants made by Purchaser in this Agreement or (ii) the payment or other disposition of the amounts paid to Purchaser under Section 3.02(D). Seller's Knowledge: The actual knowledge of the managerial employees of Seller in charge of the particular matter or function at the level of District Superintendent or above within Seller's organization. Tax Credit Properties: As defined in Section 13.02 (J). Tax Credit Properties Letter Agreement: As defined in Section 13.02 (J). Tax Credit Properties Purchase Price: As defined in Section 13.02 (J). Title Defect: Any Encumbrance, other than a Permitted Encumbrance, that would (a) cause Seller to own less than the Net Revenue Interest in a Leasehold shown on Exhibit "A" to the Agreement or (b) obligates Seller to pay and bear a share of the costs and risks of exploring, developing and operating a Leasehold greater than the Working Interest shown on Exhibit "A" to the Agreement. Title Defect Amount: As defined in Section 7.04. Title Defect Deductible Amount: An amount equal to TWO MILLION AND NO/100 DOLLARS ($2,000,000.00) 5 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 5 Unit Agreements: Pooling and/or unit agreements covering the Assets to which the Assets are subject. Working Interest: The interest in the full and entire leasehold estate created by virtue of the Leaseholds and all rights and obligations of every kind and character appurtenant thereto, or arising therefrom. ARTICLE II Purchase and Sale 2.01. Conveyance and Transfer of Assets. Seller and Purchaser, intending to be bound by this Agreement, hereby agree that, at Closing, subject to the terms and conditions of this Agreement, Seller shall convey, transfer, assign and deliver, "as is" and "where is", the right, title and interest of Seller in the wells on the lands covered by the leaseholds described in Exhibit "A", including all of Seller's right, title and interest in (i) the oil and gas, and oil, gas, and mineral leases, described in Exhibit "A" hereto ("Leaseholds"); and (ii) the oil and gas, and oil, gas, and mineral fee estates created by the mineral deeds described in Exhibit "A" ("Mineral Properties") EXCEPTING AND RESERVING, however, to Seller fifty percent (50%) of all oil and gas and oil, gas, and mineral rights and interests in, under, and created by said leases and mineral deeds in and to all depths below the top of the Queenston Formation, such reserved rights and interests being proportionately reduced in the event Seller owns less than the entire interest in and to such leases and mineral fee estates, with and subject to any Unit Agreements and Seller's rights and obligations under the Operating Agreements, and further subject to any other depth limitations shown on Exhibit "A"; and (iii) any easements, surface rights of way or fee interests created by the Leaseholds and Mineral Properties and by the grants identified in Exhibit "A", including any and all of Seller's rights of ingress and egress EXCEPTING AND RESERVING, however, to Seller joint and concurrent ownership and usage of the easements, surface rights of way or fee interests for access to the Leaseholds and Mineral Properties and (iv) any and all gas gathering and transmission pipelines in, on, or otherwise relating to the Leaseholds and Mineral Properties, inclusive of, but not limited to, that certain portion of the gas gathering and transmission pipeline system known as the Cranberry Pipeline INSOFAR AND ONLY INSOFAR as that portion of said pipeline system situated in Crawford, Mercer, and Venango Counties, Pennsylvania ("Pipeline") and (v) wells, tankage, fixtures, treating facilities, pumping equipment, flow lines, any Seller owned field compressor facilities, together with any real and personal property interests appurtenant or related to or used in connection with the Leaseholds and Mineral Properties, and the Books and Records exclusively relating thereto; (all of which Leaseholds, Mineral Properties, Pipeline and other property or rights are referred to as "Assets" under this Agreement) effective as of 7:00 a.m., Eastern Standard Time on September 1, 1997 ("Effective Time"). All such Assets are described in Exhibit "A" to this Agreement. 2.02 Assumption of Liabilities. Subject to the terms and conditions of this Agreement and in reliance upon the representations and warranties contained herein, at the Closing Seller shall convey, transfer, assign and deliver "as is" and "where is" all of Seller's right, title and interest in the Assets (on the form of Assignment, Bill of Sale and Conveyance prescribed in Exhibit "B" with a description of the Assets attached thereto) to Purchaser; and as of the Effective Time Purchaser assumes all of the liabilities and obligations of Seller pertaining to the Assets, as evidenced by executing and delivering with Seller the Assignment, Bill of Sale and Conveyance. Purchaser's assumption of the liabilities and obligations of Seller shall not include payment of unpaid costs or expenses attributable to Seller's operation of the Assets prior to the Effective Date, including without limitation any obligations to Seller Employees through the Closing Date. As to the liabilities of Seller not assumed by Purchaser, Seller shall satisfy all such obligations in the ordinary course of business so that, among other things, the Assets shall be free and clear of any liabilities or liens with respect thereto. 6 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 6 2.03 Purchase Price. Upon the terms and subject to the conditions of this Agreement, at Closing, Purchaser will pay Seller for the Assets a purchase price of EIGHTY FIVE MILLION NINE HUNDRED THOUSAND AND NO/100 DOLLARS ($85,900,000.00) ("Purchase Price"). The Purchase Price shall be paid in the amount of: (A) EIGHT MILLION SIX HUNDRED FIFTY THOUSAND AND NO/100 DOLLARS ($8,650,000.00) which was paid by Purchaser to Seller as a non-refundable performance deposit ("Performance Deposit") in connection with the return of an executed copy of this Agreement to Seller; and (B) at Closing, the balance of the Purchase Price for the Assets of SEVENTYSEVEN MILLION TWO HUNDRED FIFTY THOUSAND AND NO/100 DOLLARS ($77,250,000.00), subject to adjustment according to the provisions of this Agreement. All payments shall be made by wire transfer to Seller's account or by National Bank Cashier's Check, or other form of immediately available funds to Seller. 2.04 Purchase Price Adjustments. The Purchase Price shall be adjusted as follows: (A) upward by: (1) an amount in respect of the value of all natural gas and merchantable, allowable oil and condensate credited to the Leaseholds and Mineral Properties that is beyond the wellhead at the Effective Time, which amount shall be equal to the proceeds received by Purchaser therefor, net of applicable taxes; (2) the amount of all expenses paid by Seller in respect of the Assets subsequent to the Effective Time excluding Seller's overhead but including, without limitation: (a) Lease Burdens, actual direct operating expenditures for work actually performed, operator and outside operator direct labor and usual fringe benefit costs, fixed rate overhead charges paid to outside operators and/or other third parties, delay rentals, shut-in royalties, valid calls under the Operating Agreements, and production and severance taxes paid with respect to the Leaseholds and Mineral Properties from the Effective Time to the Closing; (b) all capital and drilling expenditures incurred subsequent to the Effective Time and other capital and drilling expenditures incurred as permitted in this Agreement; and (c) the amount of $100,000.00 per month for the period from the Effective Time to the Closing and a prorata payment for each part thereof (which amount shall be in lieu of general and administrative costs and expenses of Seller that are paid or accrued by Seller in connection with the operation or ownership of the Assets during the period of time between the Effective Time and the Closing); and (3) an amount equal to the portion of all taxes paid by Seller and relating to the operation of the Assets subsequent to the Effective Time; provided, however, that no upward adjustment of the Purchase Price shall be made for or in connection with any federal income taxes, provincial income taxes, gross receipts taxes, capital gains taxes, franchise taxes or any similar taxes; 7 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 7 (4) an amount equal to the purchase price for the Hancock Properties under the Hancock Letter Agreement if the Hancock Properties are acquired by Seller prior to Closing; and (5) an amount equal to the Tax Credit Properties Purchase Price under the Tax Credit Properties Letter Agreement and an amount equal to the Option Purchase Price under the Tax Credit Properties Letter Agreement if the Tax Credit Properties are acquired by Seller prior to Closing. (B) downward by, (1) the proceeds (other than those referred to in clause (2) below) received by Seller (or for which Seller has received offset or other similar credit) and all receivables of Seller that are attributable to the operation or ownership of the Assets during the period of time between the Effective Time and the Closing; (2) the amount of the proceeds received by Seller from the disposition (inadvertently or with the prior written consent of the Purchaser) of all or any portion of the Assets; (3) an amount equal to all unpaid ad valorem, property, and similar taxes and assessments that are allocable to the Seller for the period of time prior to the Effective Time; and (4) an amount equal to any downward adjustments for Designated Title Defects under Article VII. (C) To Seller's Knowledge, Seller represents the Assets are not subject to any gas imbalances under any Gas Balancing Arrangement. In the event Purchaser or Seller discover a gas imbalance within ninety days of Closing, such party shall notify the other party and Purchaser and Seller shall settle such gas imbalances using a price of $2.00/mcf for production from the Assets. 2.05 Determination of Purchase Price Adjustments. (A) Prior to Closing, Seller shall deliver to Purchaser an estimate of the amount of Purchase Price adjustments as set forth in Section 2.04 ("Adjustment Estimate") as of the Closing Date setting forth in reasonable detail the calculation thereof. For purposes of the Closing, the Purchase Price shall be adjusted using the Adjustment Estimate. (B) As soon as reasonably practicable, and in any event within one hundred twenty (120) calendar days following the Closing, Seller shall deliver to Purchaser a statement of the actual Purchase Price adjustments calculated pursuant to Section 2.04 (the "Final Settlement Statement"). Purchaser shall have thirty (30) days thereafter to review the Final Settlement Statement and present any corrections thereto. Any disparities shall be resolved by the independent auditors of the Purchaser and Seller or an independent third auditor selected by both. The Final Settlement Statement shall thereafter for all purposes be final and binding on Seller and Purchaser and the amount of the Purchase Price adjustments as finally determined pursuant to this Section 2.05(B) shall be paid (with interest at the Agreed Interest Rate from the Closing to the date of payment) within five (5) days after delivery of the Final Settlement Statement or the resolution of any disputes, whichever is the later. 8 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 8 ARTICLE III The Closing 3.01 Place and Time of Closing. The Closing shall be held at the offices of Seller in Houston, Texas at 10:00 a.m., Central Standard Time, on October 1, 1997 or at such other place or time as the parties may mutually agree. 3.02 Deliveries at Closing. Upon the terms and subject to the conditions of this Agreement, at Closing: (A) Seller shall furnish to Purchaser a statement setting forth the Purchase Price adjusted pursuant to the Adjustment Estimate; (B) Purchaser shall pay to Seller the balance of the Purchase Price in the manner stipulated in Section 2.03; (C) Purchaser and Seller shall execute, acknowledge and deliver effective at the Effective Time the Assignment, Bill of Sale and Conveyance in the form attached as Exhibit "B", with the blanks and exhibits to such document appropriately completed by Seller; (D) Seller shall pay to Purchaser the amounts held in related royalty suspense accounts by Seller attributable to the Leaseholds and Mineral Properties together with a written explanation (as contained in Seller's files) of the reasons such funds are held in suspense; (E) Seller shall deliver to Purchaser possession of the Assets evidenced by delivery of such documents; (F) Seller shall deliver to Purchaser possession of the Books and Records. (G) Seller and Purchaser shall execute, acknowledge and deliver effective at the Effective Time the joint operating agreement in the form attached as Exhibit "C" covering the jointly owned interests of Purchaser and Seller in the Leaseholds and Mineral Properties. ARTICLE IV Representations and Warranties of Seller Except as otherwise disclosed in this Agreement, Seller represents and warrants (which representations and warranties are accurate as of the date hereof or shall be true on and as of the Closing Date in all material respects) that: 4.01 Organization and Good Standing. Seller is a corporation duly organized, validly existing and in good standing under the laws of Delaware and has all requisite corporate power and authority to own and lease the properties and assets it currently owns and leases and to carry on its business as such business is currently conducted and Seller is duly qualified to do business as a foreign corporation and is in good standing in the jurisdiction where the Assets are located; 4.02 Corporate Authority, Authorization of Agreement. Seller has all requisite corporate power and authority to execute and deliver this Agreement and all documents that are executed and delivered pursuant to this Agreement, to consummate the transactions contemplated hereby and to perform all the terms and conditions hereof to be performed by it. The execution and delivery by Seller of this Agreement and all documents that are executed and delivered pursuant to this Agreement, and the performance by Seller and the consummation of the transactions contemplated hereby (a) have been duly 9 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 9 authorized and approved by the Board of Directors of Seller, or (b) are within the discretion of the officers of Seller; and this Agreement and all documents executed pursuant to this Agreement are the valid and binding obligation of Seller, enforceable in accordance with their terms, except as such enforceability may be limited by bankruptcy, insolvency or other laws relating to or affecting generally the enforcement of creditors' rights and general principles of equity; 4.03 No Default; Compliance with Laws and Regulations. Seller is not in default under, and no condition exists that with notice or lapse of time or both would constitute a default under any mortgage, indenture, loan, credit agreement or other agreement or instrument evidencing indebtedness for borrowed money, or create a lien, charge or other encumbrance on the Assets; 4.04 Producing Leaseholds/Environmental. Except as set forth in Schedule 1, to Seller's Knowledge, Seller's operation of the Assets has been conducted in compliance with all applicable Environmental Statutes. The exclusive remedy of Purchaser for any breach of the representation set forth in this Section 4.04 is set forth in Section 7.06 hereof. 4.05 Warranties Disclaimer. Except for the warranty provided by Seller in Section 7.01, Seller will make no warranty or representation of title to Purchaser of any kind, and will expressly disclaim any implied warranty of title. Seller will disclaim any warranty of condition or use of personal property. 4.06 Litigation. Except as set forth in Schedule 2 there are no actions, suits, proceedings or to Seller's Knowledge, governmental investigations or inquiries pending, or, to Seller's knowledge, threatened against Seller or its Affiliates or any of the Assets that might delay, prevent or hinder the consummation of the transactions contemplated hereby, or materially effect the value of the Assets. 4.07 Payment of Royalties: To Seller's Knowledge, all material royalties (other than royalties held in suspense), rentals, and other payments due under the Leaseholds have been paid in the normal course of business according to standards generally accepted in the oil and gas industry. 4.08 Payment of Taxes: To Seller's Knowledge, all ad valorem, property, production, severance, and similar taxes and assessments based on or measured by the ownership of property or the production of hydrocarbons or the receipt of proceeds therefrom on the Assets have been properly paid. 4.09 Broker Fees: Seller has incurred no liability, contingent or otherwise, for brokers' or finders' fees relating to the transactions contemplated by this Agreement for which Purchaser shall have any responsibility whatsoever. 4.10 Citizenship of Seller: Seller is not a "foreign person" within the meaning of Section 1445 of the Internal Revenue Code of 1986, as amended. 4.11 Oil and Gas Contracts: To Seller's Knowledge, Seller has made available to Purchaser the Oil and Gas Contracts, Operating Agreements, leases of equipment or facilities and other contracts, agreements and rights that cover or affect the Assets. ARTICLE V Representations and Warranties of Purchaser Except as otherwise disclosed in this Agreement, Purchaser hereby represents and warrants that: 5.01 Organization and Existence. Purchaser is a corporation duly organized, validly existing and in good standing under the laws of the jurisdiction of incorporation and has all requisite corporate power and authority to purchase the Assets and to own and lease the properties and Assets it currently owns 10 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 10 and leases and to carry on its business as such business is currently conducted and Purchaser is duly qualified to do business as a foreign corporation and is in good standing in the jurisdiction where the Assets are located. 5.02 Authority and Approval. Purchaser has all requisite power and authority to execute and deliver this Agreement, to consummate the transactions contemplated hereby and to perform all the terms and conditions hereof to be performed by it. The execution and delivery of this Agreement by Purchaser, the performance by it of all the terms and conditions hereof to be performed by it and the consummation of the transactions contemplated hereby have been duly authorized and approved by its Board of Directors. This Agreement constitutes the legal, valid and binding obligation of Purchaser, enforceable against Purchaser in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency or other laws relating to or affecting generally the enforcement of creditors' rights and general principles of equity. 5.03 No Violations. This Agreement and the execution and delivery hereof by Purchaser do not, and the fulfillment and compliance with the terms and conditions hereof and the consummation of the transactions contemplated hereby will not, violate any provision of or constitute a default (without regard to any requirement of notice or the lapse of time or both) or require any filing or consent under Purchaser's certificate of incorporation, or other governing instruments, or any law or regulation to which Purchaser is subject, or any provision of any material indenture, mortgage, lien, lease, agreement, instrument, order, arbitration award, judgment or decree to which Purchaser or any of its affiliates is a party or by which Purchaser or any of its affiliates or any of their respective assets or properties is bound. 5.04 Funds Available. Purchaser has, or will have prior to the Closing, sufficient cash, available lines of credit or other sources of immediately available funds to enable Purchaser to make payment of the balance of the Purchase Price at the Closing in accordance herewith. 5.05 Litigation. There are no actions, suits, proceedings or governmental investigations or inquiries pending, or, to the knowledge of Purchaser, threatened, against Purchaser or its Affiliates or any of their respective properties, assets, operations or businesses that might delay, prevent or hinder the consummation of the transactions contemplated hereby. ARTICLE VI Additional Agreements and Covenants 6.01 Covenants of Seller. Seller covenants and agrees (subject to any requirements imposed upon Seller pursuant to the terms of the Operating Agreements, the Unit Agreements and the Oil and Gas Contracts), with Purchaser that from the date of this Agreement until the Closing Date, Seller (i) will make reasonable efforts to cause the Assets to be operated and maintained in a good and workmanlike manner consistent with prior practices, and will pay or cause to be paid all costs and expenses in connection therewith, (ii) will not sell, lease, encumber, abandon or otherwise dispose of any of the Leaseholds or Mineral Properties other than to make sales of produced Hydrocarbons in the ordinary course of business, (iii) will maintain insurance now in force with respect to the Assets, (iv) will make reasonable efforts to comply with all the rules, regulations, and orders of all state and federal agencies which are applicable to Seller and the Assets, (v) will make reasonable efforts to perform and comply with all of the material covenants and conditions contained in agreements relating to the Assets, (vi) will pay all taxes and assessments with respect to the Assets which become due and payable prior to the Closing Date, and (vii) will not commence or consent to any material operations on any Leaseholds or Mineral Properties that Seller has not previously committed to and that may be expected to cost in excess of FIFTY THOUSAND AND NO/100 DOLLARS ($50,000.00) (attributable to 100% of the operating interest) except for emergency operations, in which case Seller shall promptly notify Purchaser. Seller shall not be obligated to renew or extend expiring Leaseholds after the Effective Date unless mutually agreed at Purchaser's 11 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 11 expense. Without expanding any obligations which Seller may have to Purchaser, it is expressly agreed that Seller shall never have any liability to Purchaser with respect to operation of an Asset greater than that which it might have as the Operator to a Non-operator under the applicable operating agreement or, in the absence of such an agreement, then under the AAPL 610 (1989) Model Form Operating Agreement, IT BEING RECOGNIZED THAT CERTAIN OF SUCH AGREEMENTS PROVIDE THAT THE OPERATOR IS NOT RESPONSIBLE FOR ITS OWN NEGLIGENCE, AND HAS NO RESPONSIBILITY OTHER THAN FOR GROSS NEGLIGENCE OR WILLFUL MISCONDUCT. 6.02 Records Inspection/Access/Disclaimer. Seller will afford to Purchaser and its authorized representatives, at Purchaser's sole cost, risk and expense, and upon reasonable notice, reasonable access to the Assets from the date hereof until the Closing, during normal business hours, and to the Books and Records which are related primarily to the Assets insofar as such access and disclosure does not unreasonably interfere with the normal operation of the business of Seller or violate the terms of any agreement by which Seller is bound or any applicable law or regulation. Seller will include all of its complete records to the best of its knowledge, however Seller does not represent or guarantee that such information or data or the Book and Records will be accurate or complete, and any reliance thereon will be at the sole risk, exposure and expense of Purchaser. 6.03 No Negotiations. After execution of this Agreement, Seller shall not solicit from any Person any proposals or offers, or enter into any negotiations relating to the disposition of the Assets, except for sales of Hydrocarbons in the ordinary course of business. 6.04 Public Announcements. Subject to applicable securities law or stock exchange requirements, at all times, Seller or Purchaser shall obtain the approval of the other before issuing, or permitting any of their respective directors, officers, employees or agents or any Affiliate to issue, any press release with respect to this Agreement or the transactions contemplated hereby. 6.05 Cooperation. Seller shall cooperate with Purchaser to obtain all such permissions, approvals and consents by federal, state and local governmental authorities and others as may be required to consummate the transactions contemplated herein or as may be reasonably requested by Purchaser. 6.06 Covenants of Purchaser. Purchaser covenants and agrees with Seller as follows: (A) Confidential Information. In the event that this Agreement is terminated or, if not terminated, until the Closing, the confidentiality of any data or information received by Purchaser regarding the Assets shall be maintained by Purchaser. (B) Use of the name "Cabot Oil & Gas Corporation", "Cranberry Pipeline Corporation" or "Big Sandy Gas Company". Within sixty (60) days after the Closing Date, Purchaser shall eliminate the names (i) "Cabot Oil & Gas Corporation", "Cabot Oil & Gas" or "Cabot", (ii) "Cranberry Pipeline Corporation", "Cranberry Pipeline", or "Cranberry", (iii) "Big Sandy Gas Company", "Big Sandy Gas" or "Big Sandy" and any derivative thereof or any other word or expression similar thereto from the Assets and thereafter Purchaser shall not use any logos, trademarks or tradenames belonging to Seller. (C) Assumed Liabilities. From and after the Closing, Purchaser shall assume and undertake to pay, perform and discharge, when due, and shall indemnify and save Seller harmless from all the debts, liabilities, obligations and commitments of Seller that arise (i) from or out of the ownership of the Assets regardless of whether such liabilities and obligations are absolute, contingent or otherwise known or unknown as of the date hereof and (ii) from such liabilities and obligations of Seller under all Legal Requirements respecting plugging and abandoning of all wells on the Leaseholds (and the reclamation of the surface thereof) at the end of their producing life, and Legal Requirements issued by governmental commissions, or their governmental successors, including any investigation or order issued or which may be issued under legal authority. Notwithstanding the foregoing, Purchaser shall not assume any liabilities 12 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 12 specifically excluded from Section 2.02 as to which Seller shall pay, perform, and discharge such liabilities when due and shall indemnify and save Purchaser harmless therefrom. ARTICLE VII Title Matters 7.01 Scope. This is a sale of all of Seller's right, title and interest in the Assets to Purchaser, subject to the Permitted Encumbrances. The Assets shall be conveyed with Seller's warranty to defend title to the Assets against every person claiming or to claim an interest therein by, through or under Seller, but not otherwise subject to the Permitted Encumbrances. If any Asset is erroneously described, Seller shall, at any time before or after Closing correct such description upon proof of proper description. Seller shall transfer the Assets on an "as is" and "where is" basis. 7.02 Limitation on Adjustment. The Purchase Price, as adjusted pursuant to Section 2.04, shall not be adjusted with respect to matters set forth in Section 7.05 and shall not be adjusted with respect to Title Defects except as provided in this Article. Notwithstanding anything in this Agreement to the contrary, the Purchase Price shall not be adjusted for Title Defect Amounts (defined in Section 7.04) which do not, in the aggregate, exceed the Title Defect Deductible Amount and Purchaser shall take delivery of such Leaseholds and Mineral Properties subject to such Title Defects. 7.03 Title Examination. Seller shall make available to Purchaser the Books and Records pursuant to Article 6.02. From and after the date of this Agreement, Purchaser may examine title to the Leaseholds and Mineral Properties through examination of Seller's Books and Records and any other independent source of title records Purchaser deems necessary. 7.04 Claim Period/Designated Title Defects. In order to receive a Purchase Price adjustment attributable to Title Defects, Purchaser must, no later than sixty (60) days after Closing, furnish Seller with written notice specifying in detail each Title Defect which Purchaser is asserting, the Leaseholds that each Title Defect affects and the Title Defect amount estimated by Purchaser for each Title Defect ("Title Defect Amount"). If the aggregate of all Title Defect Amounts in Purchaser's written notice exceeds the Title Defect Deductible Amount then all Title Defects (including the Title Defects which comprise the Title Defect Deductible Amount) set forth in such notice ("Designated Title Defects") shall be addressed pursuant to this Section 7.04 As to the Designated Title Defects, Seller shall have sixty (60) days from the receipt of Purchaser's written notice in which to notify Purchaser in writing with respect to each Designated Title Defect of (i) Seller's intent to attempt to cure the Designated Title Defect at Seller's expense, (ii) Seller's election to reduce the Purchase Price by the Title Defect Amount for the Designated Title Defect, (iii) Seller's election to reduce the Purchase Price by the Title Defect Amount for the Designated Title Defect and accept a reconveyance from Purchaser to Seller of the Leaseholds or Mineral Properties affected by such Designated Title Defect or (iv) the dispute by Seller of the existence of the Designated Title Defect or the Title Defect Amount estimated by Purchaser for the Designated Title Defect. When considering whether Seller has cured a Designated Title Defect, Seller and Purchaser shall determine whether the Designated Title Defect has been cured based on the standards currently prevalent in the acquisition of producing oil and gas properties and pipeline rights of way, easements and fee rights, and property. If Seller elects to attempt to cure any Designated Title Defect and cures such Designated Title Defect on or before the end of Seller's sixty (60) day period, no Purchase Price adjustment shall be made. Upon the expiration of sixty (60) days after Closing, all Title Defects are deemed waived except those Designated Title Defects set forth in Purchaser's notice. 7.05 Preferential Rights and Consents to Assignment. The Assets may be subject to existing preferential rights to purchase or consents to assignment by third parties (including those reflected in Schedule 3). Assets subject to existing preferential rights to purchase or consents to assignment by third parties shall not be considered as properties with Title Defects or in value amounts for determining the 13 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 13 aggregate of all Title Defect Amounts in excess of the Deductible Amount. Seller shall use reasonable efforts to obtain waivers of all preferential rights and to obtain all consents to assignment prior to Closing. The amount allocated by Seller to any Asset subject to a claim of preferential right shall be determined based on Purchaser's itemized allocation which Purchaser shall provide to Seller as requested by Seller in connection therewith. The rights and obligations of the parties concerning such preferential rights and consents to assignment are as follows: (A) In the event a preferential right is exercised prior to Closing, then (i) Seller shall be entitled to all proceeds paid by such third party exercising its preferential right, (ii) the Purchase Price shall be adjusted downward in an amount equal to the price paid to Seller by such third party, and (iii) such Assets shall be deleted from the Assignment, Bill of Sale and Conveyance. (B) In the event a preferential right is exercised subsequent to Closing, then Purchaser shall be obligated to comply with such preferential right but shall be entitled to all proceeds paid by such third party exercising its preferential right. 7.06 Environmental Condition. Purchaser's exclusive remedy, for any Environmental Condition shall be as provided in this Section 7.06. If within one (1) year after the Effective Time Purchaser notifies Seller in writing of facts, conditions, and circumstances which constitute an Environmental Condition with respect to the Assets and such Environmental Condition results in Purchaser having aggregate losses in excess of the Environmental Deductible Amount then subject to the further limitations set forth in this Section 7.06, Seller shall indemnify Purchaser for all aggregate losses incurred from the first dollar. Seller's liability under this Section 7.06 shall be limited to a maximum of THREE MILLION AND NO/100 DOLLARS ($3,000,000.00) and Seller's liability under this Section 7.06 shall in no event ever exceed such amount. ARTICLE VIII Termination 8.01 Grounds for Termination. This Agreement may be terminated at any time prior to the Closing: (A) by the mutual written agreement of Seller and Purchaser; or (B) by either Seller or Purchaser if the consummation of the transactions contemplated hereby would violate any non-appealable final order, decree or judgment of any court or governmental authority having competent jurisdiction enjoining, restraining or otherwise preventing, or awarding substantial damages in connection with, the consummation of this Agreement or the transactions contemplated hereby; (C) by Seller if Purchaser, through no breach of this Agreement by Seller, should fail or refuse to close by the Closing Date; or (D) by Purchaser if Seller, through no breach of this Agreement by Purchaser should fail or refuse to close by the Closing Date. 8.02 Effect of Termination. The following provisions shall apply in the event of a termination of this Agreement: (A) If this Agreement is terminated by Seller or Purchaser as permitted under Sections 8.01(A), (B), or (D) hereof and not as the result of Purchaser's failure to perform its obligations hereunder then Seller shall return the Performance Deposit to Purchaser. Such termination under Sections 8.01(A) or 14 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 14 (B) shall be without liability of any party to this Agreement or any Affiliate, shareholder, director, officer, employee, agent or representative of such party. (B) If this Agreement is terminated as a result of (i) the material breach by Purchaser of any of the material terms and provisions of this Agreement, (ii) the negligent or willful failure of Purchaser to perform its obligations hereunder or (iii) Purchasers failure or refusal to close by the date set forth in Article 8.01(C), Purchaser shall be fully liable for any and all damages, costs and expenses (including, but not limited to, reasonable attorneys' fees, expert witness' fees and court costs) thereby sustained or incurred by Seller and Seller shall be entitled to retain the Performance Deposit as liquidated damages and not as a penalty. (C) If this Agreement is terminated as a result of (i) the material breach by Seller of any of the material terms and provisions of this Agreement, (ii) the negligent or willful failure of Seller to perform its obligations hereunder or (iii) Seller's failure or refusal to close by the date set forth in Article 8.01(D), Seller shall be fully liable for any and all damages, costs and expenses (including, but not limited to, reasonable attorney's fees, expert witness fees and court costs) thereby sustained or incurred by Purchaser and Purchaser shall be entitled to seek specific performance of this Agreement if it believes that monetary damages would not be adequate to compensate Purchaser therefore. ARTICLE IX Extent and Survival of Representations and Warranties; Indemnification 9.01 Scope of Representations of Seller. EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT, SELLER MAKES NO REPRESENTATION OR WARRANTY WHATSOEVER AND DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO PURCHASER (INCLUDING, BUT NOT LIMITED TO, ANY OPINION, INFORMATION OR ADVICE WHICH MAY HAVE BEEN PROVIDED TO PURCHASER BY ANY AFFILIATE, OFFICER, STOCKHOLDER, DIRECTOR, EMPLOYEE, AGENT, CONSULTANT OR REPRESENTATIVE OF SELLER OR ANY PETROLEUM ENGINEER OR ENGINEERING FIRM, SELLER'S COUNSEL OR ANY OTHER AGENT, CONSULTANT OR REPRESENTATIVE). WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, EXCEPT AS AND TO THE EXTENT EXPRESSLY SET FORTH IN THIS AGREEMENT, SELLER MAKES NO REPRESENTATION OR WARRANTY AS TO (A) THE TITLE TO ANY OF THE LEASEHOLDS OR MINERAL PROPERTIES (B) THE AMOUNTS OF HYDROCARBON RESERVES ATTRIBUTABLE TO THE LEASEHOLDS OR MINERAL PROPERTIES (IF ANY) OR (C) ANY GEOLOGICAL OR OTHER INTERPRETATIONS OR ECONOMIC EVALUATIONS. PURCHASER ACKNOWLEDGES AND AFFIRMS THAT IT HAS HAD FULL ACCESS TO THE BOOKS AND RECORDS OF SELLER AND THE INFORMATION THEREIN, AND PURCHASER HAS MADE ITS OWN INDEPENDENT INVESTIGATION, ANALYSIS AND EVALUATION OF (I) THE WELLS ON THE LANDS COVERED BY THE LEASEHOLDS AND MINERAL PROPERTIES (INCLUDING PURCHASER'S OWN ESTIMATE AND APPRAISAL OF THE EXTENT AND VALUE OF THE HYDROCARBON RESERVES OF THE LEASEHOLDS AND MINERAL PROPERTIES), (II) TITLE TO THE LEASEHOLDS AND MINERAL PROPERTIES, (III) OPERATION OF THE LEASEHOLDS AND MINERAL PROPERTIES AND (IV) ENVIRONMENTAL CONDITIONS ON, IN AND UNDER THE LEASEHOLDS AND MINERAL PROPERTIES. PURCHASER SHALL HAVE INSPECTED, OR HAVE WAIVED (AND UPON CLOSING SHALL BE DEEMED TO HAVE WAIVED) IT'S RIGHT TO INSPECT, THE ASSETS FOR ALL PURPOSES AND SATISFIED ITSELF AS TO THE ASSETS PHYSICAL AND ENVIRONMENTAL CONDITION, BOTH SURFACE AND SUBSURFACE, INCLUDING BUT NOT 15 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 15 LIMITED TO CONDITIONS SPECIFICALLY RELATED TO THE PRESENCE, RELEASE OR DISPOSAL OF HAZARDOUS SUBSTANCES, SOLID WASTES, ASBESTOS AND OTHER MAN-MADE FIBERS, OR NATURALLY OCCURRING RADIOACTIVE MATERIALS ("NORM"). PURCHASER IS RELYING SOLELY UPON ITS OWN INSPECTION OF THE ASSETS, AND PURCHASER SHALL, EXCEPT AS PROVIDED OTHERWISE IN THIS AGREEMENT, ACCEPT ALL THE SAME IN THEIR "AS IS, WHERE IS" CONDITION. ANY AND ALL BOOKS AND RECORDS, DATA, RECORDS, REPORTS, PROJECTIONS, INFORMATION AND OTHER MATERIALS (WRITTEN OR ORAL) FURNISHED BY SELLER OR OTHERWISE MADE AVAILABLE OR DISCLOSED TO PURCHASER ARE PROVIDED PURCHASER AS A CONVENIENCE AND SHALL NOT CREATE OR GIVE RISE TO ANY LIABILITY OF OR AGAINST SELLER AND ANY RELIANCE ON OR USE OF THE SAME SHALL BE AT PURCHASER'S SOLE RISK TO THE MAXIMUM EXTENT PERMITTED BY LAW; PROVIDED, HOWEVER, THAT SELLER HAS NOT INTENTIONALLY PROVIDED ANY INFORMATION OR MATERIAL TO PURCHASER WHICH SELLER KNOWS TO BE FALSE OR MISLEADING. 9.02 Representations and Warranties of Seller. The representations and warranties of Seller set forth in this Agreement and in any instrument delivered in connection herewith shall survive the Closing provided that neither Purchaser nor any Affiliate or successor or assign to Purchaser may bring any action or present any claim for a breach of such representations and warranties unless written notice of such claim with reasonable particulars of the claim has been delivered to Seller within one (1) year after the Effective Time. 9.03 Representations and Warranties of Purchaser. The representations, warranties and indemnities by Purchaser shall survive until the expiration of any applicable limitations period. 9.04 Indemnification of Seller. Purchaser agrees to indemnify Seller, its respective Affiliates and all of their respective directors, officers, agents and representatives, against, and hold Seller, its respective Affiliates, and all of their respective directors, officers, agents and representatives, harmless from, any Seller Indemnified Loss. 9.05 Indemnification of Purchaser. Seller agrees to indemnify Purchaser against and hold Purchaser harmless from every Purchaser Indemnified Loss; provided, however, that Purchaser shall not be entitled to assert rights of indemnification under this Article IX for Purchaser Indemnified Losses unless and until and then only to the extent the aggregate of all such amounts exceed the Deductible Amount. If the aggregate of all Purchaser Indemnified Losses exceeds the Deductible Amount, then Seller shall indemnify Purchaser for all Purchaser Indemnified Losses incurred from the first dollar. In no event shall the total of the liabilities and indemnities of Seller under this Agreement, including, without limitation, any claims relating to its representations, exceed the Purchase Price. ARTICLE X Casualty Loss It is understood and agreed that Seller does not maintain insurance covering the Assets. If, prior to the Closing, all or any part of the Assets shall be destroyed by fire or other casualty, or any part of the Assets shall be taken in condemnation or under the right of eminent domain, or if proceedings for such purposes shall be pending or threatened, Seller shall, at the Closing, pay to Purchaser all sums paid to Seller by reason of such destruction or taking, and assign, transfer, and set over unto Purchaser all of the right, title and interest of Seller in and to any unpaid awards or other payments arising out of such destruction or taking. 16 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 16 ARTICLE XI Taxes 11.01 Tax Purchase Price Allocations. Seller and Purchaser recognize that reporting requirements as imposed by Section 1060(b) of the United States Internal Revenue Code, and the Regulations thereunder, may apply to the transaction contemplated by this Agreement. If so, Seller and Purchaser agree that the Purchase Price shall be allocated among the Assets as mutually agreed by Seller and Purchaser, and such allocation shall satisfy the requirements of Section 1060 of the Code, and the Regulations thereunder. For purpose of this Section, no Asset shall be allocated a negative value. 11.02 Sales and Use Taxes, Recording Fees and Income Taxes. Purchaser shall pay all documentary, filing and recording fees required in connection with the filing and recording of any assignments. Purchaser shall be liable for and pay all applicable transfer, sales and use taxes occasioned by the sale of the Assets and such amount, if assessed, will be additional to the Purchase Price. For purposes of federal and state income taxation, Seller shall include in all appropriate income tax returns all items of income, expense, gain and loss attributable to the Assets for the period of time ending on or before the Effective Time, and Purchaser will include in its income tax returns all items of income expense, gain or loss attributable to the period after the Effective Time. 11.03 Ad Valorem and Property Taxes. All ad valorem and property taxes and any similar assessment based upon or measured by Seller's ownership interests in the Assets or the production of Hydrocarbons therefrom or the receipt of proceeds on sales therefrom shall be prorated between Seller and Purchaser as of the Effective Time based upon such taxes assessed against the Assets for the tax period in question, or if there is insufficient information for such tax period, based upon taxes assessed for the immediately preceding tax period just ended. All such taxes will be prorated on the basis of a 365 day year. Ad valorem and similar taxes assessed for periods prior to the Effective Time shall be borne by Seller and ad valorem taxes assessed for periods on or after the Effective Time shall be borne by Purchaser (ad valorem and similar taxes shall be considered assessed for the period for which they are stated to be assessed, even if the same are based on production or other activities occurring in prior periods). 11.04 Like Kind Exchange. Seller may elect to structure this transaction as a like-kind exchange pursuant to Section 1031 of the Internal Revenue Code of 1986, as amended, and the regulations promulgated thereunder, with respect to any or all of the Assets ("Like-Kind Exchange"), by notifying the Purchaser in writing of such election at any time prior to the date of Closing. In the event Seller elects a Like-Kind Exchange, then in order to effect such Like-Kind Exchange, the Purchaser shall cooperate and do all acts as may be reasonably required or requested by Seller with regard to effecting the Like-Kind Exchange, including, but not limited to, permitting Seller to assign its rights under this Agreement to a qualified intermediary of Seller's choice in accordance with Treasury Regulation Section 1.1031(k)-1(g)(4) or executing additional escrow instructions, documents, agreements or instruments to effect an exchange; provided, however, Purchaser shall incur no expense (that is not reimbursed by the Seller) or liability in connection with such Like-Kind Exchange and Purchaser shall not be required to take title to any property other than the Assets in connection with the Like-Kind Exchange, and, in the case of a Like-Kind Exchange election by Seller, Purchaser's possession of the Properties will not be delayed by reason of any such Like-Kind Exchange. ARTICLE XII Employee Matters 12.01 Seller Employees. The term "Seller Employees" shall mean those employees set forth on Schedule 4 hereto. 17 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 17 12.02 Employment Offers. On or before the Closing Date, Purchaser shall make offers to Seller Employees of full-time employment with Purchaser in comparable positions to those which Seller Employees hold with Seller, upon terms and conditions of employment (including without limitation, salaries and employee benefit programs) which are the same or similar to the terms and conditions of employment Purchaser has for employees in comparable positions with Purchaser. 12.03 Employee Termination. On the Closing Date, Seller shall terminate the employment of all Seller Employees and Purchaser shall offer employment to Seller Employees on the terms and conditions of employment set forth in this Article. Seller shall be solely responsible for all obligations to Seller Employees arising on or before the Closing Date including, without limitation, any and all accrued pension, severance, vacation, or other benefits. ARTICLE XIII Notices; Miscellaneous 13.01 Notices. All notices and other communications given hereunder shall be in writing and shall be deemed given if delivered personally or mailed by registered or certified mail, return receipt requested, to the parties at the following addresses: (A) If to Purchaser: Lomak Petroleum, Inc. 125 State Route 43 - PO Box 550 Hartville, Ohio 44632 Attention: Jeffery A. Bynum (330) 877-6747 Phone (330) 877-6129 Fax Walter M. Epstein, Esq. Rubin, Baum, Constant, Levin, & Friedman 30 Rockefeller Plaza - 29th Fl. New York, NY 10112 (B) If to Seller to: Cabot Oil & Gas Corporation 15375 Memorial Drive Houston, Texas 77079 Attention: Mr. J. L. Batt 13.02 Miscellaneous. (A) Exclusive Agreement. This Agreement (including the Schedules and Exhibits attached hereto) supersedes all prior written or oral agreements between the parties with respect to the transactions contemplated herein and is intended as a complete and exclusive statement of the terms of the agreement between the parties with respect to the transactions contemplated herein. (B) Choice of Law; Choice of Forum; Amendments; Headings. This Agreement shall be governed by the laws of the State where the lands covered by the Leaseholds and Mineral Properties are situated. This Agreement may not be changed or terminated orally. The headings contained in this 18 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 18 Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement. Terms such as "herein", "hereby", "hereto", "hereunder", and "hereof" refer to this Agreement as a whole. The term "include" and derivatives thereof are used in an illustrative sense and not a limitative sense. (C) Assignments and Third Parties. Neither party hereto shall assign this Agreement or any part hereof without the prior written consent of the other party. Except as otherwise provided herein, this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns. No such assignment shall release Purchaser of any of its obligations under this Agreement. Nothing in this Agreement shall entitle any person other than Seller, Purchaser or their respective permitted successors and assigns to any claim, cause of action, remedy or right of any kind. (D) Schedules and Exhibits. The Schedules and Exhibits attached hereto are made part hereof for all purposes. Seller shall revise or supplement the Schedules and Exhibits attached to this Agreement at any time within six (6) months after Closing to reflect a change in any state of facts or the occurrence, non-occurrence or existence of any events that would make the information contained in any such Schedule or Exhibit misleading or incorrect if it was not revised or supplemented. (E) Severability. If any term or other provision of this Agreement is invalid, illegal or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of this Agreement shall nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any manner adverse to any party. Upon any binding determination that any term or other provision is invalid, illegal or incapable of being enforced, the parties hereto shall negotiate in good faith to modify this Agreement so as to effect the original intent of the parties as closely as possible in an acceptable and legally enforceable manner, to the end that the transactions contemplated hereby may be completed to the extent possible. (F) Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original and all of which together shall constitute but one and the same agreement. (G) Further Assurances. Seller and Purchaser agree to promptly execute and deliver or cause to be executed and delivered to the other on the Closing Date, and at such other times thereafter as shall be reasonably requested, any additional instrument or take any further action as may be reasonably necessary or appropriate that the other may reasonably request for the purpose of carrying out the transactions contemplated by and the purposes and intents of this Agreement. (H) Preservation of Books and Records. For a period of two (2) years after the Closing Date, Purchaser shall (i) preserve and retain the Books and Records that relate to the period of time prior to the Closing (including, but not limited to, any documents relating to any governmental or non-governmental actions, suits, proceedings or investigations prior to the Closing) and (ii) make the Books and Records available at the then current administrative headquarters of Purchaser to Seller and its officers, employees, agents and affiliates upon reasonable notice and at reasonable times, it being understood that Seller shall be entitled to make and retain copies of any of the Books and Records as it shall deem necessary; provided, however, in the event Purchaser shall wish to destroy any of the Books and Records, Purchaser shall give Seller not less than sixty (60) days notice and Seller shall have the right, at its own expense, during reasonable business hours to remove such Books and Records and to keep possession of same. Purchaser agrees to permit representatives of Seller to meet with employees of Purchaser on a mutually convenient basis in order to enable Seller to obtain additional information and explanations of any materials provided pursuant to this Section. (I) Dispute with John Hancock Mutual Life Insurance Company. Set forth on Schedule 2 is a description of a dispute between Seller and John Hancock Mutual Life Insurance Company ("Hancock") 19 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 19 concerning certain oil and gas property interests owned by Hancock ("Hancock Properties") Resolution of the dispute and the possible purchase and sale of the Hancock Properties from Hancock to Seller and Seller to Purchaser is set forth in a letter agreement between Seller and Purchaser which has been executed contemporaneously with the execution of this Agreement (the "Hancock Letter Agreement"). (J) Tax Credit Properties. Certain properties to be acquired by Purchaser, pursuant to the terms and conditions of a letter agreement between Seller and Purchaser which has been executed contemporaneously with the execution of this Agreement ("Tax Credit Properties Letter Agreement"), are burdened by an Assignment of Oil & Gas Leases with Reservation of Production Payment, dated effective September 1, 1995, between Seller, as grantor, and Natural Gas Investments, L.L.C. ("NGI"), as grantee ("Tax Credit Properties"). Pursuant to an option to Purchase Oil and Gas Interests, dated September 1, 1995, between Seller and NGI ("Option Agreement"), Seller has the unilateral right to repurchase the Tax Credit Properties from NGI upon the terms and conditions contained in the Option Agreement. Seller shall exercise its option to repurchase the Tax Credit Properties, effective September 1, 1997 and pay NGI for such repurchase in accordance with the Option Agreement ("Option Purchase Price"). Purchaser's obligation to purchase and pay for the Tax Credit Properties ("Tax Credit Properties Purchase Price") and to reimburse Seller for the Option Purchase Price and Seller's obligation to sell the Tax Credit Properties are set forth in the Tax Credit Properties Letter Agreement. IN WITNESS WHEREOF, the undersigned have executed this Agreement as of the date first written above. SELLER: CABOT OIL & GAS CORPORATION By: --------------------------------- J.L. Batt Attest: Vice President Lisa A. Machesney Secretary CRANBERRY PIPELINE CORPORATION By: Attest: --------------------------------- Jeffrey W. Hutton Vice President Lisa A. Machesney Secretary BIG SANDY GAS COMPANY By: Attest: --------------------------------- Jeffrey W. Hutton Vice President Lisa A. Machesney Secretary 20 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 20 PURCHASER: LOMAK PETROLEUM, INC. By: Attest: --------------------------------- Jeffery A. Bynum Vice President Secretary Lomakfin.doc/ss 21 Jeffery A. Bynum Lomak Petroleum, Inc. September 8, 1997 Page 21

1 EXHIBIT 10.1(l) LOMAK PETROLEUM, INC. 1997 STOCK PURCHASE PLAN, AS AMENDED ARTICLE I PURPOSE The purpose of the Plan is to provide Eligible Persons, as defined herein, of Lomak Petroleum, Inc. (the "Company") with an opportunity to purchase Common Stock of the Company and thereby participate in the growth and future prospects of the Company. Each Participant will be entitled to purchase Common Stock at prices ranging from between 50% to 85% of the then fair market value of Common Stock. The Plan is not intended to comply with the provisions of Section 423 of the Internal Revenue Code of 1986, as amended. ARTICLE II DEFINITIONS The following terms, when capitalized, shall have the meanings specified below unless the context clearly indicates to the contrary. 2.1 "Board of Directors" shall mean the Board of Directors of the Company. 2.2 "Code" shall mean the Internal Revenue Code of 1986, as amended from time to time. 2.3 "Committee" or "Compensation Committee" shall mean the Compensation Committee appointed by the Board of Directors in accordance with Article III of the Plan. 2.4 "Committee Member" shall mean any past, present or future member of the Committee. 2.5 "Common Stock" shall mean the Common Stock, $.01 par value per share, of the Company. 2.6 "Company" shall mean Lomak Petroleum, Inc., a Delaware corporation. 2.7 "Effective Date" shall the date the Plan is declared operative by the Board of Directors. 2.8 "Eligible Person" shall mean only those persons who are officers, directors, key employees or consultants of the Company, as determined in the discretion of the Committee. 2.9 "Offering" shall mean the offering of shares of Common Stock to Eligible Persons pursuant to the Plan during any Plan Year, or on other dates as the Committee may determine. -1- 2 2.10 "Participant" shall mean an Eligible Person who elects to participate in the Plan. 2.11 "Plan" shall mean the Lomak Petroleum, Inc. 1997 Stock Purchase Plan, as amended. 2.12 "Plan Year" shall mean each calendar year during the term of the Plan commencing on the date of the annual meeting of the shareholders of the Company and terminating on the day preceding the annual meeting of the shareholders of the Company the following year, or other such fiscal year as determined by the Committee. 2.13 "Purchase Amount" shall mean an amount, not less than $500 in any Plan Year and not more than such amounts as may from time to time be determined by the Committee, to be applied to the purchase of Common Stock pursuant to this Plan. 2.14 "Purchase Date" shall mean any business day of a Plan Year on which a Participant advises an appropriate officer of the Company of such Participant's election to purchase Common Stock under the Plan, or any such other date or dates as the Committee may determine. 2.15 "Vested" shall mean non-forfeitable. The masculine gender, whenever used in this Plan, includes the feminine, the singular includes the plural and the plural includes the singular unless the context otherwise requires. ARTICLE III ADMINISTRATION OF PLAN The Plan shall be administered by the Compensation Committee appointed by the Board of Directors. The Committee shall have full and final authority to make rules and regulations, subject to the express provisions of the Plan, for the administration of the Plan, to decide who shall be Eligible Persons and Participants in the Plan, the maximum Purchase Amount, to determine the method and times of purchase of shares of Common Stock, to determine the purchase price of any shares of Common Stock sold to Participants hereunder, and to settle any disputes which may arise under the terms of the Plan. The Committee's interpretations and decisions with regard to the provisions of the Plan and any rules or regulations promulgated thereunder shall be final and conclusive. A majority of the Committee shall constitute a quorum, and acts of a majority of the members present at any meeting at which a quorum is present, or acts approved in writing by a majority of the Committee, shall be deemed the acts of the Committee. ARTICLE IV SHARES There shall be 500,000 shares of Common Stock reserved under the Plan, subject to adjustment in accordance with Article XII hereof. The shares of Common Stock subject to the Plan shall be either shares of authorized but unissued Common Stock or shares of Common Stock reacquired on the open market or otherwise for the account of the -2- 3 Participants. The Committee shall determine from time to time whether the shares of Common Stock shall be authorized or unissued shares or reacquired shares. ARTICLE V ENTRY INTO THE PLAN; PAYMENT FOR SHARES The Committee shall determine prior to any Plan Year, the number of shares that any Eligible Person shall be entitled to purchase pursuant to the Plan. The method of payment for the purchase of shares of Common Stock shall be determined by the Committee and may include, without limitation, cash, promissory notes, payroll deductions or any other method or combination thereof. No share of the Company's Common Stock may be issued to a Participant until such time as the Share has been fully paid for as above provided. ARTICLE VI PURCHASE OF SHARES At the beginning of each Plan Year, the Committee will determine who shall be Eligible Persons and Participants in the Plan, the maximum Purchase Amount for each Participant or class of Participants, and the procedures for a Participant to exercise a purchase under the Plan. Thereafter, a Participant may select the Purchase Date or Purchase Dates of the Participant's choice to purchase Common Stock up to the aggregate Purchase Amount designated by the Committee. Upon the purchase of stock by an employee, the Company will withhold the necessary employment taxes from regular cash wages. Participation in the Plan is strictly voluntary with regard to any Eligible Participant. ARTICLE VII PURCHASE PRICE The purchase price per share of any shares of Common Stock sold to any Participant hereunder shall, in the discretion of the Committee in respect of any Purchase Date, be between fifty (50%) percent and eighty-five (85%) percent of the fair market value (including transaction costs) of shares of Common Stock on the Purchase Date. In determining the purchase price per share of any shares of the Company's Common Stock sold to any Participants hereunder, the Committee may consider a number of factors including the performance and future prospects of the Company and the relationship of the fair market value of the Company's Common Stock to other indicia of value. Anything herein to the contrary notwithstanding, the purchase price for shares of authorized but unissued Common Stock of the Company purchased pursuant to this Plan shall not be less than the par value of the Common Stock. For purposes of the Plan, the fair market value of shares of Common Stock on any date shall be determined as follows: (a) If the Common Stock is then listed on a national securities exchange, the "fair market value" shall be the closing price of a share of Common Stock on such exchange on the last preceding business day on which shares of Common Stock were traded. (b) If the Common Stock is then not listed on a national securities exchange, the "fair market value" shall be the closing price of a share of Common Stock in the over-the- -3- 4 counter market as reported by the Nasdaq Stock Market National Market System ("Nasdaq") on that date or as reported on such other similar system then in use. (c) If the Common Stock is not then reported by Nasdaq or by such other similar system then in use, the "fair market value" shall be the closing bid price as furnished by a professional market maker making a market in the Common Stock as selected by the Board of Directors. (d) If neither (a), (b), nor (c) applies, the "fair market value" shall be determined by the Committee in good faith. Such determination shall be binding on all persons. (e) In any event, the "fair market value" shall be adjusted to include actual transactions costs and expenses, including broker's commissions and fees, stock transfer taxes and the like, of re-acquisition of shares of Common Stock on the open market or otherwise. ARTICLE VIII ISSUANCE OF SHARES; STOCK CERTIFICATES The shares of Common Stock purchased by a Participant on a Purchase Date shall, for all purposes, be deemed to have been issued and sold at the close of business on such Purchase Date. Prior to that time, none of the rights or privileges of a stockholder of the Company shall exist with respect to such shares. As soon as practicable after each Purchase Date, the Company will deliver, or cause to be delivered, a certificate for the number of shares purchased by the Participant. ARTICLE IX TERMINATION OF EMPLOYMENT OR AGENCY RELATIONSHIP In the event of termination of the employment or retention relationship between a Participant and the Company, for any reason, including death or permanent disability (as defined in Section 22(e) (3) of the Code), such Participant shall thereafter no longer be an Eligible Person under the Plan. ARTICLE X PROCEDURE IF INSUFFICIENT SHARES AVAILABLE In the event that on any Purchase Date the aggregate number of shares subscribed for by a Participant or Participants is a greater number of shares than the number of shares then available for purchase under the Plan, the Committee shall proportionately reduce the number of shares to be purchased by each Participant on such Purchase Date in order to eliminate such deficiency, and the Plan shall terminate immediately after such Purchase Date. ARTICLE XI RIGHTS NOT TRANSFERABLE A Participant's right to purchase shares of Common Stock under the Plan may not be assigned, transferred, pledged, hypothecated, or disposed of in any way and any attempted transfer or disposition thereof shall be null and void. -4- 5 ARTICLE XII RECAPITALIZATION; EFFECT OF CERTAIN TRANSACTIONS The aggregate number of shares of Common Stock reserved for purchase under the Plan as provided in Article IV hereof shall be appropriately adjusted by the Board of Directors to reflect a stock dividend, stock split-up, share combination, exchange of shares, recapitalization, merger, consolidation, liquidation or other similar changes or transactions by the Company. ARTICLE XIII TERMINATION AND AMENDMENT OF THE PLAN The Plan shall continue in effect through December 31, 2003, unless terminated prior thereto pursuant to Article X hereof or pursuant to the next succeeding sentence. The Board of Directors shall have the right to terminate the Plan at any time. The Board of Directors may from time to time make such amendments or modifications to the Plan as it shall deem advisable, provided, however, that no such action shall prejudice or diminish any right of any Participant hereunder which shall have theretofore accrued. Other than as expressly set forth herein, the Board of Directors may not amend the Plan if such amendment would increase the cost thereof to the Company other than with the affirmative vote of a majority in interest of the Company's stockholders. ARTICLE XIV INDEMNIFICATION OF COMMITTEE In addition to such other rights of indemnification as they may have as directors or officer's of the Company or as members of the Committee, the members of the Committee shall be indemnified by the Company against the reasonable expenses, including attorney's fees actually and necessarily incurred in connection with the defense of any action, suit or proceeding, or in connection with any appeal therein, to which they or any of them may be a party by reason of any action taken or failure to act under or in connection with the Plan and against all amounts paid by them in settlement thereof (provided such settlement is approved by independent legal counsel selected by the Company) or paid by them in satisfaction of a judgment in any such action, suit or proceeding, except in relation to matters as to which it shall be adjudged in such action, suit or proceeding that such Committee member is liable for willful misconduct in the performance of his duties. ARTICLE XV TERMINATION OF RIGHT OF ACTION Every right of action arising out of or in connection with the Plan by or on behalf of any Participant under the Plan against the Company, or any Committee Member will, irrespective of the place where an action may be brought and irrespective of the place of residence of any such Participant or Committee Member, cease and be barred by the expiration of three years from the date of the act or omission in respect of which such right of action is alleged to have arisen. -5- 6 ARTICLE XVI REGULATORY MATTERS The purchase of Common Stock on behalf of the Participants pursuant to the Plan, the issuance of Common Stock to the Participants pursuant to the Plan and the transfer of Common Stock by participants acquired pursuant to the Plan shall be subject to compliance with the requirements of the Securities Act of 1933, as amended, the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder, the requirements of any stock exchange upon which the Common Stock may then be listed and shall be subject to prior approval by the Company's legal counsel with respect to all legal matters in connection therewith. ARTICLE XVII CONSTRUCTION This Plan shall be construed and enforced in accordance with the laws of the State of Delaware. Approved: ----------------------------- John H. Pinkerton President Dated: June 19, 1997 -6-

1 EXHIBIT 22 LOMAK PETROLEUM, INC. SUBSIDIARIES OF REGISTRANT
PERCENTAGE OF VOTING JURISDICTION OF SECURITIES OWNED BY NAME INCORPORATION IMMEDIATE PARENT ---- --------------- -------------------- Lomak Operating Company Ohio 100% Lomak Production Company Delaware 100% Buffalo Oilfield Services, Inc. Ohio 100% Lomak Energy Services Company Delaware 100% Lomak Resources Company Delaware 100% Eastern Petroleum Company Ohio 100% Lomak Energy Company Delaware 100% Lomak Gathering & Processing Company Delaware 100% Lomak Gas Company Delaware 100% Lomak Financing Trust Delaware 100%
48

1 EXHIBIT 23 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report on the consolidated financial statements of Lomak Petroleum, Inc. for the year ended December 31, 1997, included in this Form 10-K, into the Company's previously filed Registration Statements on Form S-1 File No. 333-08211, Form S-3 File No. 333-23955, Form S-8 File No. 10719, Form S-8 File No. 33-66322, Form S-3 File No. 33-64303, Form S-3 File No. 333-20257, Form S-3 File No. 333-43823 and Form S-8 File No. 333-44821. ARTHUR ANDERSEN LLP Cleveland, Ohio, March 18, 1998. 49

5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM LOMAK PETROLEUM, INC. FINANCIAL STATEMENT INCLUDED IN FORM 10-K AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 1,000 YEAR DEC-31-1997 JAN-01-1997 DEC-31-1997 9,725 8,041 29,200 0 2,779 49,745 876,507 171,146 764,213 54,912 0 0 1150 211 195,589 764,213 149,338 149,338 98,626 98,626 58,700 0 27,175 (35,163) (11,831) (23,332) 0 0 0 (23,332) (1.31) (1.31)