ITEM 1. BUSINESS
GENERAL
Lomak Petroleum, Inc. ("Lomak" or the "Company") is an independent oil and gas company engaged in the acquisition, development, exploration and enhancement of oil and gas properties in the United States. Lomak's core areas of operation are located in Texas, Oklahoma and Appalachia. The Company has grown through a combination of acquisition, development, exploration and enhancement activities. Since January 1, 1990, 60 acquisitions have been consummated at a total cost of approximately $200 million and $24 million has been expended on development and exploration activities. As a result, proved reserves and production have each grown during this period at a rate in excess of 80% per annum. At December 31, 1995, proved reserves totaled 298 Bcfe, having a pre-tax present value at constant prices of $229 million and a reserve life of nearly 12 years.
Lomak's acquisition effort is focused on properties with prices of less than $30 million within its core areas of operation. Management believes these purchases are less competitive than those involving larger property interests. To the extent purchases continue to be made primarily within existing core areas, efficiencies in operations, drilling, gas marketing and administration should be realized. In 1993, Lomak initiated a program to exploit its growing inventory of development projects. In the future, Lomak expects its growth to be driven principally by a combination of acquisitions and development and, to a lesser extent, exploration.
At December 31, 1995, Lomak held interests in 6,596 gross (4,965 net) productive oil and gas wells. The Company currently operates over 6,200 wells which account for more than 93% of its developed reserves. In addition, the Company owns and operates approximately 1,900 miles of gas gathering systems in proximity to its principal gas properties. The Company also provides oil field services, including brine disposal and various well services primarily for certain of its own properties. The operations of the Company are considered to fall within a single industry segment; the exploration for, development and production of crude oil and natural gas.
The Company's common stock is listed on the Nasdaq National Market ("Nasdaq") under the symbol "LOMK". During 1995, trading volume averaged 82,000 shares per day. The Company maintains its corporate headquarters at 500 Throckmorton Street, Fort Worth, Texas 76102 and its telephone number is (817) 870-2601.
DESCRIPTION OF THE BUSINESS
Strategy
The Company's objective is to continue to increase its asset base, cash flow and earnings through a balanced strategy of acquisitions, development, exploration and enhancement activities in core operating areas. In each core area, the Company establishes separate acquisition, engineering, operating, geological and other technical expertise. The Company currently has core operating areas in Texas, Oklahoma and Appalachia. Through its strategy, the Company does not depend solely on any one region or activity to grow its asset base. In addition, by operating in three core areas, the Company has expanded its acquisition, development and exploration opportunities.
Acquisitions. Since 1990, 60 acquisitions have been completed for a total consideration of $200 million. Over 295 Bcfe of proved reserves have been acquired at an average cost of $.63 per Mcfe. The Company's acquisition strategy is based on: (i) Size: targeting smaller, less competitive transactions having a cost below $30 million; (ii) Locale: focusing in areas containing many small oil and gas operators and where larger companies are no longer active; (iii) Efficiency: targeting acquisitions in which operating and cost efficiencies can be obtained; (iv) Reserve Potential: pursuing properties with the potential for reserve increases through recompletions and drilling; (v) Incremental Purchases: seeking acquisitions where opportunities for purchasing additional interests in the same or adjoining properties exist; and (vi) Complexity: pursuing more complex but less competitive corporate or partnership acquisitions.
Development. The Company's development activities include recompletions of existing wells, infield and step-out 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, 1995, over 750 proven development projects were in inventory. These projects are located in eight different fields, vary between oil and gas, and are balanced between low and medium risk. Approximately 100 of these projects are expected to be initiated in 1996 at a total cost of approximately $13 million. Based on the number of projects currently in inventory, development expenditures are currently projected to approximate $45 million over the three year period 1996 through 1998.
Exploration. To date, the Company has concentrated on its acquisition and development activities while building its asset base and cash flow. In the future, exploration activities are expected to be expanded within the Company's core operating areas. These activities are expected to be an extension of the Company's development activities and will be initiated by its in-house technical staff.
Enhancements. The Company's enhancement activities include all activities other than acquisitions, development and exploration which maximize the value of its assets. Enhancements include: reducing overhead, operating and development costs; concentrating operations to increase efficiency; the rapid disposal of non-strategic properties; expanding marketing options; and applying new technology to exploit additional reserves. Enhancements increase margins and help maintain profitability during downward phases of energy price cycles.
Acquisition Activities
Since 1990, the Company has completed 60 acquisitions for $200 million of consideration. During 1995, $71.1 million of purchases were completed. The Company's acquisition strategy is to concentrate on smaller transactions that offer higher expected returns. The Company believes that it can continue to implement its acquisition strategy based on the following:
SIZE: The Company believes that smaller transactions (less than $30 million in cost) provide the opportunity for higher returns due to the limited number of buyers that have the interest, financial capabilities and the operational efficiencies necessary to consummate such transactions. Smaller companies generally do not have sufficient capital or the requisite expertise to engage in such transactions while the larger companies are focusing on other areas, such as overseas operations, or larger transactions. Additionally, because of the continuing restructuring of the domestic oil and gas industry, many small oil and gas entities are for sale and many larger companies are selling their smaller or non-strategic properties. As the Company grows, it may review acquisitions in excess of $30 million, however, the significant portion of its acquisitions are still expected to be $30 million or below.
LOCALE: Focusing on areas containing many small, less capitalized operators. These typically are areas in which many of the major and larger independent companies are no longer active and where, in some cases, they are divesting their remaining assets. The potential for reserve increases in these areas exists through the application of new operating and technical advances.
EFFICIENCY: Targeting acquisitions in which operating and cost efficiencies can be obtained. The Company concentrates on acquiring oil and gas assets in areas in which it already operates and seeks to subsequently merge into its existing infrastructure the overhead functions of companies, partnerships and direct property interests it acquires. Not only does the increased efficiency result in increased profitability, but it also enables the Company to be an aggressive buyer while still generating an attractive return.
RESERVE POTENTIAL: Pursuing properties with the potential for reserve increases through workovers, recompletions, drilling and secondary recovery operations.
INCREMENTAL PURCHASES: Seeking acquisitions where opportunities for purchasing incremental interests in the same or adjoining properties exist. Properties in which the Company currently owns an interest contain over $100 million of estimated value attributable to the reserves for interests held by third parties. The purchase of incremental interests results in only minor increases in overhead cost.
COMPLEXITY: A number of companies and partnerships which own oil and gas assets have been acquired at attractive prices. Due to the added complexity involved in acquiring and integrating these entities and their assets, many buyers do not have the expertise or desire to compete for such acquisitions.
The following table sets forth information pertaining to acquisitions completed during the past six years.
(1) Includes purchase price for proved reserves as well as other acquired assets, including gas gathering lines, undeveloped leasehold and field service assets.
(2) Includes purchase price for proved reserves only.
Development Activities
Development activities include recompletions of existing wells, the drilling of infield and step-out wells and secondary recovery projects. Approximately $3.7, $9.5 and $11.1 million was expended on these activities during 1993, 1994 and 1995, respectively. The Company estimates that it will spend up to $15 million on development activities in 1996. Based on over 750 proven development projects currently in inventory, capital expenditures are currently estimated to be approximately $45 million over the three year period 1996 through 1998.
The Company's development strategy is to own as large an interest as possible in more established, lower risk development projects. Conversely, in development activities that are less established and therefore deemed to be of higher risk, the Company generally seeks to participate for no more than a 50% interest. As more confidence is gained in regard to the higher risk development activities, the Company may increase its ownership percentage.
Texas. At December 31, 1995, Texas accounted for 182 proved development projects. The majority of these projects include recompletions and infield drilling locations in the Big Lake Area of west Texas and the Laura LaVelle Field of east Texas. The production from these two fields is predominantly oil. The Company has performed 29 recompletions and drilled 40 wells in these two fields. As a result of development and additional acquisitions, gross production from the two fields has increased from 500 Boe per day to over 1,850 Boe per day. In 1996, the Company expects to recomplete 12 wells and drill 18 new wells in the two fields at a cost of approximately $2.5 million.
Oklahoma. Essentially all of the 207 Oklahoma proved development projects are in the Okeene Field located in the northwestern portion of the Anadarko Basin. These projects include 133 recompletions and 74 drilling locations. The Company's primary producing area is situated in a four township area that straddles the Blaine-Major County line, with over 250 Company operated wells. The majority of the reserves are gas and are produced from six geologic horizons at depths ranging from 7,000 to 9,000 feet. The Company acquired its interests in the field during the fourth quarter of 1994. In 1996, the Company estimates it will undertake 24 recompletions and drill 9 new wells for approximately $4.0 million. An extensive geologic study of the area has been initiated to further identify additional development opportunities.
Appalachia. In Ohio, Pennsylvania and West Virginia 392 proved development projects have been identified in the shallow Clinton, Medina and Upper Devonian Sandstone formations. These projects are located on 448,000 gross (341,000 net) acres under lease and range in depth from 2,000 to 6,000 feet. The reserves are characterized by initial flush production, followed by extremely gradual decline rates resulting in a projected life of over twenty years. During 1996 the Company estimates that it will recomplete 10 wells and drill 30 new wells at a cost of approximately $4.0 million. The Company currently has a sufficient inventory of proved infield drilling locations to drill over 75 wells per year over the next five years.
In addition to the shallow formations discussed above, the Appalachian Basin has less developed formations including the Rose Run-Beekmantown and Trempealeau which range in depths from 4,000 to 8,000 feet. The geological boundaries of these formations lie approximately 2,500 feet below the shallower Clinton and Medina Sandstone formations. While the industry has drilled over 100,000 Clinton and Medina Sandstone wells, fewer than 1,700 wells have been drilled to the Rose Run-Beekmantown and 5,000 wells to the Trempealeau. The industry's initial results were poor because the wells were based strictly upon regional geology and limited seismic data was utilized. However, more recent activities using modern seismic technologies have significantly improved the returns from these deeper zones. Since 1993, the Company has participated in 29 deeper wells with an average working interest of 11%, of which, 16 were productive and 13 were dry. Currently, the Company owns leases covering 318,000 gross (237,000 net) acres in the deeper "Rose Run Trend." The Company's 1996 budget allocates approximately $2 million to acquire acreage and seismic and to drill wells in this area.
Enhancement Activities
The Company defines enhancements as those activities, other than acquisitions or drilling, which maximize the value of its asset base. Enhancements include: reducing overhead, operating and development costs on a per Mcfe basis; concentrating operations to increase efficiency; disposing non-strategic properties rapidly; expanding marketing options; and applying new technology to exploit additional reserves. Enhancements create higher margins and help maintain profitability during the downward phase of energy price cycles. Despite low oil and gas prices in recent years, the Company posted increased cash flow and profits, partly due to enhancements. Primarily as a result of its enhancement activities during the past five years the Company has: (i) decreased overhead costs per Mcfe by 89%; (ii) cut operating costs per Mcfe by 30%; (iii) reduced development costs per Mcfe by 31%; (iv) now operates properties representing more than 93% of its reserves; (v) sold over 1,000 non-strategic properties; (vi) expanded gas marketing to neraly 90 MMcf per day through 1,900 miles of Company-owned gas gathering systems; and (vii) improved seismic and completion techniques by applying new technology.
Production
Production revenue is generated through the sale of oil and gas from properties held directly and through partnerships and joint ventures. Additional revenue is received from royalties. While oil and gas production is sold to a limited number of purchasers, it is believed that the loss of any one of them 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. There has been a worldwide surplus of oil and gas for more than a decade which has weakened oil prices and depressed the price of natural gas. 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 may continue to have, an unpredictable 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).
(a) Oil is converted to Mcfe at a rate of 6 Mcf per barrel.
On a Mcfe basis, approximately 69% of 1995 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 1995, revenues from oil and gas production amounted to $37.4 million, representing 72% of revenues. Oil and gas revenues for 1995 increased 53% over 1994.
Field Services
The field services area is comprised of three components -- well operations, brine disposal and well servicing. As of December 31, 1995, Lomak acted as operator of, or provided pumping services for, over 6,200 wells. Lomak performs virtually all day-to-day services required by these operations, rather than subcontracting them. For its services, Lomak receives a monthly fee plus reimbursement of third party charges.
Prior to 1995, Lomak conducted brine disposal and well servicing operations on its properties as well as for third parties primarily in Ohio and to a lesser extent in Pennsylvania and Texas. In 1994, Lomak sold substantially all of brine disposal and well servicing assets located in Ohio. Through an acquisition completed in early 1995, the Company began conducting brine disposal and well services in Oklahoma.
Gas Transportation and Marketing
The gas transportation and marketing revenues are comprised of fees for the transportation of production through gathering lines and, to a lesser extent, income from marketing of oil and gas. In 1994, the Company began to take a more active role in marketing both its oil and gas production. As a result, at year end 1995, the Company was marketing approximately 90 MMcfe per day, including its production and the production of third parties. Gas transportation and marketing revenues were $2.2 and $3.3 million for 1994 and 1995, respectively.
The Company has currently hedged through the financial markets less than 3% of its monthly production through September 1996. These hedges involve fixed price arrangements and other price arrangements at a variety of prices, floors and caps. 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. In the future, the Company may increase the percentage of its production covered by hedging arrangements, however, it currently anticipates that such percentage would not exceed 50%.
The Company prefers to hedge its gas production through fixed price gas contracts. At December 31, 1995, approximately 42% of the Company's gas production was under fixed priced arrangements. These contracts vary in length from one year to the life-of-the-well. A majority of the contracts are for three years or less. Essentially all these contracts are with industrial end-users and utilities.
In total, field services provided revenues of $10.1 million in 1995, representing 19% of total revenues. Field service revenues for 1995 increased 32% over the prior year.
Interest and Other
The Company earns interest on its cash and investment accounts, as well as on various notes receivable. Other income in 1995 was comprised principally of gains on sales of non-strategic properties and various fees charged to third parties. The Company expects to continue to sell assets which have no strategic benefit. Interest and other income in 1995 amounted to $1.3 million, representing 3% of total revenues. Revenues from interest and other for 1995 increased 180% from the 1994 level.
COMPETITION
The Company encounters substantial competition in acquiring properties, marketing oil and gas, securing personnel and conducting its field services operations. Many competitors have financial and other resources which substantially exceed those of the Company. The competitors in acquisitions, development, exploration 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. The competition for capital to finance oil and gas acquisitions and drilling is intense. 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.
EMPLOYEES
As of December 31, 1995, the Company had 281 full time employees, 198 of whom were field personnel. None are covered by a collective bargaining agreement and management believes that its relationship with its employees is good.
SUBSEQUENT EVENTS
In February 1996, the Company completed three oil and gas property acquisitions for $17.5 million of consideration. The properties are located in Lomak's core operating areas of Appalachia and Texas. In aggregate, the acquisitions are estimated to contain proved reserves of 20.2 Bcf of gas and 240,000 barrels of oil, or 21.6 Bcfe in total.
ITEM 2.

ITEM 2. PROPERTIES
On December 31, 1995, the Company's properties included working interests in 6,596 gross (4,965 net) productive oil and gas wells and royalty interests in 614 additional wells. The properties contained, net to the Company's interest, estimated proved reserves of 10.9 million barrels of oil and 232.9 Bcf of gas or a total of 298 Bcfe. The Company also held interests in 311,200 gross (225,100 net) undeveloped acres at year end.
PROVED RESERVES
The following table sets forth as of December 31 estimated proved reserves for the preceding five years.
Proved developed reserves are expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty. On a Mcfe basis, approximately 77% of the Company's proved reserves were developed at December 31, 1995. Approximately 93% of the proved reserves set forth above were engineered by independent petroleum consultants, while the remaining 7% was evaluated by the Company's engineering staff.
The following table sets forth as of December 31, 1995 the estimated future net cash flow from and the present value of the proved reserves. 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 on December 31, 1995. Average product prices in effect at December 31, 1995 were $18.14 per barrel of oil and $2.28 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, 1995.
SIGNIFICANT PROPERTIES
Until 1990, virtually all of the Company's properties were located in Ohio. Since that time, properties have been acquired in Texas and Oklahoma and other areas of Appalachia. At December 31, 1995, on a pre-tax present value basis, 49% of the reserves were located in Appalachia, 25% were in Texas and 22% were in Oklahoma. The Company also held interests in 272,200 gross (211,200 net) undeveloped acres at December 31, 1995. The following table sets forth information with respect to the Company's estimated proved oil and gas reserves as of December 31, 1995.
The largest concentration of reserves is in Appalachia with 49% of total present value. On an Mcfe basis, gas accounts for approximately 96% of these reserves. These reserves are ascribed to over 5,200 wells located in Pennsylvania, Ohio, West Virginia and New York. The Company operates nearly all of these wells. The reserves produce principally from the Medina, Clinton, Upper Devonian and Rose Run formations at depths of 3,000 to 7,000 feet. After initial flush production, these properties are characterized by extremely gradual decline rates and often have a projected life of more than twenty years. Gas production is transported through Company-owned gas gathering systems and is sold primarily to utilities and industrial end-users.
The second largest concentration of reserves is in Texas, totaling 25% of present value. On an Mcfe basis, oil makes up 67% of the reserves. The largest portion of these reserves is ascribed to 354 operated wells in the Big Lake Area of west Texas. These wells produce from the San Andres/Grayburg formation at a depth of approximately 2,500 feet. The properties have a projected remaining life of over 25 years. Over 80% of these reserves are oil. Oil production is sold to Scurlock Permian and gas to J.L. Davis Company. The second largest portion of these reserves are ascribed to 93 operated wells in the Laura LaVelle Field in east Texas. These wells produce from the shallow Carrizo section of the Wilcox formation at a depth of approximately 1,600 feet. These properties have a projected remaining life of twenty years. All of the reserves are oil and production is sold to Texaco. The third largest portion is in Hagist Ranch Field in south Texas. The Company operates 62 wells in this field which produces primarily from the Wilcox at approximately 8,000 feet. Arco purchases the gas production from the Hagist Ranch Field.
The third largest concentration of reserves is in Oklahoma, totaling 22% of present value. On an Mcfe basis, gas makes up 83% of these reserves. The largest portion of these reserves is ascribed to over 257 operated wells in and around the Okeene Field of the Anadarko Basin. These wells produce from numerous formations ranging in depth from approximately 6,000 to 9,000 feet. The properties have a projected remaining life of over fifteen years. Gas production is sold primarily to Phillips Petroleum and Natural Gas Clearinghouse on an index or percent of plant proceeds basis.
PRODUCTION
The following table sets forth production information for the preceding five years (in thousands, except average sales price and operating cost data).
(a) Oil is converted to Mcfe at a rate of 6 Mcf per barrel.
PRODUCING WELLS
The following table sets forth certain information relating to productive wells at December 31, 1995. The Company owns royalty interests in an additional 614 wells. Wells are classified as oil or gas according to their predominant production stream.
ACREAGE
The following table sets forth the developed and undeveloped acreage held at December 31, 1995.
DRILLING RESULTS
The following table summarizes drilling activities for the preceding three years.
REAL PROPERTY
The Company's primary office facilities are located in Ft. Worth, Texas, Hartville, Ohio and Oklahoma City, Oklahoma. These offices total approximately 40,000 square feet of which 60% is owned with the remainder leased. The Company also owns a number of smaller field offices in proximity to its areas of operations. The office leases are standard arrangements expiring at various times through September 1996. 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.

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 material adverse effect on the Company's financial position.
ITEM 4.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5.

ITEM 5. MARKET FOR THE COMMON STOCK AND RELATED MATTERS
The Company's Common Stock is listed on Nasdaq under the symbol "LOMK". During 1995, trading volume averaged 82,200 shares per day. The stock prices below are based on the last trade price.
DIVIDENDS
Dividends of $.01 per share were initiated on the Common Stock in December 1995. The 7-1/2% Convertible Preferred Stock receives cumulative quarterly dividends at the annual rate of $1.875 per share. The $2.03 Convertible Preferred Stock receives cumulative quarterly dividends at the annual rate of $2.03 per share.
The Company currently retains substantially all of its earnings to support the development of its business. Any future determination as to the payment of dividends will be at the discretion of the Board of Directors of the Company, and will depend on the Company's financial condition, results of operations and capital requirements, and such other factors as the Board of Directors deems relevant. In addition, the Company's bank credit facility limits the amount of cash dividends that can be paid in one year to 75% of the Company's net income, plus the cumulative net proceeds from all equity offerings completed after January 1, 1996.
HOLDERS OF RECORD
At December 31, 1995, the number of holders of record of the Common Stock, 7-1/2% Convertible Preferred Stock and $2.03 Convertible Preferred Stock were 5,062, 48 and 17, respectively.
On March 11, 1996, the closing price of the Common Stock was $10.50. To date in 1996, trading volume has averaged 154,000 shares per day.
ITEM 6.

ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected financial information covering the preceding five years.
The following table sets forth summary unaudited financial information on a quarterly basis for the past two years (in thousands, except per share data).
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.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FACTORS EFFECTING FINANCIAL CONDITION AND LIQUIDITY
LIQUIDITY AND CAPITAL RESOURCES
The Company's financial position continues to strengthen. The Company had working capital of $4.4 million at December 31, 1995 compared to $1.0 million at December 31, 1994. The Company had cash and cash equivalents of $3.0 million at year end 1995. The Company's primary sources of cash in 1995 consisted of (i) operating cash flow of $21.5 million (net income plus deferred taxes, depreciation, depletion and amortization and exploration expense); (ii) proceeds from the sale of preferred stock of $27.8 million; (iii) proceeds from the sale of common stock of $10.6 million; and, (iv) proceeds from the issuance of long-term debt of $21.3 million. The Company's primary uses of cash in 1995 consisted of (i) acquisitions of oil and gas properties of $67.1; (ii) capital expenditures for development and exploration activities of $10.2; (iii) payments on long-term debt of $808,000 and (iv) dividend payments of $859,000.
The Company has three principal operating sources of cash: (i) sales of oil and gas, (ii) revenues from field services and (iii) revenues from gas transportation 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 estimated reserves that would result in decreased funds available, including funds intended for planned capital expenditures.
Virtually all oil and gas properties are subject to production declines over time. Through acquisitions, the Company has increased its reserves in each of the last six years. It is anticipated that the Company will continue to build reserves primarily through acquisitions and development over the next several years. The profitability of production and, to a lesser extent, other areas of the Company's business are influenced by energy prices.
The Company funds its short-term working capital requirements through cash flow provided by operations and borrowings under its bank credit facility. The bank credit facility provides for a maximum capacity of $250 million and has a borrowing base which is subject to semi-annual redeterminations. At December 31, 1995, the borrowing base on the credit facility was $105 million and $22 million was available under the facility. The Company's ratio of total debt to total capitalization was 45.6% at December 31, 1995, down from 56.3% at December 31, 1994. Total capitalization is defined by the Company as the sum of long-term debt, minority interest and stockholders' equity. The increase in the Company's long-term debt in recent years is due to acquisition and development activities. As of December 31, 1995, only $53,000 of long-term debt matures within one year.
During 1995, the Company sold 1,150,000 shares of preferred stock and 1,319,000 shares of common stock for total net proceeds of $38.4 million. In addition, 2.3 million shares of common stock were issued in completion of the acquisition of the Company's Oklahoma operating unit. The proceeds from the sale of stock were used to repay the bank credit facility.
Management believes that, in addition to current financial resources, adequate financial resources are available to satisfy the Company's acquisition, development and enhancement programs. Such sources of capital would include, but not be limited to, bank borrowings and the issuance of equity and debt securities.
CAPITAL EXPENDITURES
During 1995, the Company acquired oil and gas properties, gas transportation and field service assets for $71.1 million. Additionally, the Company incurred capital expenditures for development and exploration activities of $10.2 million. In total, $79.4 million of capital expenditures were incurred in 1995, versus $69.2 million in 1994. The Company currently estimates that capital expenditures for acquisition and development activities will range from $50 million to $75 million in 1996. All of these expenditures are discretionary and could increase or decrease based upon the level of activity and the availability of capital.
The only material requirements for capital during the next twelve months are $2.7 million of preferred stock dividends, interest payments on the Company's credit facility and $53,000 of debt payments. Working capital and cash flow from operations will be more than sufficient to fund these expenditures. Excess funds will be used to help fund acquisitions and development activities.
In March 1996, the Company's Board of Directors approved resolutions authorizing the Company to repurchase shares of its Common Stock from odd-lot holders. The Company will acquire any and all shares from stockholders owning 99 or fewer shares for cash at market prices. Additionally, the Board of Directors approved a dividend of $.01 per share to holders of its Common Stock to be paid on March 29, 1996.
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 1995, the Company received an average of $16.57 per barrel of oil and $1.79 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 1995. Should conditions in the industry improve, inflationary cost pressures may resume.
RESULTS OF OPERATIONS
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 49,172 Mcfe per day. 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 49% to $14.9 million in 1995 versus $10.0 million in 1994. However, the average operating cost per Mcfe produced decreased 11% from $.93 in 1994 to $.83 in 1995.
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.
Field services revenues increased 32% in 1995 to $10.1 million, despite the September 1994 sale of virtually all well servicing and brine disposal assets in Ohio. The decrease in activities due to this sale was more than offset by an increase in well servicing and brine disposal activities in Oklahoma and well operations on acquired properties. Field services expenses increased 12% in 1995 to $6.5 million versus $5.8 million. The increase is attributed to the Oklahoma well servicing and the cost of operating a larger base of properties. The increase in well operating costs was offset to a great extent by the disposal in September 1994 of the Company's lower margin well servicing and brine hauling and disposal businesses.
Exploration expense increased 43% to $512,000 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 5% in 1995 as compared to 7% in 1994. This decreasing trend 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 credit facility were $42.0 million and $73.3 million for 1994 and 1995, respectively. The weighted average interest rate on these borrowings were 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, depreciation and amortization rate for 1995 was $.83 per Mcfe versus $.93 in 1994.
Comparison of 1994 to 1993
The Company reported net income for the year ended December 31, 1994 of $2.6 million, an 88% increase over 1993 net income. This increase can be attributed primarily to the realization of income from properties acquired in the fourth quarter of 1993 and in 1994, as well as the success of the 1994 drilling program.
During the year, oil and gas production volumes increased 141% to 10.8 MMcfe, an average of 29,680 Mcfe per day. The increased revenues recognized from production volumes were partially offset by a 9% decrease in the average price received per Mcfe of production to $2.26. The average oil price decreased 5% to $15.23 per barrel and average gas prices dropped 9% to $2.10 per Mcf. As a result of the Company's larger base of producing properties and production, oil and gas production expenses increased 126% to $10.0 million in 1994 versus $4.4 million in 1993. However, the average operating cost per Mcfe produced decreased 5% from $0.98 in 1993 to $0.93 in 1994.
Gas transportation and marketing revenues rose almost four fold to $2.2 million versus $0.6 million in 1993. Coupled with this increase in gas transportation and marketing revenues was an increase in associated expenses for the year. These increases were due primarily to the acquisition of several pipeline systems in late 1993, as well as the expansion of the gas marketing efforts.
Field services revenues increased in 1994, despite the September 1994 sale of virtually all well servicing and brine hauling and disposal assets in Ohio. The decrease was offset by a marked increase in well operating revenues recognized on acquired properties. Field services expenses increased marginally in 1994 to $5.8 million versus $5.7 million. The slight increase can be attributed to the cost of operating a growing base of properties. The increase in well operating costs was offset to a great extent by the disposal in September 1994 of the Company's low-margin well servicing and brine hauling and disposal businesses.
Exploration expense increase four-fold due to the Company's increased involvement in drilling projects. The results of these costs can be seen in the increase in production due partially to its 1994 drilling program.
General and administrative expenses increased 21% from $2.0 million in 1993 to $2.5 million in 1994. As a percentage of revenues, general and administrative expenses were 7% in 1994 as compared to 11% in 1993. This decreasing trend reflects the spreading of administrative costs over a growing asset base.
Interest and other income rose 13% primarily due to a higher level of non-strategic property sales. Interest expense increased 151% to $2.8 million as compared to $1.1 million in 1993. This was as a result of the higher average outstanding debt balance during the year due to the financing of acquisitions and rising interest rates.
Depletion, depreciation and amortization increased 132% compared to 1993 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 September 1994 sale of field service assets.
Comparison of 1993 to 1992
Total revenue for 1993 rose 37% to $19.1 million compared to $13.9 million in 1992. Net income increased 103% from $686,000 in 1992 to $1,391,000 in 1993. The increases in revenues and net income was due primarily to higher oil and gas volumes from acquisitions. The earnings increase was partially offset by higher operating expenses and increased depletion associated with higher production volumes.
Oil production averaged 872 barrels per day, an increase of 60% from 1992. The average oil price received for 1993 was $16.07 per barrel compared to $18.40 for 1992. Average daily gas production was 7,095 Mcf in 1993 versus 4,921 Mcf in the prior year, a 44% increase. Gas prices averaged $2.32 per Mcf, $.07 higher than 1992. Production operating expenses increased to $4.5 million during 1993 compared to $3.1 million during 1992 due to higher volumes. The average operating cost (including production taxes) was $0.98 per Mcfe, slightly less than the prior year figure.
Field service revenues rose to $7.0 million in 1993, a 32% increase compared to 1992. The increase was primarily the result of operating more oil and gas properties during 1993 and a full year's operations of Wellworks, Inc. ("Wellworks") versus one-half year of operations in 1992. Field service expenses increased 45% reflecting the higher expense ratio of well servicing.
Interest and other income decreased 28% to $418,000 in 1993. The lower revenues were principally due to a lower level of property dispositions. Interest expense increased 18% to $1,120,000 as a result of a higher average outstanding debt balance from acquisitions. General and administrative expenses increased 7% and as a percentage of revenues was 11% in 1993 versus 14% in 1992. The reduction reflects cost efficiencies as well as higher cost reimbursements. Depletion, depreciation and amortization increased 39% in 1993 from the prior year principally due to increased oil and gas production volumes. The depletion rate in 1993 was $0.74 per Mcfe compared to $0.76 for 1992.
ACCOUNTING STANDARDS
In March 1995, the Financial Standards Board (FASB) issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." This standard requires the review of long-lived assets for impairment. Although the Company in the past has routinely reviewed its oil and gas assets for impairment, the new accounting rules may require a different grouping which may affect the amount of impairment, if any. SFAS No. 121 is required to be adopted for financial statements with fiscal years beginning after December 15, 1995 and allows the cumulative effect of the accounting change to be reported in net income in the year of adoption. The Company is currently reviewing the accounting standard and has not yet determined the effect, if any, on its consolidated financial position or results of operations.
In October 1995, FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation." This standard requires an audited pro forma footnote disclosure of what net income and earnings per share would have been for the Company based upon valuing employee options and other stock based compensation, at their estimated fair value using an option pricing model. SFAS No. 123 is required to be adopted for financial statements with fiscal years beginning after December 15, 1995. The Company is currently reviewing the accounting standard and has not yet determined the effect, if any, on its financial statements.
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Reference is made to the Index to Financial Statements on page 26 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. 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.

ITEM 9. CHANGE IN ACCOUNTANTS AND DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
The information required by Item 304 of Regulation S-K regarding changes in accountants was previously filed on Form 8-K dated May 25, 1994.
PART III
ITEM 10.

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 1995 annual meeting of stockholders. Executive officers are appointed by the Board of Directors.
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. Since 1981, Mr. Edelman has been a director and President of Snyder Oil 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 is also a director of Petroleum Heat & Power Co., Inc., a Connecticut based fuel oil distributor, Star Gas Corporation, a private company which distributes propane gas, Amerac Energy Corporation, a public domestic exploration and production company, and Command Petroleum Limited, an international exploration and production company affiliated with Snyder Oil Corporation.
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 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.
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.
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.
ANTHONY V. DUB, was elected to serve as a Director of the Company in 1995. Mr. Dub is Managing Director-Senior Advisor of CS First Boston, an international investment banking firm with headquarters in New York City. Mr. Dub joined CS First Boston in 1971 and was named a Managing Director in 1981. Mr. Dub received his Bachelor of Arts Degree from Princeton University in 1971.
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 of Akron, Ohio, a public company serving the beverage dispensing and fast food industries.
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 of Shreveport, Louisiana. 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.
STEVEN L. GROSE, Vice President-Appalchia 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. Mr. Grose received his Bachelor of Science Degree in Petroleum Engineering from Marietta College.
CHAD L. STEPHENS, Vice President-Midcontinent Region, joined the Company in 1990. Previously, Mr. Stephens was a landman 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 a landman for 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, Vice President - Finance and Chief Financial Officer, 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.
JOHN R. FRANK, Controller and Chief Accounting Officer, joined the Company in 1990. From 1989 until he joined Lomak in 1990, Mr. Frank was Vice President Finance of Appalachian Exploration, Inc. Prior thereto, he held the positions of Internal Auditor and Treasurer with Appalachian Exploration, Inc. beginning in 1977. Mr. Frank received his Bachelor of Arts Degree in Accounting and Management from Walsh College and attended graduate studies at the University of Akron.
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 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 practices of Lomak. This Committee also considers nominations of candidates for corporate officer positions. The members of 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.

ITEM 11. COMPENSATION OF EXECUTIVE OFFICERS AND DIRECTORS
Information with respect to executive compensation is ]incorporated herein by reference to the Proxy Statement for its 1996 annual meeting of stockholders.
ITEM 12.

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 1996 annual meeting of stockholders.
ITEM 13.

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 1996 annual meeting of stockholders.
PART IV
ITEM 14.

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.
November 8, 1995 - Acquisition of Transfuel Interests for $20.2 million and $755,000 in Lomak common stock. The acquisition includes approximately 1,800 producing gas wells, 1,100 miles of gathering lines, 175,000 net acres of undeveloped leases and associated real estate and equipment.
(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.
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 19, 1996
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, March 19, 1996 Chairman and Chairman of the Board
/s/ John H. Pinkerton - ------------------------ John H. Pinkerton, March 19, 1996 Chief Executive Officer, President and Director
/s/ Thomas W. Stoelk - ------------------------ Thomas W. Stoelk, March 19, 1996 Chief Financial Officer and Vice President-Finance
/s/ John R. Frank - ------------------------ John R. Frank, March 19, 1996 Chief Accounting Officer and Controller
/s/ Robert E. Aikman - ------------------------ Robert E. Aikman, Director March 19, 1996
/s/ Allen Finkelson - ------------------------ Allen Finkelson, Director March 19, 1996
/s/ Anthony V. Dub - ------------------------ Anthony V. Dub, Director March 19, 1996
/s/ Ben A. Guill - ------------------------ Ben A. Guill, Director March 19, 1996
/s/ C. Rand Michaels - ------------------------ C. Rand Michaels March 19, 1996 Vice Chairman and Director
LOMAK PETROLEUM, INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SCHEDULES
(ITEM 14[A], [D])
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.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
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, 1994 and 1995, and the related consolidated statements of income, stockholders' equity and cash flows for the years then ended. 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, 1994 and 1995, and the results of its operations and its cash flows for the years then ended, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Cleveland, Ohio, February 27, 1996
REPORT OF INDEPENDENT AUDITORS
THE BOARD OF DIRECTORS AND STOCKHOLDERS LOMAK PETROLEUM, INC.
We have audited the consolidated statements of income, stockholders' equity and cash flows of Lomak Petroleum, Inc. for the year ended December 31, 1993. 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 audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements of Lomak Petroleum, Inc. referred to above present fairly, in all material respects, the consolidated results of its operations and its cash flows for the year ended December 31, 1993, in conformity with generally accepted accounting principles.
As discussed in Note 10 to the consolidated financial statements, in 1993 the Company changed its method of accounting for income taxes.
ERNST & YOUNG LLP
Cleveland, Ohio March 8, 1994
LOMAK PETROLEUM, INC.
CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT PER SHARE DATA)
SEE ACCOMPANYING NOTES.
LOMAK PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER SHARE DATA)
SEE ACCOMPANYING NOTES.
LOMAK PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
SEE ACCOMPANYING NOTES.
LOMAK PETROLEUM, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
SEE ACCOMPANYING NOTES.
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 the acquisition, development, exploration and enhancement of oil and gas properties in the United States. Lomak's core areas of operation are located in Texas, Oklahoma and Appalachia. The Company has grown through a combination of acquisition, development, exploration and enhancement activities. Since January 1, 1990, 60 acquisitions have been consummated at a total cost of approximately $200 million and approximately $24 million has been expended on development and exploration activities. As a result, proved reserves and production have each grown during this period at a rate in excess of 80% per annum. At December 31, 1995, proved reserves totaled 298 Bcfe, having a pre-tax present value at constant prices on that date of $229 million and a reserve life of nearly 12 years.
Lomak's acquisition effort is focused on properties with prices of less than $30 million within its core areas of operation. Management believes these purchases are less competitive than those involving larger property interests. To the extent purchases continue to be made primarily within existing core areas, efficiencies in operations, drilling, gas marketing and administration should be realized. In 1994, Lomak initiated a program to exploit its inventory of over 500 development projects. In the future, Lomak expects its growth to be driven principally by a combination of acquisitions and development and, to a lesser extent, exploration.
(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 properties. Temporary investments with an initial maturity of ninety days or less are considered cash equivalents.
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 six Mcf per barrel. The depletion rates per Mcfe were $.74, $.74 and $.73 in 1993, 1994 and 1995, respectively. Approximately $5.3 million, $12.9 million and $12.2 million of oil and gas properties were classified as proved undeveloped or unproved and, therefore, not subject to depletion as of December 31, 1993, 1994 and 1995, respectively. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the excess costs are charged to expense.
GAS TRANSPORTATION AND FIELD SERVICE ASSETS
The Company owns and operates approximately 1,900 miles of gas gathering lines in proximity to its principal gas properties. Depreciation is calculated on the straight-line method based on estimated useful lives ranging from four to fifteen 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 six years, except for buildings which are being depreciated over ten to twenty-five year periods.
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
In September 1994, the Company sold substantially all of its brine disposal and well servicing assets located in the Appalachian region for approximately $1.8 million. Through an acquisition completed in early 1995, the Company began conducting brine disposal and well services in Oklahoma.
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 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 the Company's ability to obtain the necessary capital through operating cash flow, additional borrowings or additional equity funds.
FINANCIAL INSTRUMENTS
The Company's financial instruments include cash and equivalents, accounts receivable, accounts payable and debt obligations. 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 the bank's prime rate or 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.
Interest rate swap agreements, which are used by the Company in the management of interest exposure, is accounted for on an 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, 1995, the Company had $40 million of borrowings subject to two swap agreements at rates of 6.25% and 6.49% through July 12, 1999 and October 12, 1999, respectively.
The Company uses futures, option and swap contracts to reduce the effects of fluctuations in crude oil and natural gas prices. At December 31, 1995, the Company had open contracts for natural gas price swaps in the amount of 360,000 MMbtu's. These contracts expire monthly through September 1996. The resulting transaction gains and losses are included in net income and are determined monthly. Net gains for the year ended December 31, 1995 approximated $221,000 relating to these derivatives.
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
ACCOUNTING STANDARDS
In March 1995, the Financial Standards Board (FASB) issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." This standard requires the review of long-lived assets for impairment. Although the Company in the past has routinely reviewed its oil and gas assets for impairment, the new accounting rules may require a different grouping which may affect the amount of impairment, if any. SFAS No. 121 is required to be adopted for financial statements with fiscal years beginning after December 15, 1995 and allows the cumulative effect of the accounting change to be reported in net income in the year of adoption. The Company is currently reviewing the accounting standard and has not yet determined the effect, if any, on its consolidated financial position or results of operations.
In October 1995, FASB issued SFAS No. 123, "Accounting for Stock-Based Compensation." This standard requires an audited pro forma footnote disclosure of what net income and earnings per share would have been for the Company based upon valuing employee options and other stock based compensation, at their estimated fair value using an option pricing model. SFAS No. 123 is required to be adopted for financial statements with fiscal years beginning after December 15, 1995. The Company is currently reviewing the accounting standard and has not yet determined the effect, if any, on its financial statements.
EARNINGS PER COMMON SHARE
Net income per share is computed by subtracting preferred dividends from net income and dividing by the weighted average number of common and common equivalent shares outstanding. The calculation of fully diluted earnings per share assumes conversion of convertible securities when the result would be dilutive. Outstanding options and warrants are included in the computation of net income per common share when their effect is dilutive.
RECLASSIFICATIONS
Certain reclassifications have been made to prior period presentation to conform with current period classifications.
(3) ACQUISITION AND DEVELOPMENT
Since 1990, the Company has acquired $200 million of oil and gas properties and field service assets. During 1995, the Company completed $71.1 million of acquisitions. The purchases were funded by working capital, advances under a revolving credit facility and the issuance of common stock. These acquisitions are discussed below.
1995 ACQUISITIONS
APPALACHIA
Transfuel, Inc. In September 1995, the Company acquired proved oil and gas reserves, 1,100 miles of gas gathering lines and 175,000 undeveloped acres in Ohio, Pennsylvania and New York from Transfuel, Inc. for $20.2 million and approximately $800,000 of Common Stock.
Parker & Parsley Petroleum Company. In August 1995, the Company purchased proved oil and gas reserves, 300 miles of gas gathering lines and 16,400 undeveloped acres in Pennsylvania and West Virginia from Parker & Parsley Petroleum Company for $20.2 million.
Interests in approximately 470 Company operated properties in Pennsylvania and Ohio were purchased for $5.4 million.
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
OKLAHOMA - --------
The Company purchased interests in 52 wells in the Caddo and Canadian counties for $4.8 million. The Company assumed operation of half of these wells.
Interests in Company operated properties were acquired for $3.2 million.
TEXAS - -----
The Company purchased interests in 140 wells located primarily in the Big Lake Area of west Texas and the Laura LaVelle Field of east Texas for $2.8 million.
1994 ACQUISITIONS
OKLAHOMA - --------
Red Eagle Resources Corporation. In December 1994, the Company acquired effective control of Red Eagle principally through the purchase of two common stockholders' holdings. In February 1995, the remaining stockholders of Red Eagle common stock voted to approve the merger of Red Eagle with a wholly owned subsidiary of the Company in exchange for approximately 2.2 million shares of the Company's common stock. The additional equity of Red Eagle acquired in February 1995 is reflected as minority interest on the Company's balance sheet at December 31, 1994. Acquisition costs of approximately $46.5 million have been capitalized in regards to this acquisition. Red Eagle's assets included interests in approximately 370 producing wells located primarily in the Okeene Field of Oklahoma's Anadarko Basin. Subsequently, the Company acquired additional interests in 70 Red Eagle wells for $1.7 million.
TEXAS - -----
Grand Banks Energy Company. The Company purchased Grand Banks for $3.7 million. Grand Banks' assets included interests in 182 producing wells located in west Texas, essentially all of which are now operated by the Company. Grand Banks owned an average working interest of 70% in the producing reserves, of which 60% was oil. Approximately 40% of Grand Banks' proved reserves are attributed to the Mills-Strain Unit located in the Sharon Ridge Field of Mitchell County, Texas. The Mills-Strain Unit is a waterflood unit producing from the Clearfork Formation at a depth of approximately 2,000 feet. The Mills-Strain Unit has a remaining life of over 20 years. The Company also purchased, for $1.2 million, additional interests in a number of the Grand Banks properties.
Gillring Oil Company. The Company acquired Gillring for $11.5 million. Gillring's assets included $5.2 million of working capital and interests in 106 producing oil and gas wells located in south Texas. Gillring owned an average working interest of 80% in the producing reserves of which 80% were gas. The Gillring properties are located principally in two fields producing from the Wilcox and Vicksburg formations ranging in depths from 4,000 to 11,000 feet. Subsequent to the purchase of Gillring, the Company acquired, for $2.1 million, the limited partner interests and associated debt of a partnership for which Gillring acted as general partner.
The Company acquired from four parties interests in 118 producing wells in the Big Lake Area of west Texas and the Laura LaVelle Field of east Texas for $6.5 million.
APPALACHIA - ----------
The Company acquired, for $5.0 million, interests in 98 new wells and additional interests in 436 wells which the Company already operated.
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
1993 ACQUISITIONS
APPALACHIA - ----------
Mark Resources Corporation. In December 1993, the Company acquired Mark for approximately $28.4 million. Mark's assets were located primarily in the Meadville Area of the Appalachian Basin. Mark owned interests in 655 producing wells, 230 miles of gas gathering lines and over 180 proven drilling locations. Mark operated nearly all of its properties.
Ohio Trend Area. The Company acquired interests in 119 wells and over 70 miles of gas gathering systems in Ohio for $2.9 million.
Meadville Area. The Company acquired interests in 274 wells, one disposal facility and various undeveloped leaseholds for $2.5 million.
TEXAS - -----
Big Lake Area. The Company acquired from three parties interests in 84 producing wells in the Big Lake Area of west Texas for $4.2 million.
Laura LaVelle Field. The Company acquired interests in 7,734 gross (7,524 net) acres in the Laura LaVelle Field located in east Texas for $2.5 million. The Company assumed operations of 44 producing wells.
UNAUDITED PRO FORMA FINANCIAL INFORMATION
The following table presents unaudited, pro forma operating results as if the transactions had occurred at the beginning of each period presented. The pro forma operating results include the following acquisitions, all of which were accounted for as purchase transactions; (i) the purchase of Grand Banks Energy Company, (ii) the purchase of Gillring Oil Company, (iii) the purchase of Red Eagle Resources Corporation, (iv) the purchase by the Company of certain oil and gas properties from a subsidiary of Parker & Parsley Petroleum, Co., (v) the purchase by the Company of certain oil and gas properties from Transfuel, Inc., (vi) the private placement of 1.15 million shares of Convertible Preferred Stock and the application of the net proceeds therefrom and (vii) the private placement of 1.2 million shares of Common Stock and the application of the net proceeds therefrom.
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 acquisition been made at the beginning of each period presented or to necessarily be indicative of future operations. Included in the 1994 pro forma financial information are revenues regarding partnership activities which contributed $0.22 per share. These same activities did not occur in 1995.
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
(4) NOTES RECEIVABLE
In 1994, the Company issued $165,000 in notes receivable to three of its officers in connection with their exercise of stock options. The notes accrued interest at the prime rate plus 1% payable quarterly. In 1995, the notes were repaid.
(5) INDEBTEDNESS
The Company had the following debt outstanding as of the dates shown. Interest rates at December 31, 1995 are shown parenthetically:
The Company maintains a $250 million revolving bank credit facility. The facility provides for a borrowing base which is subject to semi-annual redeterminations. At December 31, 1995, the borrowing base on the credit facility was $105 million. The facility bears interest at prime rate or LIBOR plus 0.75% to 1.25% depending upon the percentage of the borrowing base drawn. Interest is payable quarterly and the loan is payable in sixteen quarterly installments beginning February 1, 1999. A commitment fee of 3/8% of the undrawn balance is payable quarterly. It is the Company's policy to extend the term period of the credit facility annually. The weighted average interest rate on these borrowings were 6.3% and 7.3% for the years ended December 31, 1994 and 1995, respectively. The weighted average interest rate gives effect to interest rate swap arrangements which have the effect of fixing the interest rate on $40 million of the credit facility at a rate of 6.4%. The existing interest rate swap arrangements will remain in effect through no less than July 1997 and no longer than October 1999. The Company's other debt is comprised of secured equipment financings.
The debt agreements contain various covenants relating to net worth, working capital maintenance and financial ratio requirements. Interest paid during the years ended December 31, 1993, 1994 and 1995 totaled $1.2 million, $2.8 million and $4.9 million, respectively.
Maturities of indebtedness as of December 31, 1995 were as follows (in thousands):
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
(6) COMMITMENTS AND CONTINGENCIES
In January 1995, a lawsuit (the "Lawsuit") was filed in the Delaware Court of Chancery, New Castle County, against Red Eagle Resources Corporation, each of the members of the Board of Directors of Red Eagle and the Company. The Plaintiff sought to represent all holders (the "Class") of Red Eagle common stock, excluding the Red Eagle Directors and Lomak. A settlement was reached during 1995 under which the Company paid $250,000 in cash plus 74,286 shares of the Company's Common Stock.
The Company is involved in various other legal actions and claims arising in the ordinary course of business. In the opinion of management, such litigation and claims will be resolved without material adverse effect on the Company's financial position.
(7) EQUITY SECURITIES
In 1993, $5,000,000 of 7-1/2% cumulative convertible exchangeable preferred stock (the "7-1/2% Preferred Stock") was privately placed. The 7-1/2% Preferred Stock is convertible, at the option of the holders, into 576,945 shares of common stock, at an average conversion price of $8.67 per share. The Company may convert the 7-1/2% Preferred Stock into common stock if the closing price for the common stock exceeds an average price of $11.70 for twenty out of thirty consecutive trading days. Beginning in July 1996, the Company may redeem the 7-1/2% Preferred Stock at a 7-1/2% premium to liquidation value. Holders of the 7-1/2% Preferred Stock are entitled to two votes per share on matters presented to the shareholders. At the Company's option, it can exchange the 7-1/2% Preferred Stock for convertible subordinate notes due July 1, 2003. The notes carry the same conversion and redemption terms as the 7-1/2% Preferred Stock.
In November 1995, the Company sold 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 December 1995, the Company privately placed 1.2 million shares of its Common Stock for $10.2 million to a state sponsored retirement plan. Warrants to acquire 40,000 shares of common stock were outstanding at December 31, 1995. The warrants have an exercise price of $7.50 per share and expire in December 1996.
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
(8) STOCK OPTION AND PURCHASE PLAN
The Company maintains a Stock Option Plan which authorizes the grant of options of up to 1.5 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:
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, 1995, 44,000 options were outstanding under the Directors Plan of which 3,600 were exercisable as of that date. The exercise price of the options ranges from $7.75 to $8.00 per share.
In 1994, the stockholders approved the 1994 Stock Purchase Plan (the "1994 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 had a 1989 Stock Purchase Plan (the "1989 Plan") which was identical to the 1994 Plan except that it covered 333,333 shares. Upon adoption of the 1994 Plan, the 1989 Plan was terminated. The plans are administered by the Compensation Committee of the Board. During the year ended December 31, 1995, the Company sold 85,800 unregistered common shares to officers and outside directors. From inception of the 1989 Plan through December 31, 1995, a total of 388,000 unregistered shares had been sold, for a total consideration of approximately $1.8 million at prices equal to 75% of market value at the time of the sale.
(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 1993, 1994 and 1995 were $189,000, $226,000 and $346,000, respectively.
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
(10) INCOME TAXES
Federal income tax (benefit) expense was ($81,000), $139,000 and $1.8 million for the years 1993, 1994 and 1995, respectively. The current portion of the income tax provision represents alternative minimum tax currently payable. A reconciliation between the statutory federal income tax rate and the Company's effective federal income tax rate is as follows:
In 1993, the Company adopted 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. Prior to the adoption, income tax expense was determined using the deferred method and the Company reported tax expense equal to current alternative minimum taxes payable. Deferred taxes have not been provided on temporary differences prior to adoption due to the existence of net operating loss and other carryforwards.
Significant components of the Company's deferred tax liabilities and assets are as follows (in thousands):
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
As permitted by Statement 109, the Company has elected not to restate prior year financial statements. As a result of tax basis in excess of the basis on the financial statements at January 1, 1993, the Company estimated deferred tax assets of $2.6 million and deferred tax liabilities of $0.9 million, for net deferred tax assets of $1.7 million. Due to uncertainty as to the realizability of the tax benefit, a valuation allowance was established for the full amount of the net deferred tax assets. In 1993, 1994 and 1995, income taxes were reduced from the statutory rate of 34% by approximately $0.5 million, $0.9 million and $0.3 million, respectively, through realization of a portion of the valuation allowance, resulting in $1.2 million, $0.3 million and $40,000, respectively of the remaining allowance at December 31, 1993, 1994 and 1995.
During 1993, the Company acquired Mark Resources Corporation (See Note 3), a taxable business combination accounted for as a purchase. Deferred tax assets of $3.9 million and a deferred tax liability of $8.1 million were recorded in connection with the business combination. During 1994, the Company acquired Gillring Oil Company and Grand Banks Energy Company, taxable business combinations accounted for as purchases. Deferred tax assets of $3.5 million and deferred tax liabilities of $3.4 million were recorded in connection with these transactions. The Company acquired Red Eagle Resources Corporation, a taxable business combination accounted for as a purchase. Deferred tax liabilities of $12.3 million and deferred tax assets of $0.3 million were recorded in connection with this 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, 1995, the Company had available for federal income tax reporting purposes net operating loss carryovers of approximately $13.3 million which are subject to annual limitations as to their utilization and otherwise expire between 1996 and 2010, if unused. The Company has alternative minimum tax net operating loss carryovers of $8.2 million which are subject to annual limitations as to their utilization and otherwise expire from 1996 to 2009 if unused. The Company has statutory depletion carryover of approximately $8.5 million and an alternative minimum tax credit carryover of approximately $500,000. The statutory depletion carryover and alternative minimum tax credit carryover are not subject to limitation or expiration.
(11) 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. At December 31, 1995, approximately 59% of the Company's gas production was being sold under market sensitive contracts which do not contain floor price provisions. For the year ended December 31, 1995, no one customer accounted for more than 10% of the Company's total oil and gas revenues. 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. The Company sells to oil purchasers on a basis of price and service.
The Company has currently hedged less than 3% of its monthly production through September 1996. These hedges involve fixed price arrangements and other price arrangements at a variety of prices, floors and caps. 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.
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
(12) OIL AND GAS ACTIVITIES
The following summarizes selected information with respect to oil and gas producing activities:
(13) SUBSEQUENT EVENTS
In February 1996, the Company completed three oil and gas property acquisitions for $17.5 million of consideration. The properties are located in Lomak's core operating areas of Appalachia and Texas. In aggregate, the acquisitions are estimated to contain proved reserves of 20.2 Bcf of gas and 240,000 Bbls of oil, or 21.6 Bcfe in total.
In March 1996, the Company's Board of Directors approved resolutions authorizing the Company to repurchase shares of its Common Stock from odd-lot holders. The Company will acquire any and all shares from stockholders owning 99 or fewer shares for cash at market prices. Additionally, the Board of Directors approved a dividend of $.01 per share to holders of its Common Stock to be paid on March 29, 1996.
(14) RELATED PARTY TRANSACTIONS
Mr. Edelman, Chairman of the Company, is also an executive officer and shareholder of Snyder Oil Corporation ("SOCO"). At December 31, 1995, Mr. Edelman owned 6.0% of the Company's common stock. In 1994, the Company repurchased 30,000 shares of its common stock from SOCO for $240,000. The purchase price was based upon the prior day's closing price for the stock. In 1995, SOCO sold its remaining shares of the Company's common stock.
In 1995, the Company acquired SOCO's interest in certain wells located in Appalachia for $4 million. The price was determined based on arms-length negotiations through a third-party broker retained by SOCO. Subsequent to the transaction, the Company and SOCO no longer held interests in any of the same properties.
During 1994 and 1995, the Company incurred fees of $369,000 and $145,000, respectively, to the Hawthorne Company in connection with acquisitions. Mr. Aikman, a director of the Company, is an executive officer and a principal owner of the Hawthorne Company. The fees were consistent with those paid by the Company to third parties for similar services.
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
(15) 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.
QUANTITIES OF PROVED RESERVES
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.
LOMAK PETROLEUM, INC. Notes to Consolidated Financial Statements
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.
STANDARDIZED MEASURE
CHANGES IN STANDARDIZED MEASURE
LOMAK PETROLEUM, INC.
INDEX TO EXHIBITS
(Item 14[a 3])
* Filed herewith.