ITEM 1. BUSINESS
A. GENERAL
Howell Corporation and its subsidiaries (the "Company") are primarily engaged in the exploration, production, acquisition and development of oil and gas properties. The Company is also involved in technical fuels and chemical processing, and crude oil marketing and transportation. These operations are conducted in the United States. A description of each of the Company's principal business segments and the markets in which they operate is summarized below. For information relating to industry segments, reference is made to "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements and notes thereto.
OIL AND GAS EXPLORATION AND PRODUCTION
The Company's oil and gas exploration and production activities are conducted entirely within the United States by Howell Petroleum Corporation ("HPC") and are concentrated along the Gulf Coast, both offshore and onshore and in Wyoming. At December 31, 1996, the Company's estimated proved oil reserves were 7,959 MBbl and estimated proved natural gas reserves were 60,254 MMcf. The Company's three major producing properties, Main Pass Block 64 ("Main Pass"), the LaBarge Project and the North Frisco City Field together represented 5,054 MBbl and 48,105 MMcf of the Company's estimated proved reserves of oil and natural gas, respectively, at December 31, 1996. The Company's interest in the LaBarge Project is also the source of all of the Company's proved reserves of carbon dioxide and helium (113,397 MMcf and 2,290 MMcf, respectively, at December 31, 1996). In addition, the Company owns fee mineral interests in 876,000 net acres in Mississippi, Alabama and Louisiana. Substantially all of the Company's oil and natural gas production is sold on the spot market or pursuant to contracts priced according to the spot market. HPC has 47 employees.
The oil and gas industry is highly competitive. Major oil and gas companies, independent operators, drilling and production purchase programs, and individual producers and operators are active bidders for desirable oil and gas properties, as well as the equipment and labor required to operate those properties. Many competitors have financial resources substantially greater, and staffs and facilities substantially larger, than those of the Company. The availability of a ready market for the oil and gas production of the Company depends in part on the cost and availability of alternative fuels, the level of consumer demand, the extent of other domestic production of oil and gas, the extent of importation of foreign oil and gas, the cost of and proximity to pipelines and other transportation facilities, the regulations by state and federal authorities, and the cost of complying with applicable environmental regulations.
TECHNICAL FUELS AND CHEMICAL PROCESSING
The Company develops, manufactures and markets hydrocarbons-based research and reference fuels and provides chemical toll processing services through its wholly owned subsidiary Howell Hydrocarbons & Chemicals, Inc. ("HHC"), which has 54 employees. The Company conducts its research and reference fuels operations and its chemical processing operations at its modern 50-acre facility in Channelview, Texas. Extensive construction at the facility since 1988 has expanded the available office, laboratory and warehouse space to 24,500 square feet. The Company now has available for technical fuels operations an 1,800 BPD sweet crude unit and a 400 BPD sour crude unit, as well as extensive laboratory blending and dedicated storage facilities, including leased storage near its major customers in Detroit, Michigan. For the chemical processing operations, the facility includes three large-diameter stainless steel distillation columns for batch or continuous processing and extensive stainless steel and carbon steel tankage. In the second half of 1993, the Company constructed a synthesis reaction unit that became operational in 1994. The modern facilities afforded the Company the ability to obtain expanded air permits that enhance its competitive position.
The technical fuels business involves the processing of crude oil and blending of petroleum products and additives to create specialty fuels used for testing such things as lubricants and engine emissions. HHC's customer base for its technical fuels products includes the U.S. Government and automobile manufacturers worldwide. HHC has relatively few competitors in the technical fuels market; however, each is substantially larger and has greater financial resources than HHC. Environmental and other governmental regulations
relating to combustion product emissions, mileage criteria and equipment design continue to increase. As a result, the Company continues to develop new products to meet customer requirements and serve the demand for technical fuels.
HHC has conducted chemical toll processing and product terminalling activities at the Channelview facility for eight years. In 1994 the toll processing campaign was short-term in nature and consisted primarily of reprocessing customers' chemicals that did not meet product specifications and standby processing when the customer's own plant was unable to handle the processing.
In 1995 and 1996, HHC obtained contracts that are longer term and involve the use of the synthesis reaction unit. The Company has concentrated its marketing efforts on customers who are manufacturers of acetates and esters for the paint and coatings industry. Additionally, in 1995, HHC recognized income in conjunction with the cancellation by a customer of a long-term contract. The customer determined that demand for the product to be processed by HHC was not sufficient to warrant production and released the Company from further requirements under the contract.
HHC has competition for long-term toll manufacturing contracts from numerous companies offering similar services in the Houston area and worldwide. HHC believes its modern computer process control equipment and its access to rail and water transportation give it an advantage over some of its competitors.
In May 1996 the Company signed a letter of intent to begin negotiations to sell HHC to Schenectady International, Inc. ("Schenectady"). Subsequent to signing the letter of intent, negotiations between the Company and Schenectady were terminated. The Company continues to receive and evaluate inquiries about the sale of HHC.
PURCHASE & SALE AND CONTRIBUTION & CONVEYANCE OF CRUDE OIL GATHERING AND MARKETING OPERATIONS AND PIPELINE OPERATIONS
On December 1, 1996, Genesis Crude Oil, L.P., a Delaware limited partnership ("Buyer"), Genesis Energy, L.P., a Delaware limited partnership ("MLP"), and Genesis Energy, L.L.C., a Delaware limited liability company ("LLC"), entered into a Purchase & Sale and Contribution & Conveyance Agreement ("Agreement") with Howell Corporation and certain of its subsidiaries ("Howell") and Basis Petroleum, Inc. ("Basis"), a subsidiary of Salomon Inc. ("Salomon"). Pursuant to the Agreement, Howell agreed to sell and convey certain of its assets to Buyer. These assets consisted of the crude oil gathering and marketing operations and pipeline operations of Howell (referred to hereafter as the "Business").
Buyer was formed by MLP and LLC to acquire the Business from Howell and similar assets from Basis. MLP is owned 98% by limited partners and 2% by LLC, which is the general partner. LLC is owned 46% by Howell and 54% by Basis. As a result of this transaction Howell owns a subordinated limited partner interest in Buyer of 9.01%, a direct general partner interest in Buyer of 0.18% and a general partner interest through MLP of 0.74% of Buyer.
In accordance with the Agreement, Howell received cash of approximately $74.0 million and 991,300 subordinated limited partner units in Buyer in exchange for its sale and conveyance of the Business and recognized a gain in the amount of $13.8 million. Except as specifically provided in the Agreement, Howell retained all liabilities related to the Business arising from the operations, activities and transactions of the Business up through the closing date, including various environmental related liabilities. Howell made various representations and warranties as to itself and the Business and has agreed to indemnify Buyer for any breaches thereof. Claims for breaches of such representations and warranties must be brought before December 3, 2001. Howell has also agreed to perform, and retain the liability for, the cleaning of certain tanks used in the pipeline operations.
On the closing date, Howell entered into various agreements with Buyer, MLP and LLC pursuant to the Agreement, including (a) a non competition agreement prohibiting Howell from competing with the Business for a period of ten years; (b) an agreement relating to the purchase of crude oil by Howell for use in its technical fuels business and the sale of crude oil by Howell from its oil and gas exploration and production business; (c) an agreement whereby Howell will provide certain transitional services to Buyer; (d) an agreement whereby MLP will sell additional limited partner units to the public and use the proceeds to redeem the subordinated
limited partner units in Buyer owned by Howell after certain conditions are met; and (e) an agreement whereby one-half of the subordinated limited partner units owned by Howell are pledged to secure Howell's indemnification of Buyer for environmental liabilities.
Also at closing, Howell entered into an agreement with Salomon which provides (a) an unconditional obligation of Howell to buy its 46% share of additional limited partner interests ("APIs") from Salomon if Howell (as a member of LLC) has approved an acquisition by Buyer and (b) to the extent APIs are outstanding, an obligation by Howell to purchase 46% of such outstanding APIs, but only to the extent of any distribution made to Howell by Buyer on Howell's subordinated limited partner units.
MLP ("Genesis") is a Delaware limited partnership recently formed to acquire, own and operate the crude oil gathering and marketing operations of Basis and the crude oil gathering, marketing and pipeline operations of Howell. Upon completion of the transactions, the partnership is one of the largest independent gatherers and marketers of crude oil in North America. Genesis' operations are concentrated in Texas, Louisiana, Alabama, Florida, Mississippi, New Mexico, Kansas and Oklahoma. In its gathering and marketing business, Genesis is principally engaged in the purchase and aggregation of crude oil at the wellhead and the bulk purchase of crude oil at pipeline and terminal facilities for resale at various points along the crude oil distribution chain, which extends from the wellhead to aggregation and terminal stations, refineries and other end markets (the "Distribution Chain"). The partnership's gathering and marketing margins are generated by buying crude oil at competitive prices, efficiently transporting or exchanging the crude oil along the Distribution Chain and marketing the crude oil to refineries or other customers at favorable prices. In addition to its gathering and marketing business, Genesis' operations include transportation of crude oil for itself and for others at regulated published tariffs on its four common carrier pipeline systems. On a pro forma basis, in 1995 the gathering and marketing operations contributed approximately 65% of the partnership's total gross margin and the pipeline operations contributed the remaining 35%.
SALE OF HOWELL TRANSPORTATION SERVICES, INC., TO LODESTAR LOGISTICS, INC.
On December 31, 1996, the Company sold 100% of the outstanding common stock of Howell Transportation Services, Inc. (HTS) following the transfer of all assets and liabilities associated with crude oil gathering to Genesis. The former president of HTS purchased HTS at a value the Company believes was equivalent to an arms length transaction. The remaining assets of HTS specifically included approximately 64 tank trailers, approximately 40 leased truck tractors, real property and contracts for transportation services.
The purchase price was the net book value of HTS on the closing date. The Company received $2.6 million, consisting of $1.8 million in cash, a $0.5 million note receivable and a $0.3 million receivable in the form of services from HTS. The $0.5 million note receivable has a term of no less than 84 months and a rate of interest equal to prime as published in THE WALL STREET JOURNAL.
The Company will supply certain transition services as available, and as needed, for a period of not more than 12 months.
In addition, the Company will provide, via cash advance or guarantee, for deposits or collateral required to obtain initial insurance coverage as required.
B. GOVERNMENTAL AND ENVIRONMENTAL REGULATIONS
GOVERNMENTAL REGULATIONS
Domestic development, production and sale of oil and gas are extensively regulated at both the federal and state levels. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, have issued rules and regulations binding on the oil and gas industry and its individual members, compliance with which is often difficult and costly and some of which carry substantial penalties for failure to comply. State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning wells. Texas and other states in which the Company conducts operations also have statutes and regulations governing conservation matters, including the unitization or pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. The existing statutes or regulations currently limit the rate at which oil and gas is produced from wells in which the Company owns an interest.
The Company's other business segments also operate under strict governmental regulations. The refining and processing of fuels and chemicals is subject to state and federal regulations regarding air and water emissions and the disposal of wastes.
ENVIRONMENTAL REGULATIONS
The Company's operations are subject to extensive and developing federal, state and local laws and regulations relating to environmental, health and safety matters; petroleum; chemical products and materials; and waste management. Permits, registrations or other authorizations are required for the operation of certain of the Company's facilities and for its oil and gas exploration, production, processing and chemical toll processing activities. These permits, registrations or authorizations are subject to revocation, modification and renewal. The Company has determined that the federal wastewater discharge permit at its Channelview facility may have expired prior to the transfer of the permit to the Company. The Company has taken steps to resolve this matter. In addition, the Company has been penalized for the failure to properly handle and dispose of some wastes at the facility it formerly owned in San Antonio, Texas. See Note 10 of Notes to Consolidated Financial Statements. Governmental authorities have the power to enforce compliance with these regulatory requirements, the provisions of required permits, registrations or other authorizations, and lease conditions, and violators are subject to civil and criminal penalties, including fines, injunctions or both. Failure to obtain or maintain a required permit may also result in the imposition of civil and criminal penalties. Third parties may have the right to sue to enforce compliance. The cost of environmental compliance has not had a materially adverse effect on the Company's operations or financial condition in the past. However, violations of applicable regulatory requirements, environment-related lease conditions, or required environmental permits, registrations or other authorizations can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations.
Some risk of costs and liabilities related to environmental, health and safety matters is inherent in the Company's operations, as it is with other companies engaged in similar businesses, and there can be no assurance that material costs or liabilities will not be incurred. In addition, it is possible that future developments, such as stricter requirements of environmental or health and safety laws and regulations affecting the Company's business or more stringent interpretations of, or enforcement policies with respect to, such laws and regulations, could adversely affect the Company. To meet changing permitting and operational standards, the Company may be required, over time, to make site or operational modifications at the Company's facilities, some of which might be significant and could involve substantial expenditures. In particular, federal regulatory programs focusing on the increased regulation of storm water runoff, oil spill prevention and response and air emissions (especially those that may be considered toxic) are currently being implemented. There can be no assurance that material costs or liabilities will not arise from these or additional environmental matters that may be discovered or otherwise may arise from future requirements of law.
The Company has made a commitment to comply with environmental regulations. Personnel with training and experience in safety, health and environmental matters are responsible for compliance activities. Senior management personnel are involved in the planning and review of environmental matters.
C. EMPLOYMENT RELATIONS
In addition to the employees of the two main business segments, the Company has 20 other employees, for a total of 121 employees. The Company's employees are not represented by a union for collective bargaining purposes. The Company has experienced no work stoppages or strikes as a result of labor disputes and considers relations with its employees to be good. The Company maintains group life, medical, dental, long-term disability and accidental death and dismemberment insurance plans for its employees. In addition, the Company provides its employees with a Company stock purchase plan, a thrift plan and a Simplified Employee Pension Plan.
ITEM 2.

ITEM 2. PROPERTIES
A. SUPPLEMENTARY OIL AND GAS PRODUCING INFORMATION (UNAUDITED)
The oil and gas producing activities of the Company are summarized below. Substantially all of the Company's producing properties are subject to a lien held by a bank. See Note 6 of Notes to Consolidated Financial Statements.
OIL AND GAS WELLS
As of December 31, 1996, the Company owned interests in productive oil and gas wells (including producing wells and wells capable of production) as follows:
PRODUCTIVE WELLS GROSS(1) NET
Oil wells...................................... 290 81 Gas wells...................................... 85 13 ----- ----- Total..................................... 375 94 ===== ===== - -----------------
(1) One or more completions in the same well are counted as one well; none of the wells have multiple completions.
RESERVES
The Company's net proved reserves of crude oil, condensate and natural gas liquids (referred to herein collectively as "oil") and its net proved reserves of gas have been estimated by the Company's engineers in accordance with guidelines established by the Securities and Exchange Commission. The reserve estimates at December 31, 1996, 1995 and 1994 have been audited by independent petroleum consultants, H. J. Gruy and Associates, Inc. The estimates for the prior years were audited by L. A. Martin & Associates, Inc. These estimates were used in the computation of depreciation, depletion and amortization included in the Company's consolidated financial statements and for other reporting purposes. The Company has not filed any estimates of reserves with any federal authority or agency during the past year other than estimates contained in its last annual report on Form 10-K. Set forth on the next page are estimates of the Company's net proved oil and gas reserves, all located in the United States.
ESTIMATED QUANTITIES OF PROVED OIL AND GAS RESERVES
OIL GAS (BBLS) (MCF)
As of December 31, 1993.................... 7,270,921 70,693,980 Revisions of previous estimates............ (37,261) (1,656,466) Extensions, discoveries & other additions.. 1,523,356 5,327,274 Production.................................(1,336,937) (3,208,139) Sales of minerals in place................. (204,323) (218,059) --------- ---------- As of December 31, 1994.................... 7,215,756 70,938,590 Revisions of previous estimates............ (555,469) (11,578,149) Extensions, discoveries & other additions.. 2,523,526 3,893,092 Purchases of minerals in place............. 961,025 1,025,383 Production.................................(1,383,881) (3,526,803) Sales of minerals in place................. (160,921) (171,313) --------- ---------- As of December 31, 1995.................... 8,600,036 60,580,800 Revisions of previous estimates............ 459,820 1,007,250 Extensions, discoveries & other additions.. 122,081 2,424,077 Production.................................(1,207,906) (3,273,257) Sales of minerals in place................. (14,858) (484,520) --------- ---------- As of December 31, 1996.................... 7,959,173 60,254,350 ========= ==========
Proved developed reserves: December 31, 1993.......................... 6,782,015 63,618,243 December 31, 1994.......................... 6,201,176 63,677,432 December 31, 1995.......................... 7,662,263 60,125,223 December 31, 1996.......................... 6,995,835 58,444,115
Proved oil reserves at December 31, 1996 include 341,896 barrels of natural gas liquids.
The reserves as of December 31, 1996, shown in the table above, include 379,575 barrels of oil and 2,723,335 Mcf of gas attributable to the Company's producing fee mineral interests.
In addition to the oil and gas reserves shown above, HPC, through its participation in the LaBarge Project in southwestern Wyoming, had proved carbon dioxide reserves of 113,396,600 Mcf and proved helium reserves of 2,289,710 Mcf at December 31, 1996.
OIL AND GAS LEASEHOLDS
The table on the following page sets forth the Company's ownership interest in leaseholds as of December 31, 1996. The oil and gas leases in which the Company has an interest are for varying primary terms, and many require the payment of delay rentals to continue the primary term. The leases may be surrendered by the Company at any time by notice to the lessors, by the cessation of production or by failure to make timely payment of delay rentals.
DEVELOPED(1) UNDEVELOPED --------------- -------------------- GROSS NET GROSS NET ACRES ACRES ACRES ACRES ----- ----- ------ ------ Alabama............................. 6,583 2,378 5,039 1,591 Louisiana........................... 1,851 382 240 39 Mississippi......................... 3,803 1,150 17,962 5,522 Texas............................... 11,340 5,141 16,197 5,175 Wyoming............................. 17,499 2,501 19,199 3,225 All other states combined........... 2,522 470 1,862 511 Offshore............................ 7,025 5,589 - - ----- ----- ------ ------ Total........................... 50,623 17,611 60,499 16,063 ====== ====== ====== ======
In addition to the acreage under leaseholds as shown above, the Company owns the fee mineral acreage shown in the table below:
DEVELOPED(1) UNDEVELOPED --------------- -------------------- GROSS NET GROSS NET ACRES ACRES ACRES ACRES
Alabama............................. 2,829 1,414 618,656 308,949 Louisiana........................... 6,381 907 9,520 4,531 Mississippi......................... 20,282 10,153 1,117,130 550,413 ------ ------ --------- ------- Total........................... 29,492 12,474 1,745,306 863,893 ====== ====== ========= ======= - -----------------
(1) Acres spaced or assignable to productive wells.
DRILLING ACTIVITY
The following table shows the Company's net productive and dry exploratory and development wells drilled in the United States:
EXPLORATORY DEVELOPMENT ------------------- ----------------- NET NET NET NET PRODUCTIVE DRY PRODUCTIVE DRY YEAR WELLS HOLES WELLS HOLES ---- ------- ----- ----- ----- 1996 .16 1.45 - - ==== ==== ==== ==== ==== 1995 1.64 1.08 0.72 1.95 ==== ==== ==== ==== ==== 1994 0.53 2.17 2.03 - ==== ==== ==== ==== ====
The table above reflects only the drilling activity in which the Company had a working interest participation. In addition, in 1996, 1995 and 1994, 22, 14 and 18 gross productive wells, respectively, were drilled on the Company's fee mineral acreage.
SALES PRICES AND PRODUCTION COSTS
The following table sets forth the average prices received by the Company for its production, the average production (lifting) costs and amortization per equivalent barrel of production:
UNITED STATES --------------------- 1996 1995 1994 ---- ---- ---- Average sales prices: Oil and NGL (per Bbl)............................ $17.52 $15.67 $14.40 Natural gas (per Mcf)............................ $ 2.06 $ 1.47 $ 1.70 Production (lifting) costs (per equivalent barrel of production................................ $ 5.23 4.47 $ 4.23 Amortization (per equivalent barrel of production).. $ 5.37 $ 5.20 $ 4.96
Natural gas production is converted to barrels using its estimated energy equivalent of six Mcf per barrel.
OIL AND GAS PRODUCING ACTIVITIES
CAPITALIZED COSTS. The following table presents the Company's aggregate capitalized costs relating to oil and gas producing activities, all located in the United States, and the aggregate amount of related depreciation, depletion and amortization:
DECEMBER 31, 1996 DECEMBER 31, 1995 ----------------- ----------------- (In thousands)
Capitalized Costs: Oil and gas producing properties, all being amortized................... $280,766 $278,505 Fee mineral interests, unproven..... 18,180 18,188 ------- ------- Total............................. 298,946 296,693 ======= ======= Accumulated depreciation, depletion and amortization.................. $195,883 $188,972 ======== ========
COSTS INCURRED. The following table presents costs incurred by the Company, all in the United States, in oil and gas property acquisition, exploration and development activities:
YEAR ENDED DECEMBER 31, --------------------------- 1996 1995 1994 ---- ---- ---- (In thousands) Property acquisition: Unproved fee mineral interests...... $ - $ - $ 3 Unproved leaseholds................. 1,665 790 792 Proved properties................... - 6,218 - Exploration........................... 3,526 2,830 3,252 Development........................... 384 5,111 5,559 ------ ------- ------ $5,575 $14,949 $9,606 ====== ======= ======
In 1996, 1995 and 1994, $8,000, $12,000 and $63,000 of costs of unproved mineral interests, respectively, were transferred to the full-cost pool, representing the costs of mineral properties that were drilled and evaluated during the periods. These transfers of costs are not reflected in the table above.
RESULTS OF OPERATIONS. The following table sets forth the results of operations of the Company's oil and gas producing activities, all in the United States. The table does not include activities associated with carbon dioxide, helium and sulfur produced from the LaBarge Project or with activities associated with leasing the Company's fee mineral interests. The table does include the revenues and costs associated with the Company's production from its fee mineral interests.
YEAR ENDED DECEMBER 31, ----------------------------- 1996 1995 1994 ---- ---- ---- (In thousands)
Revenues.............................. $28,162 $27,011 $24,608 Production (lifting) costs............ 9,174 8,810 7,914 Depreciation, depletion and amortization........................... 9,416 10,259 9,282 ------ ------ ------ 9,572 7,942 7,412 Income tax expense.................... 3,318 2,396 2,283 ------ ------ ------
Results of operations (excluding corporate overhead and interest cost). $6,254 $5,546 $5,129 ====== ====== ======
Included in the 1996, 1995 and 1994 amounts above are $2,301,000, $1,992,000 and $1,908,000 of revenues and $181,000, $146,000 and $141,000 of production costs, respectively, from the production of the Company's producing fee mineral interests.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES. The accompanying table presents a standardized measure of discounted future net cash flows relating to the production of the Company's estimated proved oil and gas reserves at the end of 1996 and 1995. The method of calculating the standardized measure of discounted future net cash flows is as follows:
(1) Future cash inflows are computed by applying year-end prices of oil and gas to the Company's year-end quantities of proved oil and gas reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.
(2) Future development and production costs are estimates of expenditures to be incurred in developing and producing the proved oil and gas reserves at year-end, based on year-end costs and assuming continuation of existing economic conditions.
(3) Future income tax expenses are calculated by applying the applicable statutory federal income tax rate to future pretax net cash flows. Future income tax expenses reflect the permanent differences, tax credits and allowances related to the Company's oil and gas producing activities included in the Company's consolidated income tax expense.
(4) The discount, calculated at ten percent per year, reflects an estimate of the timing of future net cash flows to give effect to the time value of money.
DECEMBER 31, DECEMBER 31, 1996 1995 (In thousands)
Future cash inflows..................................... $398,711 $253,239 Future production costs................................. 178,157 97,093 Future development costs................................ 10,583 9,963 Future income tax expenses.............................. 55,675 32,531 --------- ------- Future net cash flows................................... 154,296 113,652 10% annual discount for estimated timing of cash flows.. 50,241 31,505 --------- ------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves................................ $104,055 $82,147 ======== =======
The standardized measure is not intended to represent the market value of reserves and, in view of the uncertainties involved in the reserve estimation process, including the instability of energy markets as evidenced by recent declines in both natural gas and crude oil prices, may be subject to material future revisions.
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS. The table below presents a reconciliation of the aggregate change in standardized measure of discounted future net cash flows:
YEAR ENDED DECEMBER 31, --------------------------- 1996 1995 1994 ---- ---- ---- (In thousands)
Sales and transfers, net of production costs. $(18,988) $(18,201) $(16,693) Net changes in prices and production costs... 58,036 15,492 7,354 Extensions and discoveries, net of future production and development costs............. 5,382 24,475 17,850 Purchases of minerals in place............... - 7,248 - Sales of minerals in place................... (494) (1,319) (1,546) Previously estimated development costs incurred during the period................... - (1,079) (446) Revisions of quantity estimates.............. 4,844 (13,690) (1,453) Accretion of discount........................ 8,215 6,844 6,426 Net change in income taxes................... (13,930) (1,706) (994) Changes in production rates (timing) and other........................... (21,157) (4,352) (6,324) -------- -------- -------- Net change............................... $21,908 $13,712 $4,174 ======== ======== ========
DESCRIPTION OF SIGNIFICANT PROPERTIES
The three producing properties of major significance to the Company are Main Pass Block 64, located in federal waters offshore Louisiana, the North Frisco City Field in Alabama and the LaBarge Project located in southwestern Wyoming. These properties represent, in total, 5,090 MBbl and 48,149 MMcf of the Company's estimated proved reserves of oil and natural gas, respectively, at December 31, 1996. In addition, the Company owns fee mineral interests in 876,000 net acres in Mississippi, Alabama and Louisiana. The following sets forth certain information with respect to the Company's interest in its most significant properties.
MAIN PASS BLOCK 64. Main Pass is located in federal waters offshore Louisiana about 70 miles southeast of New Orleans. The Company, as operator, discovered oil and gas upon drilling a test well in 1982. By August 1983, the Company had completed nine producing wells and one gas injection well and designed, constructed and placed online a production platform and oil pipeline facilities. Since then, the Company has completed eight more wells, tied into an interstate natural gas pipeline system, converted the gas injection well to a producing well and increased its working interest from 52% to almost 80%. In 1989, the Company acquired an 80% working interest in an adjacent block with five wells, a production platform and oil and gas pipelines. The Company subsequently unitized portions of these two blocks covering the then known limits of the main pay sand (the "7,300' Sand Unit") and then designed, constructed and placed on-line a waterflood project intended to repressure the 7,300' Sand Unit. Gross cumulative production from the field over almost 14 years has totaled 9,795 MBbl of oil and 25,169 MMcf of natural gas. During 1996, net production averaged 964 BOPD and 418 Mcfpd of natural gas.
Under a farm-out arrangement from the Company, a third party drilled, completed and tested a deep test well in 1993. During 1994, the Company and its partners in the 7300' Sand Unit acquired the deep well from the third party. The consideration for this acquisition was the Company's acceptance of liability to plug the deep well when it is abandoned. In December 1994 the Company connected this well to the existing platform, and production began in January 1995.
The Company currently has a working interest which averages approximately 80% in 24 gross (19.1 net) wells, five of which are water injection wells. All of the water injection wells are located on the adjacent block, utilizing the production platform as a water injection facility.
Proved reserves attributable to Main Pass at December 31, 1996 were 3,188 MBbl of oil and 2,710 MMcf of natural gas, representing 40% and 5%, respectively, of the Company's proved oil and natural gas reserves.
NORTH FRISCO CITY FIELD. The North Frisco City Field ("Unit"), located in Monroe County, Alabama, was discovered in March 1991. After the discovery well was completed, the structural complexity of this find led the Company and its partners to run a 3-D seismic program over the potential field area. Based on this data, five successful development wells were completed during 1992, two in 1993 and three in 1994. Only one dry hole has been drilled to date, thereby establishing an eastern limit to the field. In the fourth quarter of 1994, the field was unitized. The Company currently has a 24.1% working interest in nine gross (2.2 net) producing wells in the Unit, each of which produces from the Frisco City sand member of the Haynesville formation at a depth of about 12,000 feet. In addition, the Company has interests in two wells not included in the Unit. Aggregate net production from this field averaged 1,024 BOPD of crude oil, 195 BPD of natural gas liquids and 1,195 Mcfpd of natural gas during the fourth quarter of 1996.
The Company's estimated proved reserves from its working interest in the Unit at December 31, 1996 were 1,866 MBbl of oil and 2,324 MMcf of natural gas, representing approximately 24% and 4%, respectively, of the Company's total proved oil and natural gas reserves. The Company also owns a royalty interest in this field through its ownership of the fee mineral properties discussed below.
FEE MINERAL PROPERTIES. In August 1993 the Company acquired all of the fee mineral properties of the Federal Intermediate Credit Bank of Jackson, Mississippi ("FICBJ"). The Company paid FICBJ $24.1 million for these properties and expended an additional $0.2 million for costs related to the acquisition.
The properties consist of 876,000 net acres of fee mineral interests located in Mississippi (64%), Alabama (35%) and Louisiana (1%). The purchase price was allocated $6.1 million to producing acreage and $18.2 million to non-producing acreage. The value assigned to the producing acreage is included in the full cost pool being amortized as described in Note 1 of Notes to the Consolidated Financial Statements.
Proved reserves attributable to the producing acreage at December 31, 1996, were 380 MBbl of oil and 2,723 MMcf of natural gas.
The non-producing fee mineral properties generate lease bonus and delay rental revenues. During 1996, 1995 and 1994, revenues of $0.6 million, $0.2 million and $0.5 million, respectively, were generated from these types of activities.
LABARGE PROJECT. The LaBarge Project, located in southwestern Wyoming, consists of three federal units, 17 producing wells, a field gathering system, a dehydration plant, a 32-mile dehydrated raw gas pipeline, a gas processing plant with a capacity for processing up to 600,000 MCFD of raw gas into natural gas, carbon dioxide, helium and sulfur, and marketing facilities for the sale of the plant products. The Company has a 4.8% working interest in one of the units, the Fogarty Creek Unit. The Company has an interest in 12 gross (0.6 net) wells producing from depths between 14,500 feet to 17,000 feet in the Fogarty Creek Unit. Exxon Company USA ("Exxon USA") holds a 92% interest in the Fogarty Creek Unit and a 100% interest in each of the other two units, the plants and the marketing facilities.
The Company's raw gas is processed pursuant to an agreement with Exxon USA which provided for an initial processing fee equal to 65% of the sales value of the plant products through August 1991, increasing to 75% from that date forward until the sooner of payout of the gas processing plant or September 2021, at which time it will adjust to a cost-plus fee, not to exceed 50% of the sales value of the products. The processing agreement also provides for Exxon to market all of the Company's products from the LaBarge Project.
The Company has significant production and reserves of carbon dioxide and helium and small amounts of production and reserves of sulfur from its interest in the LaBarge Project, which are not included in its production and proved reserves of oil and natural gas discussed elsewhere in Item 2. The table on the next page presents information on the Company's net production of natural gas, carbon dioxide and helium attributable to the Company's interest in the LaBarge Project. The natural gas data from the LaBarge Project is also included in the other tables set forth elsewhere in Item 2.
LABARGE PRODUCTION
YEAR ENDED DECEMBER 31, 1996 1995 1994 ---- ---- ---- (IN THOUSANDS, EXCEPT UNIT PRICES)
Production data (net): Natural gas (Mcf)............... 1,222 1,261 1,141 Carbon dioxide (Mcf)(1)......... 603 659 843 Helium (Mcf).................... 27 31 34 Average sales price per unit: Natural gas (Mcf)............... $ 1.71 $ 1.41 $1.53 Carbon dioxide (Mcf)............ $ 0.30 $ 0.39 $0.56 Helium (Mcf).................... $ 43.68 $49.44 $51.61 Financial data: Revenues........................ $ 3,558 $3,819 $3,975 Processing costs................ 2,825 3,024 3,141 ------- ------ ------ Net cash flows.................. $ 733 $ 795 $ 834 ======= ====== ====== - -----------------
(1) Because of a lack of market, approximately 81%, 80% and 74% of the volume produced in 1996, 1995 and 1994, respectively, was vented and not sold. Amounts included in the table reflect only volumes sold.
B. OTHER PROPERTIES
In addition to the oil and gas properties described above, the Company and its subsidiaries lease approximately 52,900 square feet. for use as corporate and administrative offices in Houston, Texas. The Company's technical fuels and chemical processing operations are conducted at a 50 acre facility owned by the Company. The facility, located in Channelview, Texas, includes buildings covering 24,500 square feet.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
The Company, through its subsidiaries, is involved from time to time in various claims, lawsuits and administrative proceedings incidental to its business. In the opinion of management, the ultimate liability thereunder, if any, will not have a materially adverse effect on the financial condition or results of operations of the Company. See Note 9 of Notes to Consolidated Financial Statements.
ITEM 4.

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

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Howell Corporation common stock is traded on the New York Stock Exchange. Symbol: HWL
CASH PRICE DIVIDENDS FOR QUARTER ENDED HIGH LOW $ ------------------ ---- --- ----
March 31, 1995......................... 13 3/4 10 3/8 0.04 June 30, 1995.......................... 14 7/8 12 7/8 0.04 September 30, 1995..................... 16 3/8 13 7/8 0.04 December 31, 1995...................... 14 3/8 11 13/16 0.04 March 31, 1996......................... 14 5/8 13 1/2 0.04 June 30, 1996.......................... 15 1/8 13 3/8 0.04 September 30, 1996..................... 15 3/8 12 1/2 0.04 December 31, 1996...................... 16 13 1/2 0.04
Approximate number of equity shareholders as of December 31, 1996: 1,800.
It is the current intention of the Company to continue to pay quarterly cash dividends on its common stock. No assurance can be given, however, as to the timing and amount of any future dividends which necessarily will depend on the earnings and financial needs of the Company, legal restraints, and other considerations that the Company's Board of Directors deems relevant. The ability of the Company to pay dividends on its common stock is currently subject to certain restrictions contained in its bank loan agreement. See Item 7, "Management's Discussion and Analysis of Financial Condition - Liquidity and Capital Resources."
In addition, the Company has 690,000 shares of convertible preferred stock outstanding. These shares were issued in April 1993. The $3.50 convertible preferred stock is traded on the National Association of Securities Dealers, Inc. Automated Quotation System ("NASDAQ") under the symbol HWLLP. See Note 7 of Notes to Consolidated Financial Statements.
ITEM 6.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a discussion of the Company's financial condition, results of operations, capital resources and liquidity. This discussion and analysis should be read in conjunction with the Consolidated Financial Statements of the Company and the notes thereto. Management's review includes certain forward-looking statements reflecting the Company's expectations in the near future; however, many factors which may affect the actual results, especially commodity prices and changing regulations, are difficult to predict. Accordingly, there is no assurance that the Company's expectations will be realized.
RESULTS OF OPERATIONS
The Company's principal business segments are oil and gas production, crude oil marketing and transportation, and technical fuels and chemical processing. Results of operations by segment for the three years ended December 31, 1996 are discussed below. The table below for each segment's revenues does not reflect the elimination of intercompany revenues. See Note 8 of Notes to Consolidated Financial Statements.
OIL AND GAS PRODUCTION
YEAR ENDED DECEMBER 31, ----------------------------- 1996 1995 1994 ---- ---- ---- Revenues (in thousands): Sales of oil and natural gas................. $ 28,162 $27,011 $24,608 Sales of LaBarge other products.............. 1,493 1,990 2,227 Gas marketing................................ 3,553 2,196 1,560 Minerals leasing and other................... 660 304 523 ------- ------ ------ Total revenues.......................... $ 33,868 $31,501 $28,918 ======= ======= =======
Operating profit (in thousands).............. $ 8,682 $6,977 $6,224 ======= ====== ======
Operating information: Average net daily production: Oil and NGL (Bbls)....................... 3,300 3,791 3,663 Natural gas (Mcf)........................ 8,943 9,662 8,789
Average sales prices: Oil and NGL (per Bbl).................... $17.52 $15.67 $14.40 Natural gas (per Mcf).................... $ 2.06 $1.47 $1.70
REVENUES
Gas marketing revenues increased 62% in 1996 due to increased gas prices. Revenues from sales of oil and natural gas increased in 1996 when compared to 1995 as a result of an increase in the Company's average sales price of the oil offset by a decrease in the average daily production. Average oil sales prices increased 12% and were partially offset as daily oil production decreased 13%. The positive effects of an increase in the average gas sales price of 40% was partially offset by a 7% decline in daily gas production.
The Company has a revenue interest in 11 successful horizontal wells in central Texas. Horizontal wells have short lives, typically producing half of their reserves in the first six months. In 1996, oil and gas production from horizontal wells averaged 149 barrels and 215 Mcf per day. In 1995, horizontal well production contributed 192 barrels and 306 Mcf per day.
The effect on the annual average daily oil production of the Company's mineral fee properties in 1996 and 1995 was 181 and 208 barrels, respectively.
Revenues from the sales of the LaBarge other products are attributable to sales of carbon dioxide, helium and sulfur. The production level of helium was relatively stable in 1996 and 1995; however, carbon dioxide sales volumes declined due to a lack of market. The Company was also affected by a decline in helium and carbon dioxide per unit sales prices. Sulfur sales revenues in both years were insignificant.
Total revenues increased in 1995 when compared to 1994, primarily due to the acquisition of certain properties from Norcen Explorer, Inc., and an increase in oil prices of 9%. The increase was partially offset by a decrease in gas prices of 14% and a decrease in production from the Main Pass Field as a result of being shut-in for 19 days due to Hurricane Opal. Revenues from the sales of the LaBarge other products in 1995 decreased from 1994 levels due to declines in carbon dioxide sold.
OPERATING PROFIT
In 1996, the operating profit of this segment increased $1.7 million when compared to 1995. The average higher gas and oil sales prices were the largest factors in this increase in operating profit. The increase in gas marketing revenues was offset by an increase in gas marketing costs of 64%. Partially offsetting these improvements was an increased production cost per equivalent barrel of production from $4.47 in 1995 to $5.23 in 1996. This was primarily due to increased workover expense on an offshore gas supply well. Also reducing operating profit was an increase in depreciation, depletion and amortization ("DD&A") per equivalent barrel of production from $5.20 in 1995 to $5.37 in 1996. An increase in general and administrative costs from $1.6 million in 1995 to $1.9 million in 1996 also partially offset the improvements.
The increase in operating profit in 1995 when compared to 1994 was $0.8 million. Higher average oil sales prices combined with higher oil production were the largest factors in this increase. Also contributing to the increase was a decrease in general and administrative costs from $2.0 million in 1994 to $1.6 million in 1995. Partially offsetting these factors was an increase in DD&A per equivalent barrel of production from $4.96 in 1994 to $5.20 in 1995.
In 1997, the Company expects to use seismic data to identify prospects to drill in its core areas of emphasis. These areas are Texas, Louisiana, Mississippi and Alabama. The Company has also signed an agreement to work with an exploration company to assist in prospect generation. The Company continues to evaluate the potential of developmental drilling in Mississippi on acreage that it acquired in 1995 from Norcen.
CRUDE OIL MARKETING & TRANSPORTATION
YEAR ENDED DECEMBER 31, 1996 1995 1994 ---- ---- ---- (In thousands)
Revenues..................................... $666,086 $629,918 $407,530 ======== ======== ========
Operating profit............................. $9,610 $9,235 $3,374 ======== ====== ======
Revenues increased 6% in 1996 from $629.9 million in 1995 to $666.1 million in 1996, and operating profit increased 4% in 1996 from $9.2 million in 1995 to $9.6 million in 1996. The increase can be attributed to the Company's pipeline activities. Also contributing to the increase in operating profit was a decrease in general and administrative costs of $0.6 million from 1995 to 1996. The crude oil marketing activities accounted for an increase in operating profit of $1.1 million offset by a decrease in operating profit for transportation activities of $0.7 million.
Effective December 3, 1996, the Purchase & Sale and Contribution & Conveyance of Howell Crude Oil and Howell Transportation's assets and liabilities associated with crude oil gathering resulted in a pre-tax gain of $13,841,000.
Revenues increased 55% in 1995 as compared to 1994 due to a 42% increase in barrels sold per day and higher average crude oil prices. In 1994 the Company sold 67,174 barrels per day of crude oil. In 1995 that average daily sales quantity increased to 95,384 barrels. Also increasing revenues were the crude oil pipeline transmission activities of the segment. On March 31, 1995, the Company acquired three crude oil pipelines from Exxon. During the nine months the Company owned these pipelines, an average of 90,375 barrels per day were transported, generating revenues of $13.4 million. These revenues also include $1.0 million received from Exxon, representing nine months of rent under the terms of a one-year lease, of the 1.2 million barrels of tank space the Company owned in Northwest Houston. Transportation activities increased revenues by $2.6 million in 1995 as compared to 1994 due to a contract with Lyondell Petrochemical, to provide substantially all of its outbound truck transportation needs. This contract was in effect for the latter half of 1994 and all of 1995.
Operating profits of the crude oil marketing and transportation segment increased 174% from $3.4 million in 1994 to $9.2 million in 1995. This increase can be attributed to the Company's pipeline activities.
TECHNICAL FUELS AND CHEMICAL PROCESSING
YEAR ENDED DECEMBER 31, 1996 1995 1994 ---- ---- ---- (In thousands)
Revenues..................................... $30,527 $30,951 $29,580 ======= ======= =======
Operating profit (loss)...................... $ 1,064 $2,479 $ 579 ======= ====== ======
The technical fuels and chemical processing segment experienced a 1% decrease in revenues and a 57% decrease in operating profit when comparing 1996 to 1995. Revenues from chemical sales and toll processing rose significantly in 1996 resulting from a focus on acetate and ester manufacturers for the paint and coatings industry. Revenues from sales of research and reference fuels declined $1.8 million in 1996. Volumes sold decreased by 4%. These decreases are attributable to a focus by lubricant manufacturers and laboratories on product certification rather than testing to develop and certify products to meet new standards. Development is expected to increase again in 1997 in order to prepare to meet 1998 performance standards.
The $1.4 million reduction in operating profit from 1995 to 1996 was primarily due to $1.1 million recognized from the cancellation of the chemical contract in 1995 referred to below. The remaining $0.3 million was due to decline in research and reference fuels offset by a significant improvement in chemicals.
In 1995, the technical fuels and chemical processing segment experienced a 5% increase in revenues and a 328% increase in operating profit when compared to 1994. Revenues from chemical sales and toll processing rose slightly in 1995 resulting from a focus on acetate and ester manufacturers for the paint and coatings industry. Revenues from sales of research and reference fuels declined $2.4 million in 1995. Volumes sold decreased by 11%. Also contributing to higher revenues and to the improved operating results was the revenue recognized upon the cancellation of a long-term contract to process for a customer. The revenue and operating profit recognized by this contract cancellation was $1.1 million.
NET INTEREST EXPENSE
Interest expense in 1996 rose $0.4 million over the 1995 level. The primary reason for this increase was funds borrowed by the Company in March 1995 to finance the acquisitions of three crude oil pipelines from Exxon and certain oil and gas properties from Norcen. Long-term debt decreased from $104.3 million at December 31, 1995 to $26.4 million at December 31, 1996 due primarily to the repayment of the term loan and pay down of the revolving credit agreement with proceeds received from the conveyance of the Company's crude operations to Genesis. See Notes 5 and 6 of Notes to Consolidated Financial Statements.
Additionally, the increase in interest expense from higher average outstanding balances in 1996 was slightly offset by decreasing market interest rates. Market interest rates ranged from 8.25% to 8.5% throughout 1996, while in 1995 the rates fluctuated from 8.5% to 9%. Because substantially all of the Company's debt is subject to market rates, the lower 1996 rates contributed to an offset of the increase in 1996 interest expense. The rise in rates in 1995 led to the increase in interest expense in 1995 over 1994. Additionally, in 1995 the Company had a higher level of average debt outstanding than in 1994.
PROVISION FOR INCOME TAXES
In 1996 the Company's effective tax rate of 37% reflects the statutory federal rate and state income taxes less the effect of statutory depletion deductions in excess of cost basis. As the Company's pretax income increased, the effect of these deductions on the tax rate was less pronounced than in 1995 and 1994. In 1994, these deductions contributed to an effective tax rate that was less than the statutory federal rate.
LIQUIDITY AND CAPITAL RESOURCES
On March 31, 1995, the Company replaced its existing revolving credit/term loan agreement and letter of credit facility with two new credit facilities, the HPC Credit Facility and the HCO Credit Facility as discussed below. The revolving credit/term loan agreement was replaced with a new credit facility between Howell Petroleum Corporation and Bank One, Texas, N.A., Bank of Montreal, Compass Bank - Houston and Den norske Bank AS (the "HPC Credit Facility"). The borrowing base under the HPC Credit Facility was $40.5
million at December 31, 1996 and declines monthly by $1.0 million until such time as it is redetermined. In addition, on January 1, 1997, the borrowing base declined an additional $2.0 million. The borrowing base is reviewed semi-annually by the banks with mandatory payments if the borrowing base, as determined solely by the banks based on the Company's interest in proved oil and gas reserves, is less than the outstanding balance on the loan. The Company has assumed that although the borrowing base will decrease in 1997, the decrease would not result in a mandatory repayment under the terms of the HPC Credit Facility, and therefore none of the debt is reflected as a current obligation. The HPC Credit Facility provides for a revolving period until September 1, 1998, with interest to be paid monthly at the rate selected by the Company of either (1) a Floating Base Rate (as defined in the HPC Credit Facility) that is generally the prevailing prime rate or (2) a rate based on the London Interbank Offered Rate ("LIBOR"). A LIBOR-based rate of 7.6675% was applicable to $18.0 million of the outstanding balance under the HPC Credit Facility at December 31, 1996. The remainder of the outstanding balance of $22.5 million was subject to the Commitment Fee Rate of 3/8%. At the end of the revolving period, the revolving loan converts automatically to a four-year term loan, with principal payments to be made in 16 quarterly installments along with accrued interest on the unpaid principal balance. The HPC Credit Facility also provides for the issuance of letters of credit in an amount up to $5.0 million. The amount of letters of credit outstanding reduces the amount of the available commitment.
The HPC Credit Facility is collateralized by mortgages on substantially all of the Company's producing oil and gas properties, the common stock of HPC, the common stock of Howell Crude Oil Company ("HCO"), which holds the Genesis investment and the guarantee of the Company. There is no compensating balance requirement, and the HPC Credit Facility carries a commitment fee of 3/8% on the available portion of the commitment. The HPC Credit Facility limits the ability of the Company, without the banks' prior approval, to (i) declare or pay dividends on shares of any class of its capital stock any time a default or event of default (as defined in the HPC Credit Facility) exists or will result from such declaration or payment; (ii) enter into certain extraordinary corporate transactions, including a merger, consolidation, liquidation or dissolution; or (iii) during any 12-month period, dispose of assets having an aggregate book value of more than five percent of the Company's net worth. Material covenants and restrictions include requirements to maintain a ratio of current assets plus the available portion of the commitment to current liabilities of at least 1:1, to maintain tangible net worth, as defined in the HPC Credit Facility, of a floating amount that was $75.7 million at December 31, 1996, and to prohibit certain defined types of additional indebtedness and the granting of certain liens on the Company's assets without the banks' approval. Based on the terms of the HPC Credit Facility, at December 31, 1996, $14.3 million of the Company's retained earnings was unrestricted as to the payment of common and preferred dividends. This amount varies based on changes in the shareholders' equity of the Company.
The letter of credit facility was replaced with a new credit facility between Howell Crude Oil Company, Bank One, Texas, N.A., Bank of Montreal, Compass Bank - - Houston and Den norske Bank AS (the "HCO Credit Facility"). The funds generated as a result of the Purchase & Sale and Contribution & Conveyance of Howell Crude Oil and Howell Transportation's assets and liabilities associated with crude oil gathering were partially used to repay the HCO Credit Facility in full during 1996. The remainder of the funds were used to pay down the HPC Credit Facility.
In 1993 the Company issued 690,000 shares of $3.50 convertible preferred stock. The net proceeds from the sale were $32.9 million. Dividends on the convertible preferred stock are to be paid quarterly. Such dividends accrue and are cumulative. The Company has paid all dividends on time.
At December 31, 1996, the Company had negative working capital of $6.6 million. In 1996 it generated cash flow from operating activities of $27.2 million. The technical fuels and chemical processing segment is expected by the Company to continue to positively impact 1997 operating cash flow. The Company also expects a positive impact in 1997 due to lower interest expense from a decrease in debt levels.
The Company currently anticipates spending approximately $0.6 million during fiscal years 1997 and 1998 at various of its facilities for capital and operating costs associated with ongoing environmental compliance and will continue to have expenditures in connection with environmental matters beyond fiscal year 1998. The Company's Channelview facility, most of which has been constructed since 1988, was designed and engineered to comply with the more stringent current regulations. The Company has determined that the federal wastewater discharge permit at its Channelview facility may have expired prior to the transfer of the permit to
the Company. The Company is taking steps to resolve this matter. See Note 10 of Notes to Consolidated Financial Statements.
The Company believes that its cash flow from operations and amounts available under the HPC Credit Facility will be sufficient to satisfy its current liquidity requirements. At December 31, 1996, the Company had $22.5 million available to it under the HPC Credit Facility. A significant decline in the value of the Company's proved reserves could result in the bank reducing the borrowing base, causing mandatory payments under the HPC Credit Facility. While the Company does not expect this to happen in 1997, such payments would adversely affect the Company's ability to carry out its capital expenditure program.
In order to guarantee the Company a specific minimum sales price for its crude oil, the Company purchased a put option and sold a call option covering approximately 3,300 barrels per day of crude oil production for an 18-month period beginning March 1, 1995. The option strike prices are based on the average price of crude oil on the organized exchange with monthly settlement. The strike prices are $17 per barrel for the put option and $20 per barrel for the call option. During 1995, the monthly average sales price of crude oil on the organized exchange was between $17 and $20 per barrel; therefore, no options were exercised during the period.
During 1996, the monthly average sales price of crude oil on the organized exchange was between $17 and $20 per barrel for January and February; therefore, no options were exercised during the two months. The monthly average sales price for the remainder of the March 1, 1995 call option period, March 1996 through August 1996, was above the $20 ceiling. This resulted in collar payments of $0.9 million, excluding the premium amortization.
Upon the expiration of the 18-month option period, the Company purchased a $16.50 per barrel put option and sold a $21.10 per barrel call option covering 100,000 barrels of oil per month for a six-month period ending February 28, 1997. For September through December 1996, the monthly average sales price exceeded the ceiling price. This resulted in collar payments for the four-month period of $1.3 million.
In May 1996 the Company signed a letter of intent to begin negotiations to sell HHC to Schenectady. Subsequent to signing the letter of intent, negotiations between the Company and Schenectady were terminated. The Company continues to receive and evaluate inquiries about the sale of HHC.
In 1995 the Financial Accounting Standards Board issued Statements of Financial Accounting Standards Nos. 121 and 123 entitled "Accounting for the Impairment of Long-Lived Assets and Assets to Be Disposed Of" and "Accounting for Stock-Based Compensation," respectively. Statement No. 121 contains provisions for recording impairment of long-lived assets that are not expected to produce net cash flows in the future to fully recover the remaining cost of the related assets. The Company adopted Statement No. 121 in 1996 and did not record impairment on any of its assets.
Statement No. 123 permits, but does not require, a fair value-based method of accounting for employee stock option plans which results in compensation expense being recognized in the results of operations when stock options are granted. The Company plans to continue the use of its current intrinsic value-based method of accounting for such plans where no compensation expense is recognized. However, as required by Statement 123, the Company has provided pro forma disclosure of net income and earnings per share in the Notes to the Consolidated Financial Statements as if the fair value-based method of accounting had been applied.
ITEM 8.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The response to this item is submitted as a separate section of this report (see page 23).
ITEM 9.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Regarding Directors, the information appearing under the caption "Election of Directors" set forth in the Company's definitive proxy statement, to be filed within 120 days after the close of the fiscal year in connection
with the 1997 Annual Shareholders' Meeting, is incorporated herein by reference. Regarding executive officers, information is set forth below.
The executive officers are elected annually.
NAME AGE POSITION Paul N. Howell............ 78 President and Chief Executive Officer J. Richard Lisenby........ 53 Vice President and Chief Financial Officer Robert T. Moffett......... 45 Vice President, General Counsel and Secretary
Mr. Paul N. Howell is President and Chief Executive Officer of the Company. He has been Chief Executive Officer since 1955. He was elected President in September 1995. Prior to that time he served as Chief Executive Officer and Chairman of the Board.
Mr. J. Richard Lisenby was elected Vice President and Chief Financial Officer of the Company in December 1996. Prior to that time, Mr. Lisenby served as Treasurer of Columbia Gas Development, a subsidiary of Columbia Gas System.
Mr. Robert T. Moffett was elected Vice President and General Counsel of the Company in January 1994. He had served as General Counsel of the Company since September 1992. Prior to that time, Mr. Moffett was associated with the firm of Moffett & Brewster.
Regarding delinquent filers pursuant to Item 405 of Regulation S-K, the information appearing under the caption "Compliance with Section 16(a) of the Securities Exchange Act of 1934" set forth in the Company's definitive proxy statement, to be filed within 120 days after the close of the fiscal year in connection with the 1997 Annual Shareholders' Meeting, is incorporated herein by reference.
ITEM 11.

ITEM 11. EXECUTIVE COMPENSATION
The information appearing under the captions "Compensation of Executive Officers" and "Certain Transactions" set forth in the Company's definitive proxy statement, to be filed within 120 days after the close of the fiscal year in connection with the 1997 Annual Shareholders' Meeting, is incorporated herein by reference.
ITEM 12.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information appearing under the caption "Security Ownership of Management and Certain Beneficial Owners" set forth in the Company's definitive proxy statement, to be filed within 120 days after the close of the fiscal year in connection with the 1997 Annual Shareholders' Meeting, is incorporated herein by reference.
ITEM 13.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information appearing under the caption "Certain Transactions" set forth in the Company's definitive proxy statement, to be filed within 120 days after the close of the fiscal year in connection with the 1997 Annual Shareholders' Meeting, is incorporated herein by reference.
PART IV
ITEM 14.

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(1) and (2). The response to this portion of Item 14 is submitted as a separate section of this report (see page 23).
(a)(3) and (c). The response to this portion of Item 14 is submitted as a separate section of this report (see page 41).
(b). Reports on Form 8-K.
A report on Form 8-K was filed October 4, 1996 to disclose the termination of sale negotiations with Schenectady International, Inc., for the sale of the registrant's technical fuels and chemical processing assets.
A report on Form 8-K was filed December 18, 1996 to disclose the conveyance and sale of the registrant's crude oil gathering, marketing and transportation assets to Genesis Energy, L.P.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
HOWELL CORPORATION (Registrant)
By /s/ J. RICHARD LISENBY ................................ J. Richard Lisenby Vice President and Chief Financial Officer Principal Financial and Accounting Officer
Date: February 27, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.
SIGNATURE TITLE DATE ---------- ----- ---- Principal Executive /s/ PAUL N. HOWELL Officer and Director February 27, 1997 .................................... Paul N. Howell President and Chief Executive Officer
/s/ RONALD E. HALL Director February 27, 1997 .................................... Ronald E. Hall Chairman of the Board
/s/ JACK T. TROTTER Director February 27, 1997 .................................... Jack T. Trotter
/s/ ROBERT M. AYRES, JR. Director February 27, 1997 .................................... Robert M. Ayres, Jr.
/s/ WALTER M. MISCHER, SR. Director February 27, 1997 .................................... Walter M. Mischer, Sr.
HOWELL CORPORATION AND SUBSIDIARIES
FORM 10-K
ITEMS 8, 14(A) (1) AND (2)
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
The following consolidated financial statements of the registrant and its subsidiaries required to be included in Items 8 and 14(a)(1) are listed below:
PAGE Independent Auditors' Report.......................................... 24 Consolidated Financial Statements: Consolidated Balance Sheets........................................ 25 Consolidated Statements of Earnings................................ 26 Consolidated Statements of Changes in Shareholders' Equity......... 27 Consolidated Statements of Cash Flows.............................. 28 Notes to Consolidated Financial Statements......................... 29
The financial statement schedules are omitted because they are not applicable, are not required or because the required information is included in the Consolidated Financial Statements or notes thereto.
INDEPENDENT AUDITORS' REPORT
To Howell Corporation:
We have audited the accompanying consolidated balance sheets of Howell Corporation and its subsidiaries as of December 31, 1996 and 1995, and the related consolidated statements of earnings, changes in shareholders' equity, and cash flows for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Corporation'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, such consolidated financial statements present fairly, in all material respects, the financial position of Howell Corporation and its subsidiaries at December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Houston, Texas February 27, 1997
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Balance Sheets
DECEMBER 31, ------------------ 1996 1995 ---- ---- (In thousands) ASSETS Current assets: Cash and cash equivalents....................... $ 3,257 $ 3,742 Trade accounts receivable, less allowance for doubtful accounts of $267,000 in 1996 and $239,000 in 1995................................ 9,805 65,288 Inventories..................................... 2,530 5,428 Other current assets............................ 1,294 1,712 ------ ------ Total current assets......................... 16,886 76,170 ------ ------ Property, plant and equipment: Oil and gas properties, utilizing the full-cost method of accounting.................. 280,766 278,505 Fee mineral interests, unproven................. 18,180 18,188 Other........................................... 30,735 107,735 Less accumulated depreciation, depletion and amortization................................... (212,025) (209,087) ------- -------- Net property, plant and equipment............ 117,656 195,341 ------ ------ Investments in investees........................... 21,802 - Other assets....................................... 2,180 1,815 ------ ------ Total assets................................. $158,524 $273,326 ======== ========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities: Current maturities of long-term debt............ $ 5,868 $ 8,068 Accounts payable................................ 5,037 61,771 Accrued liabilities............................. 10,289 7,141 Income tax payable.............................. 2,340 - ------ ------ Total current liabilities.................... 23,534 76,980 ------ ------ Deferred income taxes.............................. 23,850 20,971 ------ ------ Other liabilities.................................. 511 150 ------ ------ Long-term debt and capital lease obligation........ 20,581 96,205 ------ ------ Commitments and contingencies
Shareholders' equity: Preferred stock, $1 par value; 690,000 shares issued and outstanding; liquidation value of $34,500,000 690 690 Common stock, $1 par value; 4,947,196 shares issued and outstanding in 1996; 4,933,446 shares issued and outstanding in 1995............. 4,947 4,933 Additional paid-in capital...................... 34,532 34,390 Retained earnings............................... 49,879 39,007 ------ ------ Total shareholders' equity................... 90,048 79,020 ------ ------ Total liabilities and shareholders' equity... $158,524 $273,326 ======== ========
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Statements of Earnings
YEAR ENDED DECEMBER 31, ---------------------------- 1996 1995 1994 ---- ---- ---- (In thousands, except per share amounts)
Revenues..................................... $712,391 $673,537 $448,952 -------- -------- -------- Costs and expenses: Products including operating expenses..... 685,201 646,676 431,783 Selling, general and administrative expenses.................................. 11,427 11,748 10,992 ------- ------- ------- 696,628 658,424 442,775 ------- ------- ------- Other income (expense): Interest expense.......................... (7,492) (7,109) (2,237) Interest income........................... 110 229 131 Equity in net earnings of investees....... 181 - - Gain on conveyance of assets.............. 13,841 - - Other, net................................ (64) 154 180 ------- ------- ------- 6,576 (6,726) (1,926) ------- ------- ------- Earnings from operations before income taxes. 22,339 8,387 4,251 Provision for income taxes................... 8,262 3,061 1,368 ------- ------- ------- Net earnings................................. $14,077 $5,326 $2,883 ====== ====== ======
Primary net earnings per common share........ $2.31 $0.59 $0.10 ====== ====== ====== Fully diluted earnings per common share...... $1.97 - - ====== ====== ======
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Statement of Changes in Shareholders' Equity
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Statements of Cash Flows
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Howell Corporation and its subsidiaries (the "Company"). The Company accounts for its investment in less than 50% owned investees using the equity method of accounting when it has the ability to exercise significant influence over operating and financial policies of the investee. All significant intercompany accounts and transactions have been eliminated.
NATURE OF OPERATIONS
The Company is primarily engaged in the exploration, production, acquisition and development of oil and gas properties. The Company is also involved in technical fuels and chemical processing and crude oil marketing and transportation. These operations are conducted in the United States. Information on the relative importance of the segments can be found in Note 8.
INVENTORIES
Inventories of refined products and crude oil are stated at the lower of market value or monthly weighted average cost. Other inventories are stated at the lower of average cost or market value.
PROPERTY, DEPRECIATION, DEPLETION AND AMORTIZATION
The Company follows the full-cost method of accounting for its oil and gas exploration and production activities, which are conducted solely in the United States. Consequently, all costs pertaining to the acquisition, exploration and development of oil and gas reserves are capitalized and amortized using the unit-of-production method as the remaining proved oil and gas reserves are produced. The Company's net investment in oil and gas properties is subject to a quarterly ceiling limitation calculation that is based on the present value of future net revenues from estimated production of proved oil and gas reserves valued at current prices. Costs in excess of the ceiling limitation are currently charged to expense. Gains or losses upon the disposition of a property, normally treated as an adjustment to capitalized costs, are recognized currently in the event of a sale of a significant portion (normally in excess of 25%) of oil and gas reserves.
The costs allocated to the unproven fee mineral interests of the Company are excluded from amortization using the full-cost method of accounting described above. These costs are reviewed periodically for impairment. This impairment will generally be based on geographic or geologic data. At the time of any impairment, the related costs will be added to the costs being amortized under the full-cost method of accounting. Due to the perpetual nature of the Company's ownership of these mineral interests, the drilling of a well, whether successful or unsuccessful, may not represent a complete test of all depths of interest. Therefore, at the time that a well is drilled only a portion of the costs allocated to the acreage drilled may be added to the costs being amortized.
Other property and equipment are carried at cost. Depreciation is provided principally using the straight-line method over the estimated useful lives of the assets, primarily 10 to 15 years for technical fuels and chemical processing and terminalling facilities and improvements, 20 years for pipelines and related assets, 20 to 25 years for buildings, and 2 to 5 years for transportation and operating equipment.
Maintenance and repairs are charged to expense as incurred, while renewals and betterments are capitalized.
INCOME TAXES
The Company utilizes a balance sheet (liability) approach in the calculation of the deferred tax balance at each financial statement date by applying the provisions of enacted tax laws to measure the deferred tax
consequences of the differences in the tax and financial (book) bases of assets and liabilities as they result in net taxable or deductible amounts in future years. The net taxable or deductible amounts in future years are adjusted for the effect of utilizing the carryback/carryforward attributes of any net losses generated and available tax credits.
EARNINGS PER COMMON SHARE
Primary earnings per common share have been computed by dividing net earnings, after reduction for preferred stock dividends, by the weighted average number of common shares and common share equivalents outstanding. Shares issuable in connection with stock options are included in the per share computations. The weighted average number of common shares and common share equivalents outstanding used in calculating primary earnings per share for 1996, 1995 and 1994 are 5,038,000, 4,976,000 and 4,893,000, respectively. Fully diluted earnings per share have been computed by dividing net earnings, after adjusting for the preferred stock dividends, by the weighted average number of common shares and common share equivalents outstanding and assuming conversion of the preferred stock. The weighted average number of common shares and common share equivalents used in calculating fully diluted earnings per share for 1996, 1995 and 1994 are 7,135,000, 7,086,000 and 6,984,000 respectively. Fully diluted earnings per share are not shown for 1995 and 1994 since the assumed conversion of the preferred stock was anti-dilutive.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Included in the statements of cash flows are cash equivalents defined as short-term, highly liquid investments that are readily convertible to cash and so near to maturity that their value would not change significantly because of changes in interest rates. The Company made cash payments for interest of $7,793,000, $6,435,000 and $2,179,000 in 1996, 1995 and 1994, respectively. In 1996, 1995 and 1994, cash payments for income taxes totaled $2,974,000, $1,158,000 and $126,000, respectively.
SUPPLEMENTARY OIL AND GAS PRODUCING INFORMATION (UNAUDITED)
The supplementary oil and gas producing information required by Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities," is included in Item 2 Properties in this annual report on Form 10-K.
DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company estimates that the carrying amount of its cash and cash equivalents and accounts receivable and payable as reflected in its balance sheet approximates fair value.
Information on the fair value of the Company's long-term debt can be found in Note 6.
ENVIRONMENTAL LIABILITIES
The Company provides for the estimated costs of environmental contingencies when liabilities are likely to occur and reasonable estimates can be made. In accordance with full cost accounting rules, the Company provides for future environmental clean-up costs associated with oil and gas activities as a component of its depreciation, depletion and amortization expense. Information regarding environmental liabilities can be found in Note 10. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred.
DERIVATIVES
Crude oil future contracts and options were used as a hedging tool in a limited program of hedging crude oil inventories and fixed purchase price commitments. Product costs of the crude oil marketing and transportation segment were reduced by $0.1 million in 1996, 1995 and 1994 from the effects of futures and options.
In addition, for the second half of 1994, the Company purchased a put option for its crude oil production to guarantee the Company a specific minimum sales price for the volume of production hedged. Because market prices were higher than the option strike price, the option was not exercised.
In 1995 the Company purchased a put option and sold a call option covering 3,300 barrels per day of oil production for an 18-month period beginning March 1, 1995. The option strike prices were based on the average price of crude oil on the organized exchange, with monthly settlement. The strike prices were $17 per barrel for the put option and $20 per barrel for the call option. The premiums for the options were amortized over the period. Upon expiration of the 18-month option period, the Company purchased a put option and sold a call option covering 100,000 barrels of oil per month for a six-month period ended February 28, 1997. The strike prices are $16.50 per barrel for the put option and $21.10 per barrel for the call option. There was no premium associated with these options.
During 1996, the monthly average price of crude oil on the organized exchange exceeded the strike price for the call option in ten months. The payments required in 1996 under the call options and the premium amortized in 1996 total $2.5 million and were recorded as a reduction of revenue. During 1995, the monthly average price of crude oil on the organized exchange was between $17 and $20 per barrel; therefore, none of the options were exercised during this period. Premiums amortized during 1995 totaled $0.4 million and were recorded as a reduction of revenue. In 1994 premiums amortized reduced revenues by $0.1 million.
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.
IMPAIRMENT OF LONG-LIVED ASSETS
In 1995 Statement of Financial Accounting Standards No. 121 ("Statement 121"), "Accounting for the Impairment of Long-Lived Assets and Assets to Be Disposed Of" was issued. Statement 121 contains provisions for recording the impairment of long-lived assets that are not expected to produce net cash flows in the future to fully recover the remaining cost of the related assets. The Company adopted Statement 121 in 1996. The Company did not record impairment on any of its assets.
STOCK-BASED COMPENSATION
In 1995, Statement of Financial Accounting Standards No. 123 ("Statement 123"), "Accounting for Stock-Based Compensation," was issued. Statement 123 permits, but does not require, a fair value-based method of accounting for employee stock option plans which results in compensation expense being recognized in the results of operations when stock options are granted. The Company plans to continue the use of its current intrinsic value-based method of accounting for such plans where no compensation expense is recognized. See Note 7.
NOTE 2. ACQUISITIONS & DISPOSITIONS
On December 31, 1996, the Company sold 100% of the outstanding common stock of Howell Transportation Services, Inc. (HTS) to Lodestar Logistics, Inc. ("Lodestar") for $2.6 million, consisting of $1.8 million in cash, a $0.5 million note receivable and a $0.3 million receivable in the form of services to be rendered by HTS, for Howell Hydrocarbons & Chemicals, Inc. Lodestar is owned by the former president of HTS, and the Company believes the sale price was equivalent to an arms-length transaction.
The $0.5 million non-revolving note bears interest at the Prime Rate (as defined below) based on a year of 360 days for the actual number of days elapsed. Prime Rate shall mean a fluctuating interest rate per annum as shall be in effect on the first day of each calendar quarter equal to the rate of interest published by THE WALL STREET JOURNAL as such day as the prime rate, principal amount of the loan during each calendar quarter shall be determined as of the opening of business on the first day of such calendar quarter. The term of the note shall be no longer than 84 months.
The note receivable and the receivable for future services are non-cash transactions and are not reflected in the statement of cash flows for the year ended December 31, 1996.
On March 31, 1995, the Company's crude oil marketing and transportation segment acquired from Exxon Pipeline Company ("Exxon") two interstate crude oil pipeline systems and one intrastate crude oil pipeline system. The interstate pipeline systems were located in Florida/Alabama ("Jay System") and Mississippi/Louisiana ("MS System"). The intrastate system was located in Texas ("Texas System"). Collectively, the purchase of these pipelines and related assets comprise the "Exxon Transaction."
The Texas System consisted of a 555-mile pipeline system extending from Groesbeck, Texas, south to Texas City, Texas, and tanks for crude oil storage with a total capacity of approximately 1.9 million barrels. The Jay System consists of a 90-mile pipeline system that extends west from Santa Rosa County, Florida to Mobile County, Alabama, and included tanks with approximately 0.2 million barrels of storage capacity. The MS system consisted of a 230-mile pipeline system extending from Jones County, Mississippi, to Baton Rouge, Louisiana, and included storage capacity of approximately 0.2 million barrels.
The total negotiated purchase price paid to Exxon for the Exxon Transaction was $63.5 million. The Exxon Transaction was financed through borrowings from banks.
On April 21, 1992, the Company sold its San Antonio, Texas, refinery for a sales price of $2.2 million. The Company received a downpayment of $0.4 million and a note requiring monthly principal and interest payments for three years. In 1993, the time period for repayment was extended one additional year. The interest rate for the note was 10%. Due to the uncertainty about the ultimate collection of the note receivable, the Company did not recognize gain on the sale or interest income on the note as payments were not made. In 1995 the Company agreed to accept $0.5 million in settlement of the balance remaining under the note. This settlement resulted in $0.4 million of income for the Company that is included in other income (expense) in the Consolidated Statement of Earnings for 1995.
NOTE 3. INVENTORIES
The major classes of inventory at December 31, 1996 and 1995 were as follows:
1996 1995 ---- ---- (In thousands)
Refined products........................................ $1,781 $1,494 Crude oil............................................... 151 2,140 Chemicals............................................... 560 1,695 Other materials and supplies............................ 38 99 ------ ------ $2,530 $5,428 ====== ======
NOTE 4. INCOME TAXES
A summary of the provision (credit) for income taxes included in the consolidated statements of earnings is as follows:
YEAR ENDED DECEMBER 31 ------------------------ 1996 1995 1994 ---- ---- ---- (In thousands)
Current: Federal........................................ $5,479 $ 356 $ - State.......................................... 475 438 161 Deferred........................................... 2,308 2,267 1,207 ------ ------ ------ $8,262 $3,061 $1,368 ====== ====== ======
Deferred income taxes are provided on all temporary differences between financial and taxable income. The approximate tax effects of each significant type of temporary difference and carryforward were as follows:
YEAR ENDED DECEMBER 31, -------------------------- 1996 1995 (In thousands)
Accrual of costs not deductible for tax............... $ 2,146 $ 864 Statutory depletion carryforwards..................... - 1,274 Minimum tax credit carryforwards...................... - 418 Net operating loss carryforwards...................... - 2,507 Other................................................. - 44 ------ ------- Total deferred tax assets............................. 2,146 5,107 ------ ------- Differences between book and tax bases of property, plant and equipment.................................. (25,991) (26,078) Other................................................. (5) - ------ ------- Total deferred tax liabilities........................ (25,996) ( 26,078) ------ ------- Net deferred income taxes....................... $(23,850) $(20,971) ======= =======
The following table accounts for the difference between the actual tax provision and the amounts obtained by applying the applicable statutory U.S. federal income tax rate to the earnings before income taxes:
YEAR ENDED DECEMBER 31, ------------------------- 1996 1995 1994 ---- ---- ---- (In thousands)
Provision for income taxes at the statutory rate... $7,819 $2,852 $1,445 Statutory depletion in excess of cost basis........ (292) (327) (237) State income taxes................................. 475 438 161 Other.............................................. 260 98 (1) ------ ------ ------ $8,262 $3,061 $1,368 ====== ====== ======
NOTE 5. INVESTMENT IN INVESTEES
On December 1, 1996, Genesis Crude Oil, L.P., a Delaware limited partnership ("Buyer"), Genesis Energy, L.P., a Delaware limited partnership ("MLP") and Genesis Energy, L.L.C., a Delaware limited liability company ("LLC"), entered into a Purchase & Sale and Contribution & Conveyance Agreement ("Agreement") with Howell Corporation and certain of its subsidiaries ("Howell") and Basis Petroleum, Inc. ("Basis"), a subsidiary of Salomon Inc. ("Salomon"). Pursuant to the Agreement, Howell agreed to sell and convey certain of its assets to Buyer. These assets consisted of the crude oil gathering and marketing operations and pipeline operations of Howell (referred to hereafter as the "Business").
Buyer was formed by MLP and LLC to acquire the Business from Howell and similar assets from Basis. MLP is owned 98% by limited partners and 2% by LLC, which is the general partner. LLC is owned 46% by Howell and 54% by Basis. As a result of this transaction, Howell owns a subordinated limited partner interest in Buyer of 9.01%, a direct general partner interest in Buyer of 0.18% and a general partner interest through MLP of 0.74% of Buyer.
In accordance with the Agreement, Howell received cash of approximately $74.0 million and 991,300 subordinated limited partner units in Buyer in exchange for its sale and conveyance of the Business and recognized a gain in the amount of approximately $13.8 million. The receipt of units is a non-cash transaction which reduced property, plant and equipment and increased investment in investees. Since this was non-cash, it is not reflected in the statement of cash flows for the year ended December 31, 1996. Except as specifically provided in the Agreement, Howell retained all liabilities related to the Business arising from the operations, activities and transactions of the Business up through the closing date, including various environmental-related liabilities. Howell made various representations and warranties as to itself and the Business and has agreed to indemnify Buyer for any breaches thereof. Claims for breaches of such representations and warranties must be
brought before December 3, 2001. Howell has also agreed to perform, and retain the liability for, the cleaning of certain tanks used in the pipeline operations.
On the closing date, Howell entered into various agreements with Buyer, MLP and LLC pursuant to the Agreement, including (a) a non-competition agreement prohibiting Howell from competing with the Business for a period of ten years; (b) an agreement relating to the purchase of crude oil by Howell for use in its technical fuels business and the sale of crude oil by Howell from its oil and gas exploration and production business; (c) an agreement whereby Howell will provide certain transitional services to Buyer; (d) an agreement whereby MLP will sell additional limited partner units to the public and use the proceeds to redeem the subordinated limited partner units in Buyer owned by Howell after certain conditions are met; and (e) an agreement whereby one-half of the subordinated limited partner units owned by Howell are pledged to secure Howell's indemnification of Buyer for environmental liabilities.
Also at closing, Howell entered into an agreement with Salomon which provides (a) an unconditional obligation of Howell to buy its 46% share of additional limited partner interests ("APIs") from Salomon if Howell (as a member of LLC) has approved an acquisition by Buyer and (b) to the extent APIs are outstanding, an obligation by Howell to purchase 46% of such outstanding APIs, but only to the extent of any distribution made to Howell by Buyer on Howell's subordinated limited partner units.
Summarized financial information for the Buyer for the period ended December 31, 1996 is as follows:
(In thousands)
Revenues.........................................$ 371,985 Net income....................................... 1,684 Current assets................................... 410,603 Property & equipment, net........................ 88,937 Current liabilities.............................. 398,794 Partners' capital................................ 111,338
At December 31, 1996, the amount of investment in the Buyer includes goodwill in the amount of $4.9 million which is being amortized over a period of 20 years.
NOTE 6. DEBT AND AVAILABLE CREDIT FACILITIES
Long-term debt and the capital lease obligation of the Company as of December 31, 1996 and 1995 were as follows:
1996 1995 ---- ---- (In thousands)
Note payable to Genesis LLC............................. $ 3,450 $ - Note payable under a $40.5 million revolving credit/term loan agreement.............................. 18,000 42,250 Note payable under a term loan agreement................ - 54,625 Note payable to Department of Energy (DOE).............. 4,999 7,265 Capital lease obligation for transportation equipment... - 133 ------ ------- 26,449 104,273 Less: Current maturities............................... 5,868 8,068 ------ ------- $20,581 $96,205 ======= =======
Maturities of long-term debt for the five years subsequent to December 31, 1996 are as follows (in thousands):
TOTAL
1997.............................. $5,868 1998.............................. 4,831 1999.............................. 4,500 2000.............................. 4,500 2001.............................. 4,500 Thereafter........................ 2,250 ------- $26,449 =======
REVOLVING CREDIT/TERM LOAN AGREEMENT
On March 31, 1995, the Company replaced its existing revolving credit/term loan agreement with a new credit facility. The revolving credit/term loan agreement was replaced with a new credit facility between Howell Petroleum Corporation and Bank One, Texas, N.A., Bank of Montreal, Compass Bank - Houston and Den norske Bank AS (the "HPC Credit Facility"). The borrowing base under the HPC Credit Facility was $40.5 million at December 31, 1996 and declines monthly by $1.0 million until such time as it is redetermined. In addition, on January 1, 1997, the borrowing base declined an additional $2.0 million. The borrowing base is reviewed semi-annually by the banks with mandatory payments if the borrowing base, as determined solely by the banks based on the Company's interest in proved oil and gas reserves, is less than the outstanding balance on the loan. The Company has assumed that although the borrowing base will decrease in 1997, the decrease would not result in a mandatory repayment under the terms of the HPC Credit Facility, and therefore none of the debt is reflected as a current obligation. The HPC Credit Facility provides for a revolving period until September 1, 1998, with interest to be paid monthly at the rate selected by the Company of either (1) a Floating Base Rate (as defined in the HPC Credit Facility) that is generally the prevailing prime rate or (2) a rate based on LIBOR. A LIBOR-based rate of 7.6675% was applicable to $18.0 million of the outstanding balance under the HPC Credit Facility at December 31, 1996. The remainder of the outstanding balance of $22.5 million was subject to the commitment fee rate of 3/8%. At the end of the revolving period, the revolving loan converts automatically to a four-year term loan, with principal payments to be made in sixteen quarterly installments along with accrued interest on the unpaid principal balance. The HPC Credit Facility also provides for the issuance of letters of credit in an amount up to $5.0 million. The amount of letters of credit outstanding reduces the amount of the available commitment.
The HPC Credit Facility is collateralized by mortgages on substantially all of the Company's producing oil and gas properties, the common stock of Howell Petroleum Corporation ("HPC"), the common stock of Howell Crude Oil Company ("HCO") which holds the Genesis investment and the guarantee of the Company. There is no compensating balance requirement, and the HPC Credit Facility carries a commitment fee of 3/8% on the available portion of the commitment. The HPC Credit Facility limits the ability of the Company, without the banks' prior approval, to (i) declare or pay dividends on shares of any class of its capital stock any time a default or event of default (as defined in the HPC Credit Facility) exists or will result from such declaration or payment; (ii) enter into certain extraordinary corporate transactions, including a merger, consolidation, liquidation or dissolution; or (iii) during any 12-month period, dispose of assets having an aggregate book value of more than five percent of the Company's net worth. Material covenants and restrictions include requirements to maintain a ratio of current assets plus the available portion of the commitment to current liabilities of at least 1:1, to maintain tangible net worth, as defined in the HPC Credit Facility, of a floating amount that was $75.7 million at December 31, 1996, and to prohibit certain defined types of additional indebtedness and the granting of certain liens on the Company's assets without the banks' approval. Based on the terms of the HPC Credit Facility, at December 31, 1996, $14.3 million of the Company's retained earnings was unrestricted as to the payment of common and preferred dividends. This amount varies based on changes in the shareholders' equity of the Company.
TERM LOAN AGREEMENT
From March 31, 1995, to December 31, 1996, the Company had a term loan agreement outstanding that was collateralized primarily by the Company's pipeline assets. The loan was repaid with the proceeds from the sale and conveyance referred to in Note 5.
DEPARTMENT OF ENERGY
As a result of an agreement settling allegations by the DOE against the Company related to crude oil pricing and allocation regulation violations in the 1970s, the Company agreed in 1989 to pay $19.4 million to the DOE. The remaining balance owed at December 31, 1996 was $5.0 million. The obligation bears interest at a trailing average prime rate. At December 31, 1996, that rate was 8.25%.
The payments required by the agreement may be accelerated at the Company's discretion or pursuant to a formula based on proceeds from any significant sale of assets by the Company or its affiliates. Asset sales in 1990 through 1995, based on the formula contained in the final order, did not result in an acceleration of principal payments. The sale of the Company's assets to Genesis in December 1996 resulted in an additional payment being due in January 1997. There is a provision in the agreement for securing the installment payments due the DOE, but only under certain conditions which are applicable in the event the Company's current secured lender releases its security. Other than the financial obligations discussed above, the agreement does not impose any restrictions or limitations on the manner in which the Company may conduct its business in the future.
OTHER
In July 1992 the Company entered into a capital lease for transportation equipment. The obligation was repaid in 1996.
FAIR VALUE OF LONG-TERM DEBT
The fair value of the Company's long-term debt at December 31, 1996 was estimated to be the same as its carrying value in the balance sheet since as all significant debt obligations bear interest at floating market rates.
NOTE 7. SHAREHOLDERS' EQUITY
PREFERRED STOCK
At December 31, 1996 and 1995, the Company had 3,000,000 shares of preferred stock authorized.
In April 1993 the Company completed a public offering of 690,000 shares of $3.50 convertible preferred stock. The offering was priced at $50 per share to yield 7%. The convertible preferred stock is convertible into common stock of the Company at the option of the holder, at any time, at a conversion rate equal to, approximately, 3.03 common shares for each preferred share, with fractional shares paid in cash. The Company has the option to redeem the convertible preferred stock at a declining premium redemption price beginning in 1996.
Dividends on the convertible preferred stock are to be paid quarterly. Such dividends accrue and are cumulative. Holders of the preferred stock have no voting rights except on matters affecting the rights of preferred shareholders. If at any time the equivalent of six quarterly dividends payable on the preferred stock are accrued and unpaid, the preferred shareholders will be entitled to elect two additional directors to the Company's Board of Directors. The Company is current in the payment of preferred dividends.
COMMON STOCK
At December 31, 1996 and 1995, the Company had 10,000,000 shares of common stock authorized.
Under the Company's 1988 Stock Option Plan, options to purchase 750,000 shares may be granted. At December 31, 1995, 182,670 options were exercisable at an average price of $10.32 per share. At December 31, 1996, 311,914 options were exercisable at an average price of $10.84 per share.
Stock option activity for the Company during 1996, 1995, and 1994 are as follows:
The Company accounts for the 1988 Plan in accordance with Accounting Principles Board Opinion No. 25 and related Interpretations, under which no compensation cost has been recognized for stock option awards. Had compensation cost for the 1988 Plan been determined consistent with Statement 123, the Company's pro forma net income would have been $13,970,000, pro forma primary net earnings per share would have been $2.29 and pro forma earnings per common share assuming full dilution would have been $1.96. The fair value of options granted under the Company's fixed stock option plans during 1996 was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions used: 1% dividend yield, expected volatility of 36.20%, risk-free interest rate of 8.00%, and expected lives of ten years. Because the Statement No. 123 method of accounting has not been applied to options granted prior to January 1, 1995, the resulting pro forma compensation cost may not be representative of what is to be expected in future years.
NOTE 8. SEGMENT INFORMATION
Financial information about the Company's continuing operations for each of the years ended December 31, 1996, 1995 and 1994 is summarized as follows:
In addition to the results of the Company's oil and gas exploration and production activities, the oil and gas production segment information includes the gas marketing activities of the Company and the results of production of carbon dioxide, helium and sulfur from the LaBarge Project.
Intersegment sales by the oil and gas production segment to the crude oil marketing and transportation segment were $15,438,000, $16,399,000 and $14,258,000 in 1996, 1995 and 1994, respectively. Intersegment sales by the crude oil marketing and transportation segment to the technical fuels and chemical processing segment in 1996, 1995 and 1994 were $1,607,000, $1,697,000 and $2,066,000, respectively. Intersegment sales by the oil and gas production segment to the technical fuels and chemical processing segment in 1996, 1995 and 1994 were $1,045,000, $737,000 and $768,000, respectively. These amounts have been eliminated in consolidation.
Marathon Oil Company, a customer of the crude oil marketing and transportation segment, accounted for approximately 18%, 12% and 18% of consolidated revenues in 1996, 1995 and 1994, respectively.
As a result of the sale and conveyance in 1996, referred to in Note 5, segment data for 1995 and 1994 have been reclassified to conform to the 1996 presentation.
NOTE 9. LITIGATION
DONNA REFINERY PARTNERS, LTD. V. HOWELL CRUDE OIL COMPANY AND HOWELL CORPORATION; Texas District Court; No. 89-033634. In December 1993 a jury verdict of $1.9 million was rendered against the Company which was subsequently reduced by the judge to approximately $675,000. The Company believes the judgment is in error. The Company filed a motion for a new trial that was denied, so the Company appealed the decision. The plaintiff has filed an appeal to increase the recovery by $1.25 million. On June 6, 1996, the Fourteenth Court of Appeals affirmed the judgment of the lower court. The Company has appealed this case to the Texas Supreme Court. The Company does not believe that the ultimate resolution of this matter will have a materially adverse effect on the financial position, results of operations or cash flows of the Company.
On July 11, 1995 the Company received a demand letter from several working interest owners in the North Frisco City Field and in the North Rome Field indicating the Company had not paid according to the terms of a "call on production." The Company was granted a call on a portion of this production but has never exercised the call. Accordingly, the Company has filed petitions for declaratory judgment to that effect in cases styled HOWELL PETROLEUM CORPORATION, ET AL, VS. SHORE OIL COMPANY, ET AL, District Court of Harris County, Texas; No. 95-037480 and HOWELL PETROLEUM CORPORATION, ET AL, VS. TENEXCO, INC., ET AL, District Court of Harris County, Texas; No. 95-037970. The defendants in this action have counterclaimed against the Company. These claims are similar in nature to the Alabama and Mississippi royalty litigation. One of the defendants, John Faulkinberry, has filed a counterclaim against the Company seeking actual damages of $75,000 and punitive damages of $100,000,000.
Related to this matter, several royalty owners have filed lawsuits against the Company in Alabama and Mississippi concerning pricing in the North Frisco City Field. The lawsuits allege the Company violated its contracts with the plaintiffs by not paying the plaintiffs ". . . the highest available price for oil." Damages claimed by the plaintiffs include approximately $3.8 million and are based on numerous damage theories including, but not limited to, allegations of breach of contract and fraud. The complaints also seek unspecified punitive damages in the Alabama lawsuits and $7 million punitive damages in the Mississippi lawsuit. The Company filed answers denying all charges. The Company does not believe that the ultimate resolution of these matters will have a materially adverse effect on the financial position, results of operations or cash flows of the Company.
There are various other lawsuits and claims against the Company, none of which, in the opinion of management, will have a materially adverse effect on the Company.
NOTE 10. COMMITMENTS AND CONTINGENCIES
The Company is subject to various environmental regulations and laws. Procedures exist within the Company to monitor compliance and assess the potential environmental exposure of the Company. The Company believes that such exposure is not material to its financial position, results of operations or cash flows.
The Company has indemnified Exxon for certain environmental claims that may be made in the future attributable to the time when Exxon owned the crude oil pipelines that the Company acquired from Exxon. Management does not believe the indemnification of Exxon for these environmental liabilities will have a material financial impact on the financial position, results of operations or cash flows of the Company.
In January 1995 an Agreed Order with the Texas Natural Resource Conservation Commission was signed by the Company with respect to alleged violations of rules regarding the permitting and storage of hazardous wastes at a facility that was previously owned by the Company. Penalties totaling $26,000 were assessed and paid by the Company. During 1996, 1995 and 1994, the Company incurred costs of $0, $28,000 and $213,000, respectively, related to remediation and disposal of the hazardous wastes. Additional testing and monitoring of the groundwater and formal approval of the remediation work are still required. The Company has completed the remediation work related to hazardous waste storage rule violations. The new owner of the facility accepted responsibility for the first $100,000 of costs related to additional testing, monitoring and remediation, if necessary, of the groundwater. Since the costs for these activities have exceeded $100,000, the Company is responsible for the balance of the additional costs. The Company does not believe that this matter will have a material adverse effect on the financial condition or results of operations of the Company.
The Channelview facility is discharging wastewater pursuant to a state wastewater discharge permit. Industries located in the state of Texas are required to obtain wastewater discharge permits from the state and from the Environmental Protection Agency ("EPA"). When the Company purchased the Channelview facility in 1988, it requested and obtained a transfer of these permits. In 1990, the Company applied for a renewal of both the federal and the state wastewater permits. The state permit was reissued in 1992. During 1993, the Company determined that the federal wastewater discharge permit may have expired prior to the EPA's transfer of the permit to the Company. The EPA has been contacted to resolve this issue, and the Company will be negotiating to obtain a renewed permit. Penalties may potentially be imposed upon the Company as a result of this matter; however, until this matter is resolved, the amount of such penalties, if any, cannot be quantified. While penalties may be material and the actions of regulatory bodies are not subject to accurate prediction, based on information currently available to the Company and on the circumstances present at its Channelview facility (including the existence of the state permit, the Company's compliance with the more stringent state permit and the ability, if required, to operate the Channelview facility utilizing holding tanks and offsite third party treatment facilities in the absence of a permit), the Company does not believe that this matter will have a materially adverse effect on the financial condition or results of operations of the Company.
The Company occupies office and operational facilities and uses equipment under operating lease arrangements. Expense of these arrangements amounted to $2,765,000 in 1996, $2,201,000 in 1995 and $2,078,000 in 1994. At December 31, 1996, long-term commitments for lease of facilities and equipment totaled approximately $5,469,000, consisting of $678,000, $578,000, $655,000, $674,000 and $672,000 for the years 1997 through 2001, respectively, and $2,212,000 thereafter.
HOWELL CORPORATION AND SUBSIDIARIES
Form 10-K Index to Exhibits
Exhibits not incorporated herein by reference to a prior filing are designated by an asterisk (*) and are filed herewith. Exhibits designated by two asterisks (**) are incorporated herein by reference to the Company's Form S-1 Registration Statement, registration No. 33-59338, filed on March 10, 1993.
EXHIBIT NUMBER DESCRIPTION
3.1 ** Certificate of Incorporation, as amended, of the Company. 3.1(a) Certificate of Amendment to the Certificate of Incorporation of the Company (filed as an exhibit to the Company's Report on Form 10-Q for the quarterly period ended June 30, 1994). 3.2 ** By-laws of the Company. 10.1 ** Howell Corporation 1988 Stock Option Plan. 10.2 ** First Amendment to the Howell Corporation 1988 Stock Option Plan. 10.3 ** Second Amendment to the Howell Corporation 1988 Stock Option Plan. 10.4 ** Form of Stock Option Agreement. 10.5 Third Amendment to the Howell Corporation Stock Option Plan (filed as an Exhibit to the Company's Report on Form 10-Q for the quarterly period ended June 30, 1994). 10.6** Form of Indemnity Agreement by and between the Company and each of its directors and executive officers. 10.7 Credit Agreement Among Howell Petroleum Corporation, as Borrower, Bank One, Texas, N.A. as Agent and as a Lender, Bank of Montreal, as a Lender, Compass Bank - Houston as a Lender and Den norske Bank AS, as a Lender, dated as of March 31, 1995 (filed as an Exhibit to the Company's Report on Form 10-Q for the quarterly period ended March 31, 1995). 10.8 Guaranty by Howell Corporation in Favor of Bank One, Texas, National Association, as Agent, dated as of March 31, 1995 Credit Facility to Howell Petroleum Corporation (filed as an Exhibit to the Company's Report on Form 10-Q for the quarterly period ended March 31, 1995). 10.13 ** Split Dollar Life Insurance Agreement dated January 27, 1990 between the Company, Steven K. Howell, Douglas W. Howell, David L. Howell, Bradley N. Howell and Charles W. Hall, Trustee of the Howell 1990 Children's Trusts. 10.14 ** Deferred Compensation and Salary Continuation Agreement dated January 23, 1990 by and between the Company and Paul N. Howell. 10.15 ** United States of America Department of Energy Economic Regulatory Administration Consent Order with the Company dated as of February 23, 1989. 10.16** Letter from the Department of Energy to the Company dated September 10, 1992 modifying the terms of the Consent Order. 10.19** United States Department of the Interior Bureau of Land Management Oil and Gas Lease of Submerged Lands under the Outer Continental Shelf Land Act by and between the United States of America and Howell Petroleum Corporation effective as of December 1, 1981. 10.20** United States Department of the Interior Minerals Management Service Oil and Gas Lease of Submerged Lands under the Outer Continental Shelf Lands Act by and between the United States of America and Total Petroleum, Inc., effective as of July 1, 1983. 10.21** Assignment, Bill of Sale and conveyance by Total Petroleum, Inc., as assignor, to Oil Acquisitions, Inc., dated January 19, 1989.
EXHIBIT NUMBER DESCRIPTION
10.22** Unit Operating Agreement 7300' Sand Unit, Blocks 64 and 65 Main Pass Area, Offshore Plaquemines Parish, Louisiana, by and among Howell Petroleum Corporation, Oil Acquisitions, Inc., Woods Petroleum Corporation, BHP Petroleum (Americas) Inc. and Challenger Minerals, Inc., dated as of March 1, 1990. 10.23** Unit Agreement for Outer Continental Shelf Development and Production Operations on the 7300' Sand Unit, Blocks 64 and 65, Main Pass Area, Offshore Plaquemines Parish, Louisiana, by and among Howell Petroleum Corporation, Oil Acquisitions, Inc., Woods Petroleum Corporation, BHP Petroleum (Americas) Inc. and Challenger Minerals, Inc., dated as of April 19, 1990. 10.24** Processing Agreement by and between Howell Petroleum Corporation and Exxon Company, U.S.A., effective as of August 1, 1988. 10.25 Purchase and Sale Agreement between Federal Intermediate Credit Bank of Jackson and Howell Petroleum Corporation (filed as an exhibit to the Company's Report on Form 10-Q for the quarterly period ended June 30, 1993). 10.26 Lease Agreement by and between Texas Commerce Bank National Association and Howell Corporation dated as of December 13, 1993 (filed as an exhibit to the Company's Report on Form 10-K for the year ended December 31, 1993). 10.27 First Amendment to Lease Agreement by and between Texas Commerce Bank National Association and Howell Corporation effective as of October 5, 1995 (filed as an exhibit to the Company's Report on Form 10-K for the year ended December 31, 1995). 10.28 Second Amendment to Lease Agreement by and between Texas Commerce Bank National Association and Howell Corporation effective as of November 21, 1995 (filed as an exhibit to the Company's Report on Form 10-K for the year ended December 31, 1995). 11 * Computation of Earnings per Share. 21 * Subsidiaries of the Company. 23 * Consent of Deloitte & Touche LLP. 27 * Financial Data Schedule.