Item 1. Business
A. General
Howell Corporation and its subsidiaries (the Company) is primarily engaged in exploration, production, acquisition and development of oil and gas properties. The Company is also involved in compatible crude oil marketing, technical fuels and chemical processing, and transportation. 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, 1994, the Company's estimated proved oil reserves were 7,216 MBbl and estimated proved natural gas reserves were 70,939 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 4,810 MBbl and 55,699 MMcf of the Company's estimated proved reserves of oil and natural gas, respectively, at December 31, 1994. 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 (79,904 MMcf and 1,422 MMcf, respectively, at December 31, 1994). 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 69 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, regulations by state and federal authorities, and the cost of complying with applicable environmental regulations.
Crude Oil Marketing
Howell Crude Oil Company (HCO), a wholly-owned subsidiary with 28 employees, conducts the operations of the Company's crude oil marketing segment. HCO has the responsibility for supplying the Company's technical fuels segment with crude oil and purchases, markets and exchanges about 67,000 BPD of crude oil and condensate from approximately 400 operators and marketers. The Company moves crude oil by common carrier pipelines or by Company trucks to pipeline injection points and to customers' facilities. HCO focuses its third-party operations on smaller producers, emphasizing service to the producer as a way to distinguish HCO from its competitors. HCO also owns a 5.5 mile pipeline in the Gulf of Mexico, which is used to transport the Company's Main Pass production. In addition, HCO has access to 32 pipeline injection points in Texas, Mississippi, Louisiana and Florida. In seeking the best price for the crude oil, HCO often enters into exchange agreements with others to take advantage of quality and location differentials. Sales of crude oil to Marathon Oil Company accounted for approximately 18% of the Company's consolidated revenues in 1994.
Profit margins in crude oil marketing are small and significantly influenced by both the real and expected volatility in crude oil prices as well as intense competition throughout the industry. The Company competes with four national and six regional gatherers. In 1993, the Company initiated a limited program of hedging its crude oil inventories to minimize the effects of future price fluctuations. With the continuing
decline in domestic crude oil production, larger companies with the financial ability to withstand significant market swings might have an advantage.
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 55 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 the technical fuels operations a 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 growing demand for technical fuels.
HHC has conducted chemical toll processing and product terminalling activities at the Channelview facility for six years. In 1992, 1993 and 1994, toll processing operations were 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.
The synthesis reaction unit capabilities that the Company can now offer are expected to significantly expand the tolling and manufacturing services of HHC. A portion of this new capability will be utilized under the terms of a six-year contract the Company has negotiated with a major chemical company. Production of the new chemical compounds under this contract began in February 1994.
With the completion of construction, HHC has turned its attention to obtaining additional long-term toll manufacturing contracts. HHC has competition for these 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.
Transportation
Howell Transportation Services, Inc. (HTS), a wholly-owned subsidiary with 152 employees, conducts the Company's bulk liquids truck transportation operations. With Interstate Commerce Commission authority to provide transportation services throughout the United States, HTS can satisfy the existing needs of its affiliates and seek opportunities to haul bulk liquids for third parties as well. In 1994, HTS saw a significant increase in its revenues from third party carriage.
HTS operates a fleet of 74 tractors and 112 trailers used to haul crude oil, petroleum specialty products, petrochemicals and chemicals. HTS' trailer fleet consists of 51 aluminum crude oil trailers, each capable of hauling about 200 barrels of oil, 47 stainless steel trailers, each capable of hauling up to 6,950 gallons of chemicals, and 14 specially designed, high volume aluminum product trailers, each capable of hauling up to
8,500 gallons of compatible chemicals and petroleum products. The addition of specially designed aluminum trailers to the fleet has given HTS a cost advantage over its competitors, which generally provide only the lower volume stainless steel trailers. HTS expends considerable effort on driver safety and training programs and has been successful in reducing employee turnover. HTS competes with many other entities in providing transportation services. Many of these competitors have greater financial resources and a larger number of trucks than HTS. HTS competes with other entities on the basis of price, quality of equipment and personnel, safety record and service. Meeting tight product quality specifications and delivery deadlines has been important to Howell since it began operating trucks for its own products in 1955.
B. Governmental and Environmental Regulation
Governmental Regulation
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 regulation. 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. Federal and state authorities also regulate the transportation of petroleum products and chemicals.
Environmental Regulation
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, transportation, 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 9 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 material 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 run-off, 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 four main business segments, the Company has 25 other employees, for a total of 329 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 5 of Notes to Consolidated Financial Statements.
Oil and Gas Wells
As of December 31, 1994, the Company owned interests in productive oil and gas wells (including producing wells and wells capable of production) as follows:
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, 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 below 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, 1991 6,530,556 71,743,910 Revisions of previous estimates (81,907) (1,014,756) Extensions, discoveries & other additions 1,072,485 1,700,108 Purchases of minerals in place 263,693 586,021 Production (881,799) (3,911,896) Sales of minerals in place (42,644) (6,917) --------- ----------- As of December 31, 1992 6,860,384 69,096,470 Revisions of previous estimates 115,544 770,842 Extensions, discoveries & other additions 1,026,261 2,358,595 Purchases of minerals in place 567,901 2,723,519 Production (1,204,948) (3,652,022) Sales of minerals in place (94,221) (603,424) ----------- ---------- 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 ========== ==========
Proved developed reserves: December 31, 1991 3,589,150 70,808,938 December 31, 1992 4,167,854 68,001,964 December 31, 1993 6,782,015 63,618,243 December 31, 1994 6,201,176 63,677,432
Proved oil reserves at December 31, 1994 include 378,185 barrels of natural gas liquids.
The reserves as of December 31, 1994, shown in the table above include 461,233 barrels of oil and 3,248,244 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 79,903,890 Mcf and proved helium reserves of 1,422,181 Mcf at December 31, 1994.
Oil and Gas Leaseholds
The following table sets forth the Company's ownership interest in leaseholds as of December 31, 1994. 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.
In addition to the acreage under leaseholds as shown above, the Company owns the fee mineral acreage shown in the table below:
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
1994 0.53 2.17 2.03 - 1993 0.05 0.79 3.34 0.67 1992 0.96 1.61 2.33 0.46
The table above reflects only the drilling activity in which the Company had a working interest participation. In addition, in 1994, 18 gross productive wells 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
1994 1993 1992 Average sales prices: Crude oil, condensate and natural gas liquids (per Bbl) $14.40 $15.86 $18.79 Natural gas (per Mcf) $1.70 $1.87 $1.72 Production (lifting) costs (per equivalent barrel of production) $4.23 $5.18 $5.48 Amortization (per equivalent barrel of production) $4.96 $4.68 $4.30
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, 1994 December 31, 1993 (In thousands) Capitalized Costs: Oil and gas producing properties, all being amortized $264,430 $256,227 Fee mineral interests, unproven 18,200 18,260 -------- -------- Total $282,630 $274,487 ======== ======== Accumulated depreciation, depletion and amortization $178,147 $169,142 ======== ========
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, 1994 1993 1992 (In thousands) Property acquisition: Unproved fee mineral interests $ 3 $18,260 $ - Unproved leaseholds 792 225 210 Proved properties - 6,868 1,536 Exploration 3,252 2,794 3,300 Development 5,559 7,622 6,192 ------ ------- ------- $9,606 $35,769 $11,238 ====== ======= =======
Included in proved property acquisition costs for the year ended December 31, 1993, is $6,061,000 expended for the producing fee mineral interests acquired from the Federal Intermediate Credit Bank of Jackson, Mississippi.
In 1994, $63,000 of cost of unproved mineral interests was transferred to the full-cost pool, representing the cost of mineral properties that were drilled and evaluated during the year. This transfer of costs is 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, 1994 1993 1992 (In thousands)
Revenues $24,608 $26,757 $23,521 Production (lifting) costs 7,914 9,393 8,410 Depreciation, depletion and amortization 9,282 8,483 6,603 ------ ------ ------ 7,412 8,881 8,508 Income tax expense 2,283 2,800 2,622 ------ ------ ------
Results of operations (excluding corporate overhead and interest cost) $5,129 $6,081 $5,886 ====== ====== ======
Included in the 1994 and 1993 amounts above are $1,908,000 and $1,104,000 of revenues and $141,000 and $76,000 of production costs, respectively, from the production from 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 1994 and 1993. 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, 1994 1993 (In thousands)
Future cash inflows $218,234 $223,095 Future production costs 83,823 98,771 Future development costs 11,057 5,740 Future income tax expenses 25,286 22,167 -------- -------- Future net cash flows 98,068 96,417 10% annual discount for estimated timing of cash flows 29,633 32,156 -------- -------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves $ 68,435 $64,261 ======== =======
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, 1994 1993 1992 (In thousands) Sales and transfers, net of production costs $(16,693) $(17,363) $(15,110) Net changes in prices and production costs 7,354 (12,012) (261) Extensions and discoveries, net of future production and development costs 17,850 12,325 16,082 Purchases of minerals in place - 7,967 2,625 Sales of minerals in place (1,546) (1,145) (134) Previously estimated development costs incurred during the period (446) (1,811) (1,997) Revisions of quantity estimates (1,453) 1,018 (1,045) Accretion of discount 6,426 5,802 5,042 Net change in income taxes (994) 5,334 (2,433) Changes in production rates (timing) and other (6,324) 6,124 4,831 -------- -------- -------- Net change $ 4,174 $ 6,239 $ 7,600 ======== ======== ========
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, 4,810 MBbl and 55,699 MMcf of the Company's estimated proved reserves of oil and natural gas, respectively, at December 31, 1994. 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 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, one gas injection well, and designed, constructed and placed on-line 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 twelve years has totaled 9,021 MBbl of oil and 24,892 MMcf of natural gas. During the fourth quarter of 1994, net production averaged 1,220 BOPD and 173 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, 1994 were 3,622 MBbl of oil and 7,346 MMcf of natural gas, representing 50% and 10%, respectively, of the Company's proved oil and natural gas reserves.
North Frisco City Field. The North Frisco City Field (North Frisco City), 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 is producing 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 1,128 BPD of crude oil, 208 BPD of natural gas liquids and 1,066 McfPD of natural gas during the fourth quarter of 1994.
The Company's estimated proved reserves from its working interest in North Frisco City at December 31, 1994 were 1,188 MBbl of oil and 2,608 MMcf of natural gas, representing approximately 16% 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. Analysis of reservoir and production data from this field indicates that a pressure maintenance program could substantially increase the amount of proved reserves. The Company plans to initiate this type of program in 1995.
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.
In 1994 the producing acreage produced 72,801 barrels of oil and 443,378 Mcf of natural gas at average sales prices of $14.41 per Bbl and $1.79 per Mcf, respectively. Proved reserves attributable to the producing acreage at December 31, 1994, were 461 MBbl of oil and 3,248 MMcf of natural gas.
The non-producing fee mineral properties generate lease bonus and delay rental revenues. During 1994 and the period in 1993 while the Company owned the properties, revenues of $0.5 million and $0.1 million, respectively, were generated from these types of activities.
In February 1994, the Company entered into a joint venture with several industry companies to pursue exploration and development opportunities derived from the Company's fee mineral interests. Howell continues to receive all of the revenues from lease bonuses, delay rentals and its royalty interests in the fee mineral properties. The purpose of the joint venture is to actively participate, as working interest owners, in drilling prospects brought to the Company by explorationists who actively generate in the Mississippi and Alabama areas where the Company's fee mineral acreage is located.
LaBarge Project. The LaBarge Project, located in southwestern Wyoming, consists of three federal units, seventeen 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 McfPD 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) 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 which provided for an initial processing fee equal to 65% of the sales value of the plant product 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 below 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.
Until October 1994, the Company, Exxon and Bechtel Enterprises, Inc. (Bechtel) had an exclusive site development agreement for an electric cogeneration facility at the LaBarge gas processing plant. The parties allowed the agreement to expire as efforts to locate electric supply contracts continue.
Based on the business concepts and strategies the Company established during the early stages of developing the proposed LaBarge cogeneration plant, the Company began to investigate other geographic areas in which some of the same concepts and strategies may apply. As a result of this investigation, the Company and Bechtel entered into an exclusive site development agreement with Conoco Inc. to develop a similar project in New Mexico. Additional agreements with Sonat Inc. for a facility in Mississippi and Amoco Canada Petroleum Company Ltd. for a facility in Canada were also negotiated. The Conoco and Sonat agreements expire in the third quarter of 1995 and the Amoco agreement expires in 1996.
If the companies successfully obtain contracts to supply electricity to be generated from the proposed cogeneration plants, then definitive agreements covering ownership, gas supply, site lease, financing and other matters must be negotiated. The proposed cogeneration plants are subject to a number of contingencies, some of which have been outlined above. There can be no assurance that all of these contingencies will be met or that any of these projects will proceed.
B. Other Properties
In addition to the oil and gas properties described above, the Company and its subsidiaries lease approximately 47,500 sq. ft. 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 sq. ft.
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 material adverse effect on the financial condition or results of operations of the Company. See Note 8 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 ending High Low $
March 31, 1993 14 1/4 10 7/8 0.04 June 30, 1993 14 7/8 12 1/4 0.04 September 30, 1993 14 1/4 10 7/8 0.04 December 31, 1993 12 1/8 10 1/2 0.04 March 31, 1994 13 5/8 11 0.04 June 30, 1994 12 1/8 10 1/2 0.04 September 30, 1994 12 1/4 10 7/8 0.04 December 31, 1994 13 1/4 11 1/4 0.04
Approximate number of equity shareholders as of December 31, 1994: 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 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 6 of Notes to Consolidated Financial Statements.
Item 6.
Item 6. Selected Financial Data
The information below is presented in order to highlight significant trends in the Company's results from continuing operations and financial condition. See Consolidated Financial Statements and notes thereto.
The loss from operations in 1991 includes a pre-tax write-down of the Company's oil and gas assets of $11,830,000.
Summarized below are the Company's unaudited quarterly financial data for 1994 and 1993.
1994 Quarters First Second Third Fourth (In thousands, except per share amounts)
Revenues $87,674 $109,013 $120,530 $131,735 Earnings before income taxes $505 $1,330 $1,309 $1,107 Net earnings $352 $905 $876 $750 Net earnings (loss) per common share $(.05) $.06 $.06 $.03
1993 Quarters First Second Third Fourth (In thousands, except per share amounts)
Revenues $112,964 $109,822 $98,119 $90,831 Earnings before income taxes $622 $917 $1,337 $715 Net earnings $437 $641 $942 $507 Net earnings (loss) per common share $.09 $.04 $.07 $(.02)
Item 7.
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.
RESULTS OF OPERATIONS
The Company's principal business segments are oil and gas production, crude oil marketing, technical fuels and chemical processing, and transportation. Results of operations by segment for the three years ended December 31, 1994 are discussed below. The table below for each segment's revenues does not reflect the elimination of intercompany revenues. See Note 7 of Notes to Consolidated Financial Statements.
Oil and Gas Production
Year Ended December 31, 1994 1993 1992 Revenues (in thousands): Sales of oil and natural gas $24,608 $26,757 $23,521 Sales of LaBarge other products 2,227 2,582 2,651 Gas marketing 1,560 1,842 8,597 Minerals leasing and other 523 100 - ------- ------- ------- Total revenues $28,918 $31,281 $34,769 ======= ======= =======
Operating profit (in thousands) $6,224 $7,287 $6,954 ====== ====== ======
Operating information: Average net daily production: Oil (barrels) 3,663 3,301 2,409 Natural gas (Mcf) 8,789 10,006 10,688
Average sales prices: Oil (per barrel) $14.40 $15.86 $18.79 Natural gas (per Mcf) $1.70 $1.87 $1.72
Revenues
Revenues from sales of oil and natural gas decreased in 1994 when compared to 1993 despite an 11% increase in the Company's average daily oil production. This decline in revenues was primarily due to 9% decreases in average sales prices of both oil and natural gas and a 12% decline in gas production. The increase in oil production is attributable to production from horizontal well successes, a full year of production
from the minerals properties acquired in August 1993 and a slight increase in oil production at the Company's Main Pass Field.
At the Company's Main Pass Field, the effects of the waterflood project became even more evident. Net oil production at the Main Pass Field improved from the 1993 average of 1,107 barrels per day to 1,250 barrels per day in 1994. The expected decline in natural gas production from the 7,300' sand that began in the latter half of 1993 continued throughout 1994. In 1993, net natural gas production at this field averaged 1,334 Mcf per day, although in the fourth quarter of 1993 the average was 303 Mcf per day. The average net natural gas production in 1994 was even lower at 169 Mcf per day.
The Company has a revenue interest in nine successful horizontal wells in central Texas. Horizontal wells have short lives, typically producing half of their reserves in the first six months. In 1994, oil production from horizontal wells averaged 244 barrels per day. In 1993, horizontal well production contributed 136 barrels per day.
The effect on the annual average daily oil production of the Company's mineral fee properties in 1994 and 1993 was 199 and 100 barrels, respectively.
Revenues from the sales of LaBarge other products are attributable to sales of carbon dioxide, helium and sulfur. The production level of helium was relatively stable in 1994 when compared to 1993; however, carbon dioxide sales volumes declined due to a lack of market. Sulfur sales revenues in both years were insignificant. Gas marketing revenues decreased in 1994 due to the decline in natural gas market prices.
Total revenues decreased in 1993 when compared to 1992, primarily due to the Company's decision in June 1992 to limit its marketing of natural gas for third parties. An increase of 37% in the average daily oil production of the Company was partially offset by a decline in the average sales price for the Company's oil production of $2.93 per barrel. Revenues from the sales of LaBarge other products in 1993 decreased from 1992 levels due to decreased sales prices for carbon dioxide.
Operating Profit
In 1994, the operating profit of this segment decreased $1.1 million when compared to 1993. The lower average gas sales price combined with lower natural gas production was the largest factor in this decline in operating profit. Partially offsetting this factor was a decrease in production costs per equivalent barrel of production from $5.18 in 1993 to $4.23 in 1994, which can be attributed to the effects of the producing fee mineral interests where the Company does not have to share in operating costs. The effect on operating profits in 1994 of minerals leasing activities also mitigated the effects of the reductions in natural gas prices and production.
General and administrative costs decreased $0.1 million in 1994 to $2.0 million. Depreciation, depletion and amortization was $9.3 million in 1994 compared to $8.5 million in 1993. This rise reflects increased production and an increase in the amortization rate of $0.28 per equivalent barrel of production.
The increase in operating profit in 1993 when compared to 1992 was $0.3 million. A combination of improved oil production and lower production costs per barrel offset by higher general and administrative costs and depreciation, depletion and amortization produced the increase.
In 1995, the Company expects to drill several wells on prospects which include its fee mineral acreage in Mississippi and Alabama. Although results from drilling exploratory wells on acreage in West Texas were not as successful as the Company had hoped in 1994, with one successful well and five dry holes, the Company believes significant potential still exists for the area and plans to drill several more exploratory wells.
Crude Oil Marketing
Year Ended December 31, 1994 1993 1992 (In thousands)
Revenues $402,855 $369,054 $417,046 Operating profit $2,085 $844 $544
Revenues increased 9% in 1994 despite a drop in crude oil sales prices. The Company sold 67,174 barrels per day of crude oil in 1994, an increase of 10,093 barrels per day from 1993. The acquisition of the pipeline injection points of Essex Oil Company provided the Company with additional marketing locations beginning in March 1994, allowing the Company to be more competitive in these areas, which contributed significantly to this increase in barrels. Operating profits in 1994 improved significantly over 1993 levels. The increase in barrels sold combined with improved margins, due partly to the limited use of hedging techniques, were factors resulting in the improved operating profits.
Revenues declined in 1993 from the 1992 level due to lower oil prices. Operating profits in 1993, however, were improved when compared to the prior year. Operating profits in 1992 had been negatively affected by the losses incurred in the latter part of that year as a result of unintentionally high inventory levels when prices were declining at a time when the Company did not hedge inventories.
Technical Fuels and Chemical Processing
Year Ended December 31, 1994 1993 1992 (In thousands)
Revenues $29,580 $25,300 $21,260 Operating profit (loss) $579 $85 $(1,696)
The technical fuels and chemical processing segment not only had a 17% improvement in revenues in 1994, but also enjoyed a significant improvement in operating results from the breakeven result in 1993.
Revenues increased in 1994 from both increased sales of research and reference fuels and higher revenues from chemical toll processing activities. A combination of new environmental mandates and development in 1992 of new test procedures by the American Society of Testing and Materials (ASTM) produced opportunities in 1993 and 1994 for development of new research and reference fuels. Volumes sold of these fuels increased from 179,866 barrels in 1992 to 215,628 and 257,604 in 1993 and 1994, respectively.
Chemical processing revenues improved in 1994 as a result of the availability of synthesis reaction capabilities beginning in February 1994 after completion of the related construction. Revenues from chemical processing suffered in 1993 and 1992 from a cyclical downturn in the chemical industry.
The technical fuels and chemical processing segment has experienced significant increases each year since 1992 in its operating profits. The operating loss in 1992 was affected by costs associated with the closure of the San Antonio facility, the decline in technical fuels sales while tests were developed by ASTM and the chemical industry downturn. Improvements in each of these areas led to the higher operating profits in 1993 and 1994.
Transportation
Year Ended December 31, 1994 1993 1992 (In thousands)
Revenues $12,418 $9,247 $7,061 Operating profit (loss) $ 1,289 $ 585 $ (14)
Revenues increased approximately 34% in 1994 due to a $1.6 million increase in revenues from third party hauls and a $1.1 million increase in revenues from transporting crude oil for the Company's crude oil marketing segment. The increase in third party hauls can be attributed largely to a contract with Lyondell Petrochemical Company to service substantially all of their truck transportation needs. This contract, which began in the third quarter of 1994, helped the transportation segment increase its exposure to other potential customers. In 1994, approximately 20% of this segment's total revenues resulted from transporting for third parties.
The improvement in 1993 over the 1992 revenue level resulted primarily from hauling crude oil. A significant increase in activity in Alabama increased the crude oil volumes hauled in that area.
Certain costs of the transportation segment are fixed in nature; therefore, all costs did not increase as the volume of hauls increased. The improvement in revenues in 1993 and 1994 without an equal increase in costs resulted in the improvement in operating profit in 1993 and 1994.
Net Interest Expense
In 1994, market interest rates as reflected by the prime rate rose 2.5 percentage points from 6% to 8.5%. As substantially all of the Company's debt is subject to market rates, this rate increase contributed to higher interest in 1994 for the Company when compared to 1993. In addition, the Company had a higher level of average debt outstanding in 1994.
In April 1993, the Company raised $32.9 million in a public offering of convertible preferred stock. The proceeds from this offering allowed the Company to reduce its average debt outstanding in 1993 as compared to 1992, resulting in a decrease in interest expense in 1993 of $0.4 million.
Provision for Income Taxes
The effects of statutory depletion deductions in excess of cost basis resulted in the variations in 1994 and 1993 in the Company's tax rate from the statutory federal rate. In 1992, the Company had a tax benefit for federal tax purposes due to these same deductions.
Under the methodology of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes", the Revenue Reconciliation Act of 1993 (the Act) did not have a material impact on the tax provision of the Company in 1993, and the Act is not expected to have a material impact on the tax provision in future years. In addition, the Act had no effect on the Company's recorded deferred tax liability.
LIQUIDITY AND CAPITAL RESOURCES
Effective December 31, 1992, the Company amended and restated its long-term revolving credit/term loan agreement (Credit Facility). The borrowing base under the Credit Facility at December 31, 1994 was $41,000,000, and will decline by $820,000 monthly until such time as it is redetermined. The borrowing base is reviewed semi-annually by the bank with mandatory payments if the borrowing base, as determined solely by
the bank 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 1995, the decrease would not result in a mandatory repayment under the terms of the Credit Facility, and, therefore, none of the debt is reflected as a current obligation. The Credit Facility provides for a revolving period until June 1, 1996, with interest to be paid monthly at the rate selected by the Company of either (1) a Floating Base Rate (as defined in the Credit Facility) that is generally the prevailing prime rate or (2) a rate based on LIBOR. A LIBOR-based rate of 8.375% was applicable to $18 million of the outstanding balance under the Credit Facility at December 31, 1994. The remainder of the outstanding balance was subject to the Floating Base Rate of 8.5%. 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 at a rate equal to the prime rate. The 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 Credit Facility is collateralized by mortgages on substantially all of the Company's producing oil and gas properties, the stock of HPC and the guarantee of the Company. There is no compensating balance requirement and the Credit Facility carries a commitment fee of 3/8% on the available portion of the commitment. The Credit Facility limits the ability of the Company, without the bank's 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 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 financial 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 Credit Facility, of a floating amount that was $65.1 million at December 31, 1994, and to prohibit certain defined types of additional indebtedness and the granting of certain liens on the Company's assets without bank approval. Based on the terms of the Credit Facility, at December 31, 1994, $6.4 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.
Effective December 23, 1994, the Company entered into a letter of credit facility agreement (LC Facility). The LC Facility provides for the issuance of letters of credit in the aggregate not to exceed the lesser of the commitment of $7.5 million or the Borrowing Base, as defined in the LC Facility. At December 31, 1994, the Borrowing Base was $7.5 million. The LC Facility carries a commitment fee of 1/4% on the available portion of the commitment. Covenants under the LC Facility are the same as those described above for the Credit Facility. Collateral for the LC Facility consists of the inventories and accounts receivable of HCO, the stock of HCO and the guarantee of the Company.
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 timely.
At December 31, 1994, the Company had working capital of $1.9 million. In 1994, it generated cash flow from operating activities of $17.9 million. The transportation, crude oil marketing and technical fuels and chemical processing segments are expected by the Company to continue to positively impact 1995 operating cash flow, offset to some extent by the impact of higher market interest rates.
The Company currently anticipates spending approximately $0.7 million during fiscal 1995 and approximately $0.7 million during fiscal 1996 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 1996. 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 9 of Notes to Consolidated Financial Statements.
The Company believes that its cash flow from operations and amounts available under the Credit Facility will be sufficient to satisfy its current liquidity requirements. At December 31, 1994, the Company had $12.7 million available to it under the 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 Credit Facility. While the Company does not expect this to happen in 1995, such payments would adversely affect the Company's ability to carry out its planned 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 eighteen 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.
On January 24, 1995, Norcen Explorer, Inc. (Norcen) accepted, subject to the execution of a definitive purchase and sale agreement, the Company's offer to purchase certain oil and gas properties and undeveloped leaseholds owned by Norcen. All of the properties are located in Mississippi. Closing is scheduled to take place in March 1995. The net purchase price is estimated to be $5.8 million.
On February 22, 1995, the Company signed a purchase and sale agreement with Exxon Pipeline Company to acquire three crude oil pipeline systems located in Texas, Mississippi/Louisiana and Florida/Alabama. The purchase price is $63.5 million, and the Company expects to spend $4.9 million during 1995 on additional costs related to the acquisition. The transaction is expected to close on March 31, 1995, although the consummation of the acquisition is subject to due diligence procedures.
The Company has obtained commitments from a group of banks, one of which is the Company's current lender, to provide financing for this transaction. The new financing arrangement will replace both the existing Credit Facility and the LC Facility and will have terms similar to those of the existing facilities. See Note 10 of Notes to Consolidated Financial Statements.
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 22).
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 1995 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 76 Chairman and Chief Executive Officer Paul W. Funkhouser 42 President and Chief Operating Officer Allyn R. Skelton, II 43 Senior Vice President, Chief Financial Officer and Secretary
Mr. Paul N. Howell is Chief Executive Officer and Chairman of the Board of the Company. He has been Chief Executive Officer since 1955.
Mr. Paul W. Funkhouser was elected President and Chief Operating Officer in February 1990. Prior to his election he had served as Executive Vice President since July 1988 and Secretary since October 1988. Mr. Funkhouser served as Vice President - Petroleum from August 1984 until July 1988. He joined the Company in 1983. In April 1991, Mr. Funkhouser was elected a Director of the Company.
Mr. Allyn R. Skelton, II, was elected Senior Vice President of the Company in July 1993, Chief Financial Officer in May 1989, Vice President in July 1988 and Secretary in February 1990. He had served as the Controller of the Company since April 1985. Mr. Skelton also served as Secretary of the Company from October 1985 until October 1988. He joined the Company in 1983.
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 1995 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 1995 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 1995 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 1995 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 22).
(a)(3) and (c). The response to this portion of Item 14 is submitted as a separate section of this report (see page 40).
(b). Reports on Form 8-K. None were filed during the last quarter of the Registrant's fiscal year ended December 31, 1994.
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/ Paul W. Funkhouser ---------------------------- Paul W. Funkhouser President, Chief Operating Officer and Director
Date: February 27, 1995
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, 1995 -------------------- Paul N. Howell Chairman of the Board and Chief Executive Officer
Principal Financial and /s/ Allyn R. Skelton, II Accounting Officer February 27, 1995 -------------------- Allyn R. Skelton, II Senior Vice President, Chief Financial Officer and Secretary
/s/ Jack T. Trotter Director February 27, 1995 -------------------- Jack T. Trotter
/s/ Wallace S. Wilson Director February 27, 1995 -------------------- Wallace S. Wilson
/s/ Robert M. Ayres, Jr. Director February 27, 1995 -------------------- Robert M. Ayres, Jr.
HOWELL CORPORATION AND SUBSIDIARIES
FORM 10-K
ITEMS 8, 14(a) (1) and (2)
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTAL SCHEDULES
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 23 Consolidated Financial Statements: Consolidated Balance Sheets 24 Consolidated Statements of Earnings 25 Consolidated Statements of Shareholders' Equity 26 Consolidated Statements of Cash Flows 27 Notes to Consolidated Financial Statements 28
The following consolidated supplemental schedules of the registrant and its subsidiaries are included in Item 14(a)(1):
Page Supplemental Schedules: Property, Plant and Equipment 38 Accumulated Depreciation, Depletion and Amortization of Property, Plant and Equipment 39
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, 1994 and 1993, and the related consolidated statements of earnings, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 1994. 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, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles.
Our audits were conducted for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplemental schedules listed in the Index on page 22 are presented for the purpose of additional analysis and are not a required part of the basic financial statements. These schedules are the responsibility of the Company's management. Such schedules have been subjected to the auditing procedures applied in our audits of the basic financial statements and, in our opinion, are fairly stated in all material respects when considered in relation to the basic financial statements taken as a whole.
DELOITTE & TOUCHE LLP
Houston, Texas February 27, 1995
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Balance Sheets
December 31, 1994 1993
(In thousands) Assets Current assets: Cash and cash equivalents $3,340 $3,337 Trade accounts receivable, less allowance for doubtful accounts of $214,000 in 1994 and $201,000 in 1993 48,432 30,352 Inventories 2,655 2,573 Other current assets 1,520 1,998 ------ ------ Total current assets 55,947 38,260 ------- ------- Property, plant and equipment: Oil and gas properties, utilizing the full-cost method of accounting 264,430 256,227 Fee mineral interests, unproven 18,200 18,260 Other 34,837 32,516 Less accumulated depreciation, depletion and amortization (192,694) (181,890) --------- --------- Net property, plant and equipment 124,773 125,113 --------- --------- Other assets 1,720 1,169 --------- --------- Total assets $182,440 $164,542 --------- ---------
Liabilities and Shareholders' Equity
Current liabilities: Current maturities of long-term debt $2,670 $2,055 Accounts payable 46,178 27,521 Accrued liabilities 5,152 4,496 --------- --------- Total current liabilities 54,000 34,072 --------- --------- Deferred income taxes 19,273 18,216 --------- --------- Other liabilities 150 150 --------- --------- Long-term debt and capital lease obligation 33,098 35,879 --------- --------- Commitments and contingencies
Shareholders' equity: Preferred stock, $1 par value, 690,000 shares issued and outstanding; liquidation value of $17,250,000 690 690 Common stock, $1 par value; 4,836,876 shares issued and outstanding 4,837 4,837 Additional paid-in capital 33,518 33,518 Retained earnings 36,874 37,180 --------- --------- Total shareholders' equity 75,919 76,225 --------- --------- Total liabilities and shareholders' equity $182,440 $164,542 ========= =========
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Statements of Earnings
Year Ended December 31, 1994 1993 1992 (In thousands, except per share amounts)
Revenues $448,952 $411,736 $461,316 -------- -------- -------- Costs and expenses: Products including operating expenses 431,783 396,556 449,942 Selling, general and administrative expenses 10,992 9,912 8,586 -------- -------- -------- 442,775 406,468 458,528 -------- -------- -------- Other income (expense): Interest expense (2,237) (1,915) (2,280) Interest income 131 308 119 Other, net 180 (70) (334) -------- -------- -------- (1,926) (1,677) (2,495) -------- -------- -------- Earnings from operations before income taxes 4,251 3,591 293 Provision (credit) for income taxes 1,368 1,064 (138) -------- -------- -------- Net earnings $2,883 $2,527 $431 ======== ======== ========
Weighted average shares outstanding 4,837 4,823 4,811 ======== ======== ========
Net earnings per common share $0.10 $0.18 $0.09 ======== ======== ========
See accompanying Notes to Consolidated Financial Statements.
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES Consolidated Statements of Cash Flows
Year Ended December 31, 1994 1993 1992 (In thousands) OPERATING ACTIVITIES: Earnings from operations $ 2,883 $ 2,527 $ 431 Adjustments to reconcile net earnings to cash provided by operations: Depreciation, depletion and amortization 12,323 11,070 9,337 Deferred income taxes 1,057 1,032 (192) (Gain) loss on sale(s) of asset(s) (25) (11) 141 (Increase) decrease in accounts receivable (18,080) 21,519 (10,367) Increase in inventories (82) (86) (268) Decrease (increase) in other current assets 478 (580) 1,073 Increase (decrease) in accounts payable 18,657 (20,650) 5,487 Increase (decrease) in accrued and other liabilities 656 (1,147) 497 ------- ------- ------ Cash provided by operating activities 17,867 13,674 6,139 ------- ------- ------
INVESTING ACTIVITIES: Proceeds from the disposition of assets 1,450 1,491 1,822 Additions to property, plant and equipment (13,408) (39,111) (12,307) Other, net (551) 28 368 ------- ------- -------- Cash utilized in investing activities (12,509) (37,592) (10,117) ------- ------- --------
FINANCING ACTIVITIES: Long-term debt: (Repayments) borrowings under revolving credit agreement (300) (4,550) 1,835 Payments to Department of Energy (1,047) (981) (29) Other borrowings - - 1,672 Other repayments (819) (479) (193) Cash dividends: Common shareholders (774) (772) (770) Preferred shareholders (2,415) (1,657) - Issuance of preferred stock - 32,860 - Exercise of stock options - 63 104 Sale of treasury shares - 115 20 ------- ------- ------ Cash (utilized in) provided by financing activities (5,355) 24,599 2,639 ------- ------- ------
NET INCREASE (DECREASE) IN CASH BALANCE 3 681 (1,339)
CASH, BEGINNING OF YEAR 3,337 2,656 3,995 ------ ------ ------ CASH, END OF YEAR $3,340 $3,337 $2,656 ====== ====== ======
See accompanying Notes to Consolidated Financial Statements.
HOWELL CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
Years Ended December 31, 1994, 1993 and 1992
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). All significant intercompany accounts and transactions have been eliminated.
Inventories
Inventories of crude oil and refined products are stated at the lower of market or monthly weighted average cost. Crude oil exchange transactions are included as additions to or reductions of inventories at the time title passes. The Company has a limited program of hedging its crude oil inventories and fixed purchase price commitments. Crude oil future contracts are being used as the hedging tool. Changes in the market value of the futures transactions are deferred until the gain or loss is recognized on the hedged transactions.
Other inventories are stated at the lower of average cost or market.
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 on 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 under 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 by 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 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
In 1991, the Company adopted the provisions of Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" (Statement 109), which governs the accounting recognition of income taxes in its financial statements. Statement 109 defines 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
Earnings per common share has been computed by dividing net earnings, after reduction for preferred stock dividends, by the weighted average number of common shares outstanding. Shares issuable in connection with stock options are not included in the per share computations since their dilutive effect is less than 3%. Earnings per share assuming full dilution does not result in a difference from earnings per share assuming no dilution. The common shares issuable upon conversion of the convertible preferred stock are anti-dilutive, and the common shares issuable in connection with stock options result in a dilutive effect of less than 3%.
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 $2,179,000, $1,816,000 and $2,411,000 in 1994, 1993 and 1992, respectively. In 1994 and 1993 cash payments for income taxes totaled $126,000 and $171,000, respectively. In 1992, cash refunds for income taxes less cash payments totaled $369,000.
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 as reflected in its balance sheet approximates fair value because of the short-term maturity of those items.
Information on the fair value of the Company's long-term debt and capital lease obligation can be found in Note 5.
Environmental Liabilities
The Company provides for the estimated costs of environmental liabilities based on engineering estimates of the costs that will be necessary for remediation. Information regarding environmental liabilities can be found in Note 9. Ongoing environmental compliance costs, including maintenance and monitoring costs, are charged to expense as incurred.
Production Hedge
As stated above, crude oil future contracts are being used as a hedging tool in a limited program of hedging crude oil inventories and fixed purchase price commitments. 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 eighteen 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. The premium for the options will be amortized over the period.
Note 2. Inventories
The major classes of inventory at December 31, 1994 and 1993 were as follows:
1994 1993 (In thousands) Refined products $1,333 $1,265 Crude oil 578 924 Other materials and supplies 744 384 ------ ------ $2,655 $2,573 ====== ======
Note 3. Note Receivable
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 is 10%. Due to the uncertainty about the ultimate collection of the note receivable, the Company has not recognized gain on the sale or interest income on the note until its collectibility appears to be more certain. At December 31, 1994, the company that purchased the facility was delinquent in its payments to the Company under the terms of the note. The Company believes the salvage value of the refinery would exceed the remaining note receivable, net of deferred gain, of $0.1 million at December 31, 1994, should the Company decide to foreclose on the mortgage.
At December 31, 1994, the note receivable is reflected in the balance sheet as follows (in thousands):
Other current assets (current portion of note receivable of $558 less deferred gross profit of $458) $100
Other assets (long-term portion of note receivable of $590 less deferred gross profit of $590) $ -
The receipt of the note receivable is a non-cash transaction and is not reflected in the statement of cash flows for the year ended December 31, 1992.
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, 1994 1993 1992 (In thousands) Current: Federal $ - $ - $ - State 161 32 130 Deferred 1,207 1,032 (268) ------ ------ ------ $1,368 $1,064 $ (138) ====== ====== ======
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, 1994 1993 (In thousands) Accrual of costs not deductible for tax $ 841 $ 742 Difference in book and tax basis of note receivable 391 361 Statutory depletion carryforwards 1,043 752 Net operating loss carryforwards 3,421 3,993 ------ ------ Total deferred tax assets 5,696 5,848 ------ ------ Differences between book and tax bases of property, plant and equipment (24,858) (23,086) Other (111) (978) -------- -------- Total deferred tax liabilities (24,969) (24,064) -------- -------- Net deferred income taxes $(19,273) $(18,216) ======== ========
The following table accounts for the difference between the actual tax provision (credit) and the amounts obtained by applying the applicable statutory U.S. Federal income tax rate of 34% to the earnings before income taxes:
Year Ended December 31, 1994 1993 1992 (In thousands)
Provision for income taxes at the statutory rate $1,445 $1,221 $100 Statutory depletion in excess of cost basis (237) (310) (366) Other 160 153 128 ------ ------ ------ $1,368 $1,064 $ (138) ====== ====== ======
At December 31, 1994, the Company, for tax reporting purposes, has a net operating loss carryforward of $9,661,000 that has been recognized as a reduction of the deferred tax liability. The carryforward, if not previously utilized, expires as follows: $4,230,000 in 2006, $4,128,000 in 2007 and $1,303,000 in 2008. In addition, the Company, for tax reporting purposes, has a statutory depletion carryforward of $2,896,000 that has been recognized as a reduction of the deferred tax liability. This carryforward has no expiration.
Note 5. Debt and Available Credit Facilities
Long-term debt and the capital lease obligation of the Company as of December 31, 1994 and 1993 were as follows:
1994 1993 (In thousands)
Note payable under a $41.0 million revolving credit/term loan agreement $24,200 $24,500 Note payable to Department of Energy (DOE) 9,387 10,434 Note payable to Paul N. Howell 2,000 2,000 Note payable to G.E. Capital - 774 Capital lease obligation for transportation equipment 181 226 ----- ----- 35,768 37,934 Less: Current maturities 2,670 2,055 ------ ------- $33,098 $35,879 ======= =======
Maturities of long-term debt for the five years subsequent to December 31, 1994 are as follows (in thousands):
Total Bank DOE Other
1995 $2,622 $ - $2,122 $ 500 1996 6,791 3,025 2,266 1,500 1997 8,468 6,050 2,418 - 1998 8,631 6,050 2,581 - 1999 6,050 6,050 - - Thereafter 3,025 3,025 - - ------- ------- ------ ------ $35,587 $24,200 $9,387 $2,000 ======= ======= ====== ======
The following is a schedule by years of future minimum lease payments for the capital lease obligation, together with the present value of the net minimum lease payments as of December 31, 1994 (in thousands):
1995 $60 1996 60 1997 83 ---- Total minimum lease payments $203 Less: Amount representing interest 22 ---- Present value of net minimum lease payments $181 ====
Revolving credit/term loan agreement
Effective December 31, 1992, the Company amended and restated its long-term revolving credit/term loan agreement (Credit Facility). The borrowing base under the Credit Facility at December 31, 1994 was $41.0 million, and will decline by $0.8 million monthly until such time as it is redetermined. The borrowing base is reviewed semi-annually by the bank with mandatory payments if the borrowing base, as determined solely by the bank 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 1995, the decrease would not result in a mandatory repayment under the terms of the Credit Facility, and, therefore, none of the debt is reflected as a current obligation. The Credit Facility provides for a revolving period until June 1, 1996,
with interest to be paid monthly at the rate selected by the Company of either (1) a Floating Base Rate (as defined in the Credit Facility) that is generally the prevailing prime rate or (2) a rate based on LIBOR. A LIBOR-based rate of 8.375% was applicable to $18 million of the outstanding balance under the Credit Facility at December 31, 1994. The remainder of the outstanding balance was subject to the Floating Base Rate of 8.5%. 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 at a rate equal to the prime rate. The 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 available commitment at December 31, 1994 was $12.7 million.
The Credit Facility is collateralized by mortgages on substantially all of the Company's producing oil and gas properties, the stock of Howell Petroleum Corporation and the guarantee of the Company. There is not a compensating balance requirement, and the Credit Facility carries a commitment fee of 3/8% on the available portion of the commitment. 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 Credit Facility, of a floating amount that was $65.1 million at December 31, 1994, and to prohibit certain defined types of additional indebtedness and the granting of certain liens on the Company's assets without bank approval. Based on the terms of the Credit Facility, at December 31, 1994, $6.4 million of the Company's retained earnings was unrestricted as to the payment of dividends. This amount varies based on changes in the shareholders' equity of the Company.
Letter of credit agreement
Effective December 23, 1994, the Company entered into a letter of credit facility agreement (LC Facility). The LC Facility provides for the issuance of letters of credit in the aggregate not to exceed the lesser of the commitment of $7.5 million or the Borrowing Base, as defined in the LC Facility. At December 31, 1994, the Borrowing Base was $7.5 million. The LC Facility carries a commitment fee of 1/4% on the available portion of the commitment. Covenants under the LC Facility are the same as those described above for the Credit Facility. Collateral for the LC Facility consists of the inventories and accounts receivable of Howell Crude Oil Company, the stock of Howell Crude Oil Company and the guarantee of the Company.
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 1970's, the Company agreed, in 1989, to pay $19.4 million to the DOE. The remaining balance owed at December 31, 1994 was $9.4 million.
In September 1992, the Company renegotiated the payment terms and interest rate for its obligation to the DOE. The interest rate is now based upon a trailing average prime rate. At December 31, 1994, that rate was 7.75%.
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 1994, based on the formula contained in the final order, did not result in an acceleration of principal payments. 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
During 1982, the Company borrowed $4.5 million from Paul N. Howell, Chairman and Chief Executive Officer of the Company. In 1987, 1988 and 1991 the Company made partial repayments of the term note totaling $2.5 million. In December 1994, the term note was renewed and is now due February 28, 1996, with
up to $0.5 million of the loan amount payable upon demand. The loan is unsecured. Interest accrues at the prevailing prime rate and is payable quarterly. At December 31, 1994, the outstanding principal balance due Mr. Howell was $2.0 million.
In June 1992, the Company borrowed $1.4 million from General Electric Capital Corporation and purchased operating equipment for its offshore oil and gas production facility. The note was repaid in 1994.
In July 1992, the Company entered into a capital lease for transportation equipment. The obligation is payable in monthly installments with interest at 7.4%. The obligation is secured by the equipment. Included in property at December 31, 1994, is the cost of the transportation equipment under capital lease of $0.3 million and accumulated depreciation of $0.1 million on the equipment.
Fair value of long-term debt
The fair value of the Company's long-term debt and its capital lease obligation at December 31, 1994 was estimated to be the same as its carrying value in the balance sheet, as all debt obligations were negotiated or renegotiated during 1992 and/or bear interest at floating market rates.
Note 6. Shareholders' Equity
Preferred stock
At the Company's Annual Meeting of Shareholders on April 25, 1994, the shareholders approved a proposal to increase the authorized number of shares of preferred stock to 3,000,000. At December 31, 1994 and 1993, the Company had 3,000,000 and 1,000,000 shares of preferred stock authorized, respectively.
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, generally, 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, 1994 and 1993, the Company had 10,000,000 shares of common stock authorized.
Under the Company's 1975 Nonqualified Stock Option Plan, options to purchase 180,000 shares could be granted. At December 31, 1994 and 1993, options to acquire 4,020 shares were outstanding and exercisable, at an average price of $14.88 per share. No options were exercised pursuant to the 1975 Plan during 1994 or 1993 and no additional options may be granted under this plan.
Under the Company's 1988 Stock Option Plan, options to purchase 750,000 shares may be granted. At December 31, 1993, options to acquire 304,253 shares were outstanding, of which 169,180 were exercisable at an average price of $9.99 per share. The average exercise price of all options outstanding at December 31, 1993 was $10.39 per share. At December 31, 1994, options to acquire 443,173 shares were outstanding, of which 209,758 were exercisable at an average price of $10.12 per share. The average exercise price of all options outstanding at December 31, 1994 was $10.56 per share. Options to acquire 7,500 and 11,880 shares were exercised in 1993 and 1992, respectively, at average exercise prices of $8.32 and $8.68 per share, respectively.
Note 7. Segment Information
Financial information about the Company's continuing operations for each of the years ended December 31, 1994, 1993 and 1992 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 segment were $14,258,000, $14,146,000 and $12,063,000 in 1994, 1993 and 1992, respectively. Intersegment sales by the transportation segment to the crude oil marketing segment in 1994, 1993 and 1992 were $7,743,000, $6,642,000 and $5,006,000, respectively. Intersegment sales by the transportation segment to the technical fuels and chemical processing segment in 1994, 1993 and 1992 were $2,066,000, $1,683,000 and $1,140,000, respectively. Intersegment sales by the oil and gas production segment to the technical fuels and chemical processing segment in 1994, 1993 and 1992 were $768,000, $675,000 and $626,000, respectively. These amounts have been eliminated in consolidation.
Marathon Oil Company, a customer of the crude oil marketing segment, accounted for approximately 18% of consolidated revenues in 1994 and approximately 11% of consolidated revenues in 1993 and 1992.
Note 8. 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 in this lawsuit alleging breach of contract. The trial judge reduced the jury verdict 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. Donna has filed an appeal to increase the recovery by $1.25 million. The Company does not believe that the ultimate resolution of this matter will have a material adverse effect on the financial condition or results of operations of the Company.
There are various other lawsuits and claims against the Company, none of which, in the opinion of management, will have a material adverse effect on the Company.
Note 9. Commitments and Contingencies
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. During 1994, the Company incurred costs of $213,000 related to remediation and disposal of the hazardous wastes. Additional testing and monitoring of the groundwater and formal approval of the remediation work is still required. At this time, the Company has not determined whether the Company or the new owner of the facility is the responsible party for the additional testing and monitoring requirements. 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 material 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 $2,078,000 in 1994, $1,729,000 in 1993 and $1,560,000 in 1992. At December 31, 1994, long-term commitments for lease of facilities and equipment totaled approximately $8,818,000, consisting of $2,146,000, $1,588,000, $753,000, $538,000 and $513,000 for the years 1995 through 1999, respectively, and $3,280,000 thereafter.
Note 10. Subsequent Events
On January 24, 1995, Norcen Explorer, Inc. (Norcen) accepted, subject to the execution of a definitive purchase and sale agreement, the Company's offer to purchase certain oil and gas properties and undeveloped leaseholds owned by Norcen. All of the properties are located in Mississippi. Closing is scheduled to take place in March 1995. The net purchase price is estimated to be $5.8 million.
On February 22, 1995, the Company signed a purchase and sale agreement with Exxon Pipeline Company to acquire three crude oil pipeline systems located in Texas, Mississippi/Louisiana and Florida/Alabama. The purchase price is $63.5 million, and the Company expects to spend $4.9 million during 1995 on additional costs related to the acquisition. The transaction is expected to close on March 31, 1995, although the consummation of the acquisition is subject to due diligence procedures.
The Company has obtained commitments from a group of banks, one of which is the Company's current lender, to provide financing for this transaction. The commitments are subject to the typical requirements for due diligence and successful negotiation of loan documents. The new financing arrangement will replace both the existing Credit Facility and the LC Facility and will have terms similar to those of the existing facilities while extending the revolving period until June 1, 1997, and increasing the amounts available under the LC Facility to $15 million. Additionally, the new facility will provide for a term loan in the amount of $57.5 million payable in quarterly installments of $1.4 million. Interest rates are the same as the existing facility except that the new facility provides for a reduction in the add-on to LIBOR when the Company meets certain debt to capitalization thresholds. Beginning with quarters ending in 1996, the Company will be required to make prepayments on the term note from excess cash flow from the pipeline activities as defined in the agreements.
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 ** Form of Indemnity Agreement by and between the Company and each of its directors and executive officers. 10.6 ** Credit Agreement by and between Howell Petroleum Corporation and Bank One, Texas, N.A. (Bank One) dated as of December 31, 1992. 10.7 ** Promissory Note of Howell Petroleum Corporation payable to the order of Bank One dated December 31, 1992. 10.8 ** Guaranty by Howell Corporation in favor of Bank One dated as of December 31, 1992. 10.9 ** Amended and Restated Mortgage and Deed of Trust, Indenture and Security Agreement by and between Howell Petroleum Corporation and Bank One dated as of December 31, 1992. 10.10 ** Security Agreement (Stock Pledge) by the Company in favor of Bank One dated as of December 31, 1992. 10.11 ** Subordination Agreement by and among the Company, Bank One and Howell Petroleum Corporation dated as of December 31, 1992. 10.12 * Promissory Note dated December 19, 1994 by and between the Company and Paul N. Howell. 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 ** United States Department of the Interior Minerals Management Service Oil and Gas Lease under the Outer Continental Shelf Lands Act by and between the United States of America and Oil Acquisitions, Inc., effective as of October 1, 1990. 10.26 ** 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 Oil Acquisitions, Inc., effective as of December 1, 1990. 10.27 ** 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 Howell Petroleum Corporation effective as of May 1, 1991. 10.28 ** 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 Howell Petroleum Corporation effective as of July 1, 1991. 10.29 ** 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 Howell Petroleum Corporation effective as of May 1, 1991. 10.30 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). 10.31 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). 10.32 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). 10.33 First Amendment to Credit Agreement Between Howell Petroleum Corporation and Bank One, Texas, N.A. effective as of November 16, 1993 (filed as an Exhibit to the Company's Report on Form 10-Q for the quarterly period ended June 30, 1994). 10.34 First Amendment to Guaranty Between Howell Corporation and Bank One, Texas, N.A. effective as of November 16, 1993 (filed as an Exhibit to the Company's Report on Form 10-Q for the quarterly period ended June 30, 1994). 10.35 Ratification of and Amendment to Amended and Restated Mortgage, Deed of Trust, Indenture, Security Agreement, Financing Statement and Assignment of Production dated as of November 16, 1993 (filed as an Exhibit to the Company's Report on Form 10-Q for the quarterly period ended June 30, 1994). 10.36 Mortgage, Deed of Trust, Indenture, Security Agreement, Financing Statement and Assignment of Production From Howell Petroleum Corporation to Bank One, Texas, N.A. dated as of November 16, 1993 (filed as an Exhibit to the Company's Report on Form 10-Q for the quarterly period ended June 30, 1994). 10.37 Second Amendment to Credit Agreement Between Howell Petroleum Corporation and Bank One, Texas, N.A. effective as of June 1, 1994 (filed as an Exhibit to the Company's Report on Form 10-Q for the quarterly period ended June 30, 1994).
Exhibit Number Description - -------- -----------
10.38 * Credit Agreement between Howell Crude Oil Company and Bank One dated as of December 23, 1994. 10.39 * Security Agreement between Howell Crude Oil Company and Bank One dated December 23, 1994. 10.40 * Guaranty by the Company in favor of Bank One dated as of February 1, 1995. 10.41 * Security Agreement (Stock Pledge) by the Company in favor of Bank One dated February 1, 1995. 11 * Computation of Earnings per Share. 21 * Subsidiaries of the Company. 23 * Consent of Deloitte & Touche LLP.